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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, 1997
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[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
For the Transition Period From ____________ to ____________
Commission File Number
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1-10290
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, 1998 was $2,565,653,110. There were 77,685,287 shares of DQE Common Stock
outstanding as of February 28, 1998.
[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.
Securities registered pursuant to Section 12(b) of the Act:
Name of each exchange
Registrant Title of each class on which registered
- ------------- ------------------- ----------------------
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, 1997
TABLE OF CONTENTS
PAGE
----
PART I
ITEM 1. BUSINESS
Corporate Structure 1
Property, Plant and Equipment (PP&E) 2
Employees 3
Electric Utility Operations 3
Fossil Fuel 4
Nuclear Fuel 4
Nuclear Decommissioning 5
Nuclear Insurance 5
Spent Nuclear Fuel Disposal 6
Uranium Enrichment Obligations 6
Environmental Matters 6
Other 7
Executive Officers of the Registrant 9
ITEM 2. PROPERTIES 10
ITEM 3. LEGAL PROCEEDINGS 11
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 15
RATE MATTERS 17
ITEM 7A. QUANTITATIVE AND QUALITATIVE
DISCLOSURES ABOUT MARKET RISK 20
ITEM 8. REPORT OF INDEPENDENT CERTIFIED
PUBLIC ACCOUNTANTS; CONSOLIDATED
FINANCIAL STATEMENTS AND
SUPPLEMENTARY DATA 21
ITEM 9. CHANGES IN AND DISAGREEMENTS
WITH ACCOUNTANTS ON ACCOUNTING
AND FINANCIAL DISCLOSURE 47
PART III
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS
OF THE REGISTRANT 47
ITEM 11. EXECUTIVE COMPENSATION 47
ITEM 12. SECURITY OWNERSHIP OF CERTAIN
BENEFICIAL OWNERS AND MANAGEMENT 47
ITEM 13. CERTAIN RELATIONSHIPS AND
RELATED TRANSACTIONS 47
PART IV
ITEM 14. EXHIBITS, FINANCIAL STATEMENT
SCHEDULES AND REPORTS ON FORM 8-K 47
SCHEDULE II 61
SIGNATURES 62
GLOSSARY 63
Part I
Item 1. Business.
Corporate Structure
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Part I of this Annual Report, Form 10-K (Report) should be read in conjunction
with DQE's audited consolidated financial statements, which are set forth on
pages 22 through 46 in Part IV of this Report. Explanations of certain financial
and operating terms used in this Report are set forth in a GLOSSARY on page 63
of this Report.
DQE, Inc. (DQE) is an energy services holding company. Its subsidiaries are
Duquesne Light Company (Duquesne); Duquesne Enterprises, Inc. (DE); DQE Energy
Services, Inc. (DES); DQEnergy Partners, Inc. (DQEnergy); and Montauk, Inc.
(Montauk). DQE and its subsidiaries are collectively referred to as "the
Company."
Duquesne is an electric utility engaged in the generation, transmission,
distribution and sale of electric energy and is the largest of DQE's
subsidiaries. DE makes strategic investments beneficial to DQE's core energy
business. These investments are intended to enhance DQE's capabilities as an
energy provider, increase asset utilization, and act as a hedge against changing
business conditions. DES is a diversified energy services company offering a
wide range of energy solutions for industrial, utility and consumer markets
worldwide. DES initiatives include energy facility development and operation,
domestic and international independent power production, and the production and
supply of innovative fuels. DQEnergy was formed to align DQE with strategic
partners to capitalize on opportunities in the energy services industry. These
alliances are intended to enhance the utilization and value of DQE's strategic
investments and capabilities while establishing DQE as a total energy provider.
Montauk is a financial services company that makes long-term investments and
provides financing for the Company's other market-driven businesses and their
customers.
Proposed Merger
On August 7, 1997, the shareholders of the Company and Allegheny Energy,
Inc. (AYE), approved a proposed tax-free, stock-for-stock merger. Upon
consummation of the merger, DQE will be a wholly owned subsidiary of AYE.
Immediately following the merger, Duquesne, DE, DES, DQEnergy and Montauk will
remain wholly owned subsidiaries of DQE. The transaction is intended to be
accounted for as a pooling of interests. Under the pooling of interests method
of accounting for a business combination, the recorded assets, liabilities and
equity of each of the combining companies are carried forward to the combined
corporation at their recorded amounts. Accordingly, no goodwill, including the
related future earnings impact of goodwill amortization, results from a
transaction accounted for as a pooling of interests. In order to qualify for
pooling treatment, many requirements must be met by each of the combining
companies for a period of time before and after the combination occurs. Examples
of the requirements prior to the merger include limitations on: dividends paid
on common stock, stock repurchases, stock compensation plan activity and sales
of significant assets. Management has focused and will continue to focus on
meeting the pooling requirements as they relate to the Company prior to the
merger.
Under the terms of the transaction, the Company's shareholders will receive
1.12 shares of AYE common stock for each share of the Company's common stock and
AYE's dividend in effect at the time of the closing of the merger. The
transaction is expected to close in mid-1998, subject to approval of applicable
regulatory agencies, including the public utility commissions in Pennsylvania
and Maryland, the Securities and Exchange Commission (SEC), the Federal Energy
Regulatory Commission (FERC) and the Nuclear Regulatory Commission (NRC).
In September 1997, the City of Pittsburgh filed a federal antitrust suit
seeking to prevent the merger and asking for monetary damages. Although the
United States District Court for the District of Western Pennsylvania dismissed
the suit in January 1998, the City of Pittsburgh filed an appeal and asked for
expedited review. The Company anticipates a decision on whether the appeal has
been granted by late March 1998.
Unless otherwise indicated, all information presented in this Annual Report
relates to the Company only and does not take into account the proposed merger
between the Company and AYE.
The Company's Electric Service Territory
The Company's electric utility operations provide service to customers in
Allegheny County, including the City of Pittsburgh; Beaver County; and
Westmoreland County. (See Item 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS "Rate Matters" on page 17.) This
territory represents approximately 800 square miles in southwestern
Pennsylvania, located within a 500-mile radius of one-half of the population of
the United States and Canada. 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.
1
Regulation
The Company is subject to the accounting and reporting requirements of the
SEC. In addition, the Company's electric utility operations are subject to
regulation by the Pennsylvania Public Utility Commission (PUC), including
regulation under the Pennsylvania Electricity Generation Customer Choice and
Competition Act (Customer Choice Act), and the FERC under the Federal Power Act
with respect to rates for interstate sales, transmission of electric power,
accounting and other matters. (See Item 7. MANAGEMENT'S DISCUSSION AND ANALYSIS
OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS "Rate Matters" on page 17.)
The Company's electric utility operations are also subject to regulation by
the 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 consolidated financial statements report regulatory assets and
liabilities in accordance with Statement of Financial Accounting Standards
(SFAS) No. 71, Accounting for the Effects of Certain Types of Regulation (SFAS
No. 71), and reflect the effects of the current ratemaking process. In
accordance with SFAS No. 71, the Company's consolidated financial statements
reflect regulatory assets and liabilities consistent with cost-based, pre-
competition 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.
A company's electric utility operations, or a portion of such operations,
could cease to meet the SFAS No. 71 criteria for various reasons, including a
change in the FERC regulations or the competition-related changes in the PUC
regulations. (See Item 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS "Rate Matters" on page 17.) The Emerging
Issues Task Force of the Financial Accounting Standards Board (EITF) has
determined that once a transition plan has been approved, application of SFAS
No. 71 to the generation portion of a utility must be discontinued and replaced
by the application of SFAS No. 101, Regulated Enterprises - Accounting for the
Discontinuation of Application of FASB Statement No. 71 (SFAS No. 101). The
consensus reached by the EITF provides further guidance that the regulatory
assets and liabilities of the generation portion of a utility to which SFAS No.
101 is being applied should be 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. Under the Customer Choice Act, the Company believes
that its generation-related regulatory assets will be recovered through a
competitive transition charge (CTC) collected in connection with providing
transmission and distribution services, and the Company will continue to apply
SFAS No. 71. Fixed assets related to the generation portion of a utility will be
evaluated including the cash flows provided by the CTC, in accordance with SFAS
No. 121, Accounting for the Impairment of Long-Lived Assets and for Long-Lived
Assets to Be Disposed Of (SFAS No. 121). The Company believes that all of its
regulatory assets continue to satisfy the SFAS No. 71 criteria in light of the
transition to competitive generation under the Customer Choice Act and the
ability to recover these regulatory assets through a CTC. Once any portion of
the Company's electric utility operations is deemed to no longer meet the SFAS
No. 71 criteria, or is not recovered through a CTC, the Company will be required
to write off assets (to the extent their net book value exceeds fair value), the
recovery of which is uncertain, and any regulatory assets or liabilities for
those operations that no longer meet these requirements. Any such write-off of
assets could be materially adverse to the financial position, results of
operations and cash flows of the Company.
Property, Plant and Equipment (PP&E)
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Investment in PP&E and Accumulated Depreciation
The Company's total investment in property, plant and equipment and the
related accumulated depreciation balances for major classes of property at
December 31, 1997 and 1996, are as follows:
PP&E and Related Accumulated Depreciation at December 31
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(Amounts in Thousands of Dollars)
1997 1996
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Accumulated Net Accumulated Net
Investment Depreciation Investment Investment Depreciation Investment
------------------------------------ ------------------------------------
Electric Production $2,494,476 $1,175,516 $1,318,960 $2,467,786 $1,092,928 $1,374,858
Electric Transmission 298,614 119,895 178,719 299,895 114,406 185,489
Electric Distribution 1,206,546 390,103 816,443 1,176,738 374,180 802,558
Electric General 334,565 192,439 142,126 324,366 168,470 155,896
Property Held for Future Use (a) 3,980 66 3,914 190,821 82,737 108,084
Property Held Under Capital Leases 113,662 50,725 62,937 99,608 47,670 51,938
Other 173,285 34,050 139,235 228,256 89,554 138,702
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Total $4,625,128 $1,962,794 $2,662,334 $4,787,470 $1,969,945 $2,817,525
================================================================================================================
(a) See "Property Held for Future Use" discussion on page 3.
2
Joint Interests in Generating Units
The Company has various contracts with subsidiaries of FirstEnergy Corporation
(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, that 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. In October 1995, CEI commenced an
action against the Company in the Court of Common Pleas, Lake County, Ohio
seeking to enjoin the Company from taking any action to effect a partition on
the basis of a waiver of partition covenant contained in the deed to the land
underlying Eastlake. 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. Currently, the
parties are engaged in settlement discussions. The Company anticipates that a
trial will commence late in 1998.
Joint Interests in Power Stations
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Nuclear Power Stations Beaver Valley
-------------------- Perry
Unit 1 Unit 2 Unit 1
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Duquesne *47.50% *13.74%(a) 13.74%
FirstEnergy Corporation 52.50% 86.26% *86.26%
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Fossil Power Stations Bruce Mansfield
Sammis ---------------------------- Eastlake
Unit 7 Unit 1 Unit 2 Unit 3 Unit 5
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Duquesne 31.20% 29.30% 8.00% 13.74% 31.20%
FirstEnergy Corporation *68.80% *70.70% *92.00% *86.26% *68.80%
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*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. The lease is accounted for as an operating lease.
Property Held for Future Use
In 1986, the PUC approved the Company's request to remove Phillips Power
Station (Phillips) and a portion of Brunot Island (BI) from service. These
assets were classified as property held for future use. In 1997, through its
analysis of customer choice in the Restructuring Plan and Stand-Alone Plan, the
Company determined that Phillips and a portion of BI would not be cost-effective
in the production of electricity in the face of a competitive marketplace. Based
on this analysis, Phillips and a portion of BI have been reclassified on the
balance sheet from property held for future use to a regulatory asset. In each
of the filings, the Company is seeking recovery of its investment and associated
costs of Phillips and BI through a CTC. (See Item 7. MANAGEMENT'S DISCUSSION AND
ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS "Rate Matters"
discussion on page 17.)
Employees
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At December 31, 1997, the Company had 3,465 employees, including 1,114
employees at the Company-operated Beaver Valley Power Station (BVPS). The
Company is party to a labor contract expiring in September 2001 with the
International Brotherhood of Electrical Workers, which represents approximately
2,000 of the Company's employees. The contract provides, among other things,
employment security, income protection and 3 percent annual wage increases
through September 2000.
Electric Utility Operations
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The Company's fossil plants operated at an equivalent availability factor of
78 percent in 1997 and 76 percent in 1996. The Company's nuclear plants operated
at an equivalent availability factor of 67 percent in 1997 and 76 percent in
1996. BV Unit 1 went off-line on September 27, 1997, for a scheduled refueling
outage, and returned to service on January 21, 1998. Perry Unit 1 completed a
refueling outage on October 23, 1997. This outage lasted 40 days, a record for
Perry Unit 1. The next refueling outage for BV Unit 1 is currently scheduled to
begin in April 1999. The next refueling outages for BV Unit 2 and Perry Unit 1
are currently scheduled to begin in September 1998 and March 1999, respectively.
The timing and duration of scheduled maintenance and
3
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 1997 and all-time customer system peak demand of 2,671 MW
occurred on July 15, 1997.
BV Unit 1 went off-line January 30, 1998, due to an issue identified in a
technical review recently completed by the Company. BV Unit 2 went off-line
December 16, 1997, to repair the emergency air supply system to the control room
and has remained off-line due to other issues identified by a similar technical
review of BV Unit 2. These technical reviews are in response to a 1997
commitment made by the Company to the NRC. The Company is one of many utilities
faced with these technical issues, some of which date back to the original
design of Beaver Valley Power Station (BVPS). Both BVPS units remain off-line
for a revalidation of technical specification surveillance testing requirements
of various plant systems. Based on the current status of the revalidation
process, the Company currently anticipates that both BVPS units will remain off-
line through March 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 continue to operate at 100
percent reactor power, although approximately 17 percent of BV Unit 1 and 2
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
scheduled refueling outage is the fall of 2000.
Fossil Fuel
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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 1997, approximately 2.3 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, 1997, the Company's net investment in the mine was
$10.7 million. The Company estimates that, at December 31, 1997, its
economically recoverable coal reserves at Warwick Mine were in excess of 1.5
million tons. An unaffiliated contract operator at Warwick Mine encountered
adverse geologic conditions late in 1996 that resulted in a contract default.
Commencing in 1997, a new unaffiliated operator began producing approximately
360,000 tons of coal per year for exclusive use at Elrama. 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 $27.5
million toward these costs.
During 1997, 34 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, 1997 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, 1997, the Company's wholly owned
and jointly owned generating units had on hand an average coal supply of 41
days.
Nuclear Fuel
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The cycle of production and utilization of nuclear fue 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's (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 2005 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 2006 through 2014 under the USEC contract and may
terminate these future years if it can arrange more cost-effective alternative
enrichment services. Fuel fabrication contracts are in
4
place to supply reload requirements through 2002 and 2003 respectively, for BV
Unit 1 and BV Unit 2 and 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 Item 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS "Nuclear Fuel Leasing" discussion on page
16.)
Nuclear Decommissioning
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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. 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. The
Company is seeking recovery of any potential shortfall in decommissioning
funding as part of either its Restructuring Plan or its Stand-Alone Plan. (See
Item 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATIONS "Rate Matters" on page 17.)
With respect to the transition to a competitive generation market, the
Customer Choice Act requires that utilities include a plan to mitigate any
shortfall in decommissioning trust fund payments for the life of the facility
with any future decommissioning filings. Consistent with this requirement, in
1997 the Company increased its annual contributions to the decommissioning
trusts by $5 million to approximately $9 million. The Company has received
approval from the Internal Revenue Service (IRS) for qualification of 100
percent of additional nuclear decommissioning trust funding for BV Unit 2 and
Perry Unit 1, and 79 percent for BV Unit 1.
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, 1997 totaled approximately $47.1 million.
Nuclear Insurance
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The Price-Anderson amendments to the Atomic Energy Act of 1954 limit public
liability from a single incident at a nuclear plant to $8.9 billion. The maximum
available private primary insurance of $200 million has been purchased by the
Company. Additional protection of $8.7 billion would be provided by an
assessment of up to $79.3 million per incident on each nuclear unit in the
United States. The Company's maximum total possible assessment, $59.4 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 $5.8 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 21 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 $3.4 million.
5
Spent Nuclear Fuel Disposal
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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 2017, 2011 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, was not entirely in favor of the DOE or the utilities. The court
permitted the DOE to pursue alternative dispute resolution, but prohibited it
from using its lack of a spent fuel repository as a defense. The DOE has
requested a rehearing on the matter, which has yet to be scheduled.
Uranium Enrichment Obligations
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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 (NEPA)
and are to be paid by such utilities over a 15-year period. At December 31,
1997, the Company's liability for contributions was approximately $7.2 million
(subject to an inflation adjustment). (See Item 7. MANAGEMENT'S DISCUSSION AND
ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS "Rate Matters" on page
17.)
Environmental Matters
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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.
The Comprehensive Environmental Response, Compensation and Liability Act of
1980 and The Superfund Amendments and Reauthorization Act of 1986 (Superfund)
established a variety of informational and environmental action programs. The
Environmental Protection Agency (EPA) previously informed the Company of its
potential involvement in three hazardous waste sites. The Company reached
agreements to make de minimis financial settlements related to these sites in
order to resolve any associated liability. Through its acquisition of GSF Energy
(GSF), the Company indirectly became involved in three additional 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 acquisition 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.
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 during the last half of 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.
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\\) and
NO\\X\\ by the year 2000. The Company currently has 662 MW of nuclear capacity
and 887 MW of coal capacity equipped with SO\\2\\ emission-reducing equipment
(excluding 300 MW of regulatory assets at Phillips). Through the year 2000, the
Company is considering a combination of compliance methods that include fuel
switching; increased use of, and improvements in, SO\\2\\ emission-reducing
equipment; low NO\\X\\ burner technology; and the purchase of emission
allowances for those remaining stations not in compliance.
6
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 EPA's final Group II
rulemaking. The Company is also currently evaluating additional low-cost,
developmental NO\\X\\ reduction technologies at Cheswick. In 1997 the Company
tested combustion-related NO\\X\\ controls at Cheswick, with positive results,
and expects to install low-cost modifications and a new flue gas conditioning
system to maximize the effects of such controls.
In addition to the Phase II Acid Rain Program requirements, the Company is
responsible for additional 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. Flue gas conditioning and post-combustion
NO\\X\\ reduction technologies may be employed to meet the one-hour standard if
economically justified. Also, the Company is examining and developing innovative
emissions technologies designed to reduce costs. The Company also continues to
work with the operators of its jointly owned stations to implement cost-
effective compliance strategies to meet these 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 the 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 Clean Air Act requirements through the year 2000 will be approximately $20
million.
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
what 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.
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. However, as the Kyoto Protocol has yet to be either signed or
ratified, and the related greenhouse gas reduction programs remain undeveloped,
the costs of compliance cannot be determined by the Company at this time.
In 1992, the DEP issued Residual Waste Management Regulations governing the
generation and management of non-hazardous residual waste, such as coal ash. The
Company is assessing the sites it utilizes and has developed compliance
strategies that are currently under review by the DEP. Capital costs of $2.8
million were incurred by the Company in 1997 to comply with these DEP
regulations. Based on information currently available, approximately $8 million
will be spent in 1998. The additional capital cost of compliance through the
year 2000 is estimated, based on current information, to be approximately $16
million. This estimate is subject to the results of groundwater assessments and
DEP final approval of compliance plans.
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. In September 1997, the Company amended its
service contract with Itron, Inc., with respect to CARS. The amendment extends
by one year, into 1998, the period during which Itron, Inc., will install and
finalize the system. As of December 31, 1997, more than 98 percent of customers'
meters had been adapted for CARS, and more than 450,000 meters were being read
automatically.
Year 2000
Many existing computer programs 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. Such failures could cause disruptions in normal business
operations.
In 1994, the Company inventoried and assessed the critical information
systems that impact operations and financial reporting (including systems with
respect to the general ledger, supply chain, billing, payroll, human resources,
financial reporting and certain types of data for plant maintenance) in order to
develop a strategy to address required computer software changes and upgrades
relating to such operations. By 1995, a plan to test
7
and, as necessary, replace, upgrade or repair these systems had been developed
and implementation had begun, with an anticipated completion date in 1999.
Although implementation of the plan has been accelerated in certain respects by
Year 2000 issues, the planned replacement, upgrade and repair of the systems is
also generally required for business purposes unrelated to the Year 2000 issue.
The Company currently believes that implementation of the plan will minimize its
Year 2000 issues relating to these systems. Replacement, upgrade and repair
projects that have been completed or are currently in progress include, without
limitation, the replacement of an integrated plant maintenance system at BVPS
(including related computer hardware), replacement of the supply chain
(purchasing and inventory) system, and release upgrades of packaged software for
the corporate financial recordkeeping system. The cost of all such projects is
currently estimated to be $35 million, approximately one-half of which had been
incurred through 1997. Duquesne has been expensing or capitalizing such costs in
accordance with appropriate accounting policies.
The Company has assembled a team to inventory and assess the Year 2000
issues that impact it. The team is comprised of management representatives from
all functional areas of the Company's businesses. In addition to monitoring the
information systems plan described above, the goals of the team include an
assessment of the Company's exposure to Year 2000-related problems in devices
and equipment containing embedded microprocessors that may not correctly
identify the year, as well as potential problems that may originate with third
parties outside the Company's control. The Company also participates in the
Electric Power Research Institute's project to share information about technical
issues regarding the Year 2000 problem with other entities in the electric
utility industry.
Given the fact that the Company's assessment, as noted above, is currently
in progress, the Company cannot currently estimate the exact extent of any
outstanding Year 2000 systems and equipment issues, the specific time frame in
which any required corrections would need to be made and the costs to the
Company in correcting any possible related outstanding matters. Until the
Company's assessment is completed, it cannot determine whether Year 2000 issues
and related costs will be material to the Company's operations, financial
condition and results of operations.
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, 1997 to 7.0
percent. The assumed change in future compensation levels and 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 M to
the consolidated financial statements, on page 43. The resulting change in
related expenses for subsequent years is not expected to be material.
Recent Accounting Pronouncements
SFAS No. 130, Reporting Comprehensive Income (SFAS No. 130) and SFAS No.
131, Disclosures about Segments of an Enterprise and Related Information (SFAS
No. 131), have been issued and are effective for fiscal years beginning after
December 15, 1997. SFAS No. 130 defines comprehensive income and outlines
certain reporting and disclosure requirements related to comprehensive income.
SFAS No. 131 requires certain disclosures about business segments of an
enterprise, if applicable. The adoption of SFAS No. 130 and SFAS No. 131 is not
expected to have a significant impact on the Company's financial statements or
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.
8
Executive Officers of the Registrant
- -------------------------------------------------------------------------------
Set forth below are the names, ages as of March 1, 1998, and positions during
the past five years of the executive officers of DQE. Additional information
related to the executive officers of DQE and Duquesne is set forth on page 21 of
DQE's Annual Report to Shareholders for the year ended December 31, 1997. The
information is incorporated here by reference.
Name Age Office
David D. Marshall 45 President and Chief Executive Officer since
August 1996. Executive Vice President
since February 1995. Vice President from July 1989
to February 1995.
Gary L. Schwass 52 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 August 1996.
James D. Mitchell 46 Vice President since February 1995. Assistant
Treasurer from January 1990 to February 1995.
Victor A. Roque 51 Vice President since April 1995 and General
Counsel since November 1994. Previously Vice
President, General Counsel and Secretary for
Orange and Rockland Utilities from
April 1989 to November 1994.
Morgan K. O'Brien 37 Vice President since October 1997. Controller and
Principal Accounting Officer since October
1995. Assistant Controller from December 1993 to
October 1995. Manager, Corporate Taxes at Duquesne Light
Company from September 1991 to December 1993.
Donald J. Clayton 43 Vice President since October 1997. Treasurer since
August 1996. Assistant Treasurer from October 1995
to August 1996. Treasurer of Duquesne Light
Company since January 1995 and Assistant Treasurer
from May 1990 to January 1995.
Jack E. Saxer, Jr. 54 Vice President since April 1996. Assistant Treasurer
from January 1996 to 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.
9
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.
The Company owns all or a portion of the following generating units except
Beaver Valley Unit 2, which is leased.
Company's
Share of Plant Output
Capacity Year Ended
(Megawatts) December 31, 1997
Name and Location Type Summer Winter (Megawatt-hours)
- ---------------------------- ------- -------- ------ ------------------
Cheswick Coal 562 570 3,475,197
Springdale, Pa.
Elrama Coal 474 487 2,097,700
Elrama, Pa.
Sammis Unit 7 (1) Coal 187 187 998,838
Stratton, Ohio
Eastlake Unit 5 (1) Coal 186 186 730,184
Eastlake, Ohio
Beaver Valley Unit 1 (1) Nuclear 385 385 1,925,121
Shippingport, Pa.
Beaver Valley Unit 2 (1) Nuclear 113 113 878,998
Shippingport, Pa.
Perry Unit 1 (1) Nuclear 161 164 1,117,806
North Perry, Ohio
Bruce Mansfield Unit 1 (1) Coal 228 228 1,397,484
Shippingport, Pa.
Bruce Mansfield Unit 2 (1) Coal 62 62 297,012
Shippingport, Pa.
Bruce Mansfield Unit 3 (1) Coal 110 110 511,924
Shippingport, Pa.
Brunot Island Oil 166 178 5,034
Brunot Island, Pa.
----- ----- ----------
Total 2,634 2,670 13,435,298
===== ===== ==========
(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.
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 Item 1. BUSINESS "Fossil Fuel" discussion on page 4.)
Additional information relating to Item 2. PROPERTIES, is set forth in
"Property, Plant and Equipment," Note C to the consolidated financial statements
on page 29 of this Report. The information is incorporated here by reference.
10
Item 3. Legal Proceedings.
Rate-Related Legal Proceedings, Property, Plant and Equipment - Related Legal
Proceedings and Environmental Legal Proceedings
- --------------------------------------------------------------------------------
Eastlake Unit 5
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. In October 1995, CEI commenced an
action against the Company in the Court of Common Pleas, Lake County, Ohio
seeking to prevent the Company from taking any action to effect a partition on
the basis of a waiver of partition covenant contained in the deed to the land
underlying Eastlake. 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. Currently, the
parties are engaged in settlement discussions. The Company anticipates that a
trial will commence late in 1998.
Proposed Merger
In September 1997 the City of Pittsburgh filed a federal antitrust suit
seeking to prevent the merger and asking for monetary damages. Although the
United States District Court for the District of Western Pennsylvania dismissed
the suit in January 1998, the City filed an appeal and asked for expedited
review. The Company anticipates a decision on whether the appeal has been
granted by late March 1998. Unless otherwise indicated, all information
presented in this report relates to the Company only and does not take into
account the proposed merger between the Company and AYE.
Proceedings involving the Company's rates are reported in Item 7. MANAGEMENT'S
DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS "Rate
Matters." Proceedings involving Property, Plant and Equipment are reported in
Item 1. BUSINESS "Property, Plant and Equipment." Proceedings involving
environmental matters are reported in Item 1. BUSINESS "Environmental Matters."
Item 4. Submission of Matters to a Vote of Security Holders.
Not applicable.
Part II
Item 5. Market for Registrant's Common Equity and Related Shareholder Matters.
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, 1997 and on page 43 in
Note L and page 46 in Note N hereto. The information is incorporated here by
reference. During 1997 and 1996, DQE declared quarterly dividends on its common
stock totaling $1.38 per share and $1.30 per share, respectively. At February
28, 1998, there were approximately 72,000 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, 1997, are set forth on pages 22 and 23 of the DQE Annual Report to
Shareholders for the year ended December 31, 1997. The information is
incorporated here by reference.
11
Item 7. Management's Discussion and Analysis of Financial Condition and Results
of Operations.
Results of Operations
- --------------------------------------------------------------------------------
The Company's future financial condition and its future operating results are
substantially dependent upon the effects of the Restructuring Plan or Stand-
Alone Plan currently before the PUC. The Company expects to be given the
opportunity to fully recover its transition costs. However, to the extent the
Company does not ultimately recover its transition costs, a charge against
earnings would be recognized. Such charge could have a materially adverse effect
on the Company's financial position, results of operations and cash flows. (See
"Rate Matters" on page 17.)
Earnings and Dividends
The Company's earnings per share in 1997 were $2.57, versus 1996 earnings per
share of $2.32, a $0.25 or 10.8 percent increase. Net income increased to $199.1
million in 1997 from $179.1 million in 1996, a $20.0 million or 11.2 percent
increase. In 1997, Duquesne contributed $1.78 to earnings per share, a decrease
from the prior year earnings per share contribution of $1.89. The decrease was
the result of the incremental $25 million accelerated nuclear fixed asset
recovery as detailed in Duquesne's 1996 PUC-approved mitigation plan. Despite
mild 1997 temperatures as compared to 1996, the utility increased total sales to
electric utility customers, primarily as a result of stronger industrial sales.
The market-driven subsidiaries contributed $0.79 or 30.7 percent of total
earnings per share in 1997, up from $0.43 or 18.5 percent of total earnings per
share in 1996. The sale of Chester Engineers (Chester) in the second quarter of
1997 and the sale of Exide Electronics Group, Inc. (Exide) stock in the fourth
quarter of 1997 together contributed $0.17 to earnings per share. The remaining
increase is the result of earnings attributable to the increased level of long-
term investments.
Earnings per share in 1996 were $2.32, an increase of $0.12 or 5.5 percent
over 1995 earnings per share of $2.20. Net income of $179.1 million in 1996 was
greater by $8.5 million or 5.0 percent from net income of $170.6 million in
1995. Duquesne contributed to earnings per share $1.89 in 1996 and $1.88 in
1995. The slight increase was the result of increased income from long-term
investments made during late 1995 and 1996, offset by the $25 million
accelerated nuclear fixed asset recovery as detailed in Duquesne's 1996 PUC-
approved mitigation plan. In 1996, the market-driven subsidiaries added $0.43, a
34.4 percent increase over the 1995 contribution, due primarily to income from
long-term investments made during late 1995 and 1996 and to increased income at
Chester.
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 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.
The Company has continuously paid dividends on common stock since 1953. The
Company's annualized dividends per share were $1.44, $1.36 and $1.28 at December
31, 1997, 1996 and 1995, respectively. During 1997, the Company paid a quarterly
dividend of $0.34 per share on each of January 1, April 1, July 1 and October 1.
The quarterly dividend declared in the fourth quarter of 1997 was increased from
$0.34 to $0.36 per share payable January 1, 1998. 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;
and regulatory matters experienced by the electric utility industry generally,
more specifically the transition to competition and related issues pending in
Pennsylvania. (See "Rate Matters" on page 17.) The Company's stock price was
$35.13 at the end of 1997. The book value per share of common stock was $19.30
at December 31, 1997, which represents a 7.2 percent increase in book value
since December 31, 1996.
12
Revenues
Total operating revenues in 1997 decreased $7.0 million or 0.6 percent as
compared to 1996. Comparing 1996 and 1995 operating revenues, there was an
increase of $6.0 million or 0.5 percent.
- -------------------------------------------------------------------------------
Increase (Decrease) from Prior Year
(Revenues in Millions of Dollars) 1997 1996
- -------------------------------------------------------------------------------
KWH Revenues KWH Revenues
Residential (1.6)% $ 0.5 (1.7)% $(8.9)
Commercial (0.7)% 5.2 0.1% (2.1)
Industrial 6.5 % 8.0 1.5% 0.0
Less: Provision for Doubtful Accounts 0.4 (2.8)
- -------------------------------------------------------------------------------
Sales to Electric Utility Customers 1.0 % 13.3 0.0% (8.2)
- -------------------------------------------------------------------------------
Sales to Other Utilities (56.4)% (33.4) 11.3% 2.3
Other Revenues 13.1 11.9
- -------------------------------------------------------------------------------
Total (11.1)% $ (7.0) 2.2% $ 6.0
===============================================================================
Sales to Electric Utility Customers
Operating revenues are primarily derived from the Company's sales of
electricity. Currently the PUC authorizes rates for electricity sales which are
cost-based and are designed to recover the Company's operating expenses and
investment in electric utility assets and to provide a return on the investment.
Customer revenues fluctuate as a result of changes in sales volume and changes
in fuel and other energy costs, as these costs are generally recoverable from
customers through the Energy Cost Rate Adjustment Clause (ECR). Under current
fuel cost recovery provisions, fuel revenues generally equal fuel expense,
including the fuel component of purchased power, and do not affect net income.
As required under the Customer Choice Act, the Company has filed with the PUC
its plan addressing its proposed restructuring to operate in a competitive
environment including unbundled charges for transmission, distribution,
generation, and a CTC. The Company cannot predict what rates the PUC will
authorize in connection with these filings and the phase-in to competition. (See
"Rate Matters" on page 17.)
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.
1997 Compared to 1996: In 1997, net customer revenues reflected on the
statement of consolidated income increased $13.3 million or 1.2 percent from
1996. The variance can be attributed primarily to an increase in revenues to
cover an increase in customer energy costs. The customer energy cost increase
was $19.9 million. To a lesser extent, customer revenues were favorably impacted
by an increase of 6.5 percent in industrial kilowatt hour (KWH) sales. Sales to
a new customer, an industrial gas supplier, represent 64 percent of the
increase, while the remaining increase is due to expansion of one of the
Company's largest customers' manufacturing facilities. Residential and
commercial sales decreased 95,295 KWH when comparing 1997 and 1996 due to mild
1997 temperatures. Sales to the Company's 20 largest customers accounted for
approximately 14 percent of customer revenues in 1997, 1996 and 1995.
1996 Compared to 1995: Net customer revenues decreased $8.2 million or 0.8
percent in 1996 compared to 1995. The variance can be attributed primarily to
decreased residential customer KWH sales of 1.7 percent due to unseasonably warm
summer temperatures in 1995, as compared to 1996, resulting in decreased
revenues of $8.9 million. Industrial KWH sales volume in 1996 increased when
compared to the prior year because of a self-generation outage experienced in
1996 by one of the Company's large industrial customers.
Sales to Other Utilities
Short-term sales to other utilities are regulated by the FERC and 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.
1997 Compared to 1996: The Company's electricity sales to other utilities in
1997 were $33.4 million or 57.4 percent less than in 1996. The reduction is due
to reduced availability of generating capacity as a result of the sale of the
Company's 50 percent interest in the Ft. Martin Power Station (Ft. Martin) in
October 1996 and to a 9.1 percent increase in other generating stations' outage
hours when compared to 1996.
1996 Compared to 1995: In 1996, electricity sales to other utilities were $2.3
million or 4.2 percent greater than in 1995 due to the timing of generating
station outages.
13
Other Operating Revenues
Other operating revenues include the Company's non-KWH utility revenues and
revenues from market-based operating activities.
1997 Compared to 1996: The other operating revenue increase of $13.1 million
or 14.2 percent when comparing 1997 to 1996 is the result of $20.4 million in
revenues from a landfill gas recovery investment made in the fourth quarter of
1996 and growth in the market-driven businesses, partially offset by decreased
revenues as a result of the sale of Chester in the second quarter of 1997.
1996 Compared to 1995: The increase of $11.9 million or 14.7 percent in other
operating revenues in 1996 as compared to 1995 is primarily due to increased
revenues at Chester, then a wholly owned subsidiary of DE, and revenues of a
landfill gas recovery investment made in the fourth quarter of 1996.
Operating Expenses
Fuel and Purchased Power Expense
Fluctuations in fuel and purchased power expense generally result from changes
in the cost of fuel, the mix between coal and nuclear generation, the total KWHs
sold, and generating station availability. Because of the ECR, changes in fuel
and purchased power costs did not impact earnings in 1997, 1996 and 1995. Under
the Company's mitigation plan approved by the PUC in June 1996, the level of
energy cost recovery is capped at 1.47 cents per KWH through May 2001. Pending
the outcome of the Company's Restructuring Plan or Stand-Alone Plan filing, the
Company may freeze the ECR and roll it into base rates. (See "Rate Matters" on
page 17).
1997 Compared to 1996: Fuel and purchased power expense decreased $13.5
million or 5.7 percent in 1997, as compared to 1996, as a result of an 11.1
percent reduction in energy volume supplied. The $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 a 9.1 percent increase in outage hours forced the
Company to buy purchased power during high demand periods, resulting in
increased costs.
1996 Compared to 1995: The increase of $5.0 million or 2.1 percent in 1996 as
compared to 1995 was the result of a 33 percent increase in purchased power
prices. This increase was partially offset by lower nuclear fuel costs.
Other Operating Expense
1997 Compared to 1996: The increase of $7.8 million or 2.6 percent in 1997 as
compared to 1996 can be attributed to operating costs from a landfill gas
recovery investment made in the fourth quarter of 1996 and growth in the market-
driven businesses, partially offset by the reduced operating costs associated
with Chester, which was sold during the second quarter of 1997.
1996 Compared to 1995: Other operating expense increased $6.0 million when
comparing 1996 to 1995. The increase was the result of several factors,
including a one-time lease charge, a full year of expense for DES in 1996 and
operating costs of a landfill gas recovery investment made in the fourth quarter
of 1996.
Maintenance Expense
1997 Compared to 1996: Maintenance expense increased $4.5 million or 5.7
percent. During 1997 there were approximately 21 percent more forced outage
hours at nuclear stations than in 1996.
1996 Compared to 1995: Maintenance expense decreased $3.1 million or 3.8
percent in 1996 from 1995. The decrease was primarily due to lower maintenance
outage costs as a result of fewer fossil station outages in 1996.
Depreciation and Amortization Expense
1997 Compared to 1996: During 1997, depreciation and amortization expense
increased $19.9 million or 8.9 percent from 1996. The May 1, 1996 increase in
the Company's electric utility operations' composite depreciation rate from 3.5
percent to 4.25 percent resulted 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 by $25 million.
Offsetting the increase 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.
1996 Compared to 1995: Depreciation and amortization expense increased $20.4
million in 1996 when compared to 1995 primarily due to the increase in the
Company's electric utility operations' composite depreciation rate from 3.5
percent to 4.25 percent effective May 1, 1996. During the third quarter of 1996,
the Company completed recovery of its investment in Perry Unit 2, the
construction of which was abandoned by the Company in 1986. The resultant
decrease in amortization expense was offset by the Company's increase in
depreciation, as well as $9 million that was expensed related to the
depreciation portion of deferred rate synchronization costs in conjunction with
the Company's 1996 PUC-approved mitigation plan.
14
Taxes Other Than Income Taxes
During 1997 and 1996, taxes other than income taxes decreased $3.4 million and
$2.7 million, respectively, from the prior year, primarily due to the reduced
West Virginia business and occupation taxes as a result of the sale of Ft.
Martin in the fourth quarter of 1996.
Other Income
1997 Compared to 1996: The Company increased other income significantly over
1996 levels. A $56.0 million or 75.9 percent increase in other income resulted
from long-term investment income, gains on the sale of Chester and 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 late in 1996 and throughout 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. In the fourth quarter of 1997, the
Company's investment in Exide stock was sold for a pre-tax gain of approximately
$11 million.
1996 Compared to 1995: The increase of $21.5 million in other income, when
comparing 1996 and 1995, was primarily the result of income from long-term
investments made during late 1995 and 1996.
Interest and Other Charges
1997 Compared to 1996: Interest and other charges increased $5.4 million or
4.9 percent during 1997 as compared to 1996. The increase in 1997 was primarily
the result of paying a full year of dividends in 1997 related to the Monthly
Income Preferred Securities (MIPS) issued in May 1996.
1996 Compared to 1995: The increase in interest and other charges in 1996 from
1995 was $2.7 million related to the MIPS issued in May 1996 and $2.5 million of
interest on new term loans. The interest expense increase was offset by
decreases from the retirement of long-term debt and preferred stock of
subsidiaries during 1995.
Income Taxes
Income taxes were higher in 1997 as compared to 1996 by $8.4 million and lower
in 1996 as compared to 1995 by $9.3 million. The 1997 variance was due to a
higher level of taxable income primarily as a result of the gains recognized
with the sale of Chester and Exide. In comparing 1996 and 1995, income taxes
decreased primarily due to reduced taxable income.
Liquidity and Capital Resources
- -------------------------------------------------------------------------------
The Company's future liquidity and capital resources could be reduced as a
result of the Restructuring Plan or Stand-Alone Plan currently before the PUC.
The Company cannot predict the level of transition cost recovery that will be
permitted, the impact of any such recovery on the Company's capitalization and
the continued compliance with the Company's debt covenants or whether internally
generated cash will continue to meet or exceed the Company's capital
requirements and dividend payments. (See "Rate Matters" on page 17.)
Capital Expenditures
The Company spent approximately $118.3 million in 1997, $101.2 million in 1996
and $94.2 million in 1995 for capital expenditures, of which $93.7 million in
1997, $88.5 million in 1996 and $78.7 million in 1995 was spent for electric
utility construction. The remaining capital expenditures were related to the
Company's market-driven businesses. 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 $130 million during 1998 and
$100 million in each of 1999 and 2000 for electric utility construction.
In 1997, the Company formed a strategic alliance with CQ Inc. to produce E-
Fuel(TM), a coal-based synthetic fuel. The first six plants to produce E-
Fuel(TM) are under construction and are expected to be in operation by mid-1998.
The Company estimates the cost of this construction to be approximately $25
million in 1998.
Long-Term Investments
The Company has made long-term investments in the following areas: leases,
affordable housing, gas reserves, energy solutions and water companies.
Investing activities during 1997 included approximately $180 million in lease
investments, $11 million in landfill gas reserve investments, $16 million in
affordable housing investments, 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
investments, 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 investments. The Company disposed
of long-term leveraged lease assets totaling $18 million during 1996. Investing
activities of approximately $192 million during 1995 were balanced between
investment types.
15
In 1997, the Company acquired 100 percent of the Class A Stock of AquaSource,
Inc. (AquaSource), which was formed to acquire small and mid-sized water,
wastewater and water services companies, with its initial focus in Texas. At
December 31, 1997, the Company had invested approximately $7 million (of which
approximately $1.5 million was in the form of DQE Preferred Stock) to acquire
the stock or assets of seven water, wastewater and water services companies. In
February 1998, the Company issued 159,732 shares of DQE Preferred Stock,
representing an investment of approximately $16 million in a water company. The
Company has committed approximately $24 million for additional investments in
water, wastewater and water services companies for the first quarter of 1998.
In 1997, the Company entered into a partnership with MCI Communications
Corporation. The Company expects this partnership will lead to investment
opportunities in the expanding telecommunications business.
The Company is also pursuing power project opportunities through several of
its investments, including landfill gas investments and certain leasehold
investments, and its joint venture with Marathon Oil.
Financing
The Company expects to meet its current obligations and debt maturities
through the year 2002 with funds generated from operations and through new
financings. At December 31, 1997, the Company was in compliance with all of its
debt covenants.
Mortgage bonds in the amount of $35 million matured in February 1998 and were
retired using available cash. In February 1998, the Company issued a notice of
redemption of $100 million principal amount of its 8.75 percent mortgage bonds,
originally due in May 2022. The redemption date is March 1998, and the
redemption price is 106.5625 percent of the principal amount, plus interest
accrued until redemption. The redemption is to be partially financed with the
proceeds of the February 1998 issuance of $40 million principal amount of 6.45
percent mortgage bonds, due in February 2008. The Company anticipates additional
financing of the redemption through the further issuance of lower interest rate
mortgage bonds. Mortgage bonds in the amount of $35 million and $5 million will
mature in June and November 1998, respectively. The Company expects to retire
these bonds with available cash or to refinance the bonds. (See "Rate Matters"
on page 17.)
The Company has $150 million in bank term loans outstanding at December 31,
1997, 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. (See
"Long-Term Investments" discussion on page 15.) As of December 31, 1997, 15,480
shares of DQE Preferred Stock had been issued and were outstanding. An
additional 159,732 shares of DQE Preferred Stock were issued in February 1998.
In October 1997, a Duquesne subsidiary issued ten shares of preferred stock,
par value $100,000 per share. 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.
Short-Term Borrowings
At December 31, 1997, the Company had two extendible revolving credit
arrangements, including a $125 million facility expiring in June 1998 and a $150
million facility expiring in October 1998. 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, 1997 and December 31, 1996, 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, 1997 or December 31, 1996. The accounts receivable sales agreement,
which expires in June 1998, 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, 1997, the amount of nuclear fuel financed by the Company under this
arrangement totaled approximately $46.2 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;
16
reload cycle design; operations; 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 1998, 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.
Rate Matters
- -------------------------------------------------------------------------------
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 have assets recorded on their
balance sheets at above-market costs, thus creating transition or stranded
costs.
In Pennsylvania, the Customer Choice Act went into effect 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, delivery of the
electricity from the generation supplier to the customer will remain the
responsibility of the existing franchised utility. The Customer Choice Act also
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 (running through 1998) and a phase-in to competition period (beginning in
1999). For the first stage, the Company filed a pilot program with the PUC on
February 27, 1997. For the second stage, the Company filed on August 1, 1997 its
restructuring and merger plan (the Restructuring Plan) and its stand-alone
restructuring plan (the Stand-Alone Plan) with the PUC. (See the detailed
discussion of these plans on page 19.)
Customer Choice Pilots
The pilot period gives utilities an opportunity to examine a wide range of
technical and administrative details related to competitive markets, including
metering, billing, and cost and design of unbundled electric services. The
Company pilot filing proposed unbundling transmission, distribution, generation
and competitive transition charges and offered participating customers the same
options that were to be available in a competitive generation market. The pilot
was designed to comprise approximately 5 percent of the Company's residential,
commercial and industrial demand. The 28,000 customers participating in the
pilot may choose unbundled service, with their electricity provided by an
alternative generation supplier, and will be subject to unbundled distribution
and CTC charges approved by the PUC and unbundled transmission charges pursuant
to the Company's FERC-approved tariff. On May 9, 1997, the PUC issued a
Preliminary Opinion and Order approving the Company's filing in part, and
requiring certain revisions. The Company and other utilities objected to several
features of the PUC's Preliminary Opinion and Order. Hearings on several key
issues were held in July. The PUC issued its final order on August 29, 1997,
approving a revised pilot program for the Company. On September 8, 1997, the
Company appealed the determination of the market price of generation set forth
in this order to the Commonwealth Court of Pennsylvania. The Company expects a
hearing to be scheduled for mid-1998. Although this appeal is pending, the
Company complied with the PUC's order to implement the pilot program that began
on November 3, 1997.
Financial Impact of Pilot Program Order
It is anticipated that the net financial impact of the Company's customers'
choosing alternative generation suppliers during the pilot period (through 1998)
will be a reduction of operating revenues of approximately $1 million per month.
(See "Forward-Looking Statements" discussion on page 20.) The Company is seeking
in its Restructuring Plan and its Stand-Alone Plan to maintain current rates
under Section 2804(4)(v) of the Customer Choice Act (Rate Cap Provision), which
states that in certain circumstances an electric distribution utility may roll
its energy cost rate into base rates without reducing its rates below the capped
level if the PUC determines that excess earnings are to be used for mitigation
of transition costs. The Company will reduce its accelerated nuclear lease
amortization to offset the shortfall, if any, in operating revenues between the
pilot program and the final approved rates.
Phase-In to Competition
The phase-in to competition begins on January 1, 1999, when 33 percent of
customers will have customer choice (including customers covered by the pilot
program); 66 percent of customers will have customer choice no later than
January 1, 2000; and all customers will have customer choice no later than
January 1, 2001.
17
However, in its sole order to date (the PECO Order), the PUC ordered the phase-
in provisions of the Customer Choice Act to require the acceleration of the
second and third phases to January 2, 1999 and January 2, 2000, respectively. As
they are phased-in, customers that have chosen an electricity generation
supplier other than the Company will pay that supplier for generation charges,
and will pay the Company a CTC (discussed below) and unbundled charges for
transmission and distribution. Customers that continue to buy their generation
from the Company will pay for their service at current regulated tariff rates
divided into unbundled generation, transmission and distribution charges. The
PECO Order concluded that under the Customer Choice Act, an electric
distribution company, such as Duquesne, is to remain a regulated utility and may
only offer PUC-approved, tariffed rates (including unbundled generation rates).
Delivery of electricity (including transmission, distribution and customer
service) will continue to be regulated in substantially the same manner as under
current regulation.
Rate Cap and Transition Cost Recovery
Before the phase-in to customer choice begins in 1999, the PUC expects
utilities to take vigorous steps to mitigate transition costs as much as
possible without increasing the rates they currently charge customers. The
Company has mitigated in excess of $350 million of transition costs during the
past three years through accelerated annual depreciation and a one-time write-
down of nuclear generating station costs, accelerated recognition of nuclear
lease costs, increased nuclear decommissioning funding, and amortization of
various regulatory assets. This relative level of transition cost reduction,
while holding rates constant, is unmatched within Pennsylvania.
The PUC will determine what portion of a utility's transition costs that
remain at January 1, 1999 will be recoverable through a CTC from customers. The
CTC recovery period could last through 2005, providing a utility a total of up
to nine years beginning January 1, 1997 to recover transition costs, unless this
period is extended as part of a utility's PUC-approved transition plan. An
overall four-and-one-half-year rate cap from January 1, 1997 will be imposed on
the transmission and distribution charges of electric utility companies.
Additionally, electric utility companies may not increase the generation price
component of rates as long as transition costs are being recovered, with certain
exceptions. Following is a summary of the Company's requested transition cost
recovery, net of deferred taxes, as of January 1, 1999; the related net balances
as of December 31, 1997; and the amounts mitigated during the past three years.
Transition Costs
- --------------------------------------------------------------------------------------------
Mitigation Balance CTC Recovery
(Amounts in Millions of Dollars) 1/1/95 - 12/31/97 12/31/97 Requested 1/1/99
- --------------------------------------------------------------------------------------------
Nuclear generation plant (a) $232 $ 968 $ 877
Fossil generation plant (a) -- 541 541
Generation-related regulatory assets (b) 103 382 357
Decommissioning costs (c) 18 133 124
- --------------------------------------------------------------------------------------------
Total $353 $2,024 $1,899
============================================================================================
(a) Nuclear and fossil generation plant represent a projection of the amount
by which the net book value, including materials and supplies inventories, and
fuel inventories, of the generating plants exceeds the market value for these
plants. "Nuclear generation plant" also includes the present value of future
above-market lease payments related to the sale/leaseback of BV Unit 2.
(b) Generation-related regulatory assets represent costs which under the
historical ratemaking process were deemed recoverable from customers through
future rates. These regulatory assets include, among other items, amounts
related to future federal income tax payments, premiums paid to reacquire debt,
initial operating costs of BV Unit 2 and Perry Unit 1, and energy costs not
recovered currently.
(c) Decommissioning costs represent the estimated present value of unfunded
fossil and nuclear generation plant decommissioning costs.
Financial Exposure to Transition Cost Recovery
Any estimate of the ultimate level of transition costs (including those set
forth in the table above) depends on, among other things, the extent to which
such costs are deemed recoverable by the PUC; the ongoing level of the Company's
costs of operations; regional and national economic conditions; and growth of
the Company's sales. The Company believes that it is entitled to recover
substantially all of its transition costs, but cannot predict the outcome of
this regulatory process. (See "Forward-Looking Statements" discussion on page
20.) Indeed, the PECO Order provides for recovery by PECO Energy Company (PECO)
of 100 percent of transition costs determined to be just and reasonable by the
PUC. However, in determining transition costs, the PUC found the market value of
PECO's generating units to be significantly higher than the estimate of market
value sponsored by PECO. Thus, the total amount of transition costs requested by
PECO was significantly more than
18
that allowed by the PUC in the PECO Order, as the PUC-determined market value
offset a larger portion of the transition costs. The PUC-ordered recovery of
PECO's transition costs through a CTC is permitted over an eight-and-one-half-
year period beginning January 1, 1999. However, PECO is only permitted to earn a
return on the unamortized balance of transition costs at a rate equal to its
long-term cost of debt. In the event that the PUC rules that any or all of the
Company's transition costs cannot be recovered through a CTC mechanism, or the
Company fails to satisfy the requirements of SFAS No. 71, these costs will be
written off. (See Item 1. BUSINESS "Regulation" on page 2.) On January 26, 1998,
PECO announced that it was reducing its dividend by 44 percent, and also that it
was reporting a net loss for 1997 of $1.5 billion, including an extraordinary
charge of $3.1 billion ($1.8 billion net of taxes) in the fourth quarter of 1997
to reflect the effects of the PECO Order. As the Company has substantial
exposure to transition costs relative to its size, significant transition cost
write-offs could have a materially adverse effect on the Company's financial
position, results of operations and cash flows. Various financial covenants and
restrictions could be violated if substantial write-off of assets or recognition
of liabilities occurs. Under such circumstances the Company may face constraints
on its ability to pay dividends (See "Earnings and Dividends" discussion on page
12), issue new mortgage debt or maintain access to bank lines of credit, thus
negatively impacting its operations.
Timetable for Restructuring Plan and Stand-Alone Plan Approval
On August 1, 1997, the Company filed the Restructuring Plan and the Stand-
Alone Plan with the PUC. Although the provisions of the Customer Choice Act
require a PUC decision nine months from the filing date (which would be April
30, 1998), the Pennsylvania Attorney General's Office requested an extension in
order to conduct an investigation into certain competition issues relating to
the Restructuring Plan. Pursuant to an arrangement among the Company, the PUC
and the Attorney General, the Company anticipates a decision by the PUC (with
respect to the Restructuring Plan if the merger is approved, or with respect to
the Stand-Alone Plan if the merger is not approved) on or before May 29, 1998 or
such later date as the parties may agree.
Stand-Alone Plan
In the event the merger with AYE is not consummated under the filed
Restructuring Plan, the Company has sought approval for restructuring and
recovery of its own transition costs through a CTC under the Stand-Alone Plan.
The Company proposed that any finding of market value for the Company's
generating assets should be based on market evidence and not on an
administrative determination of that value based on price forecasts (the PECO
Order determined the market value of PECO's generation based on the price
forecast sponsored by the Pennsylvania Office of Consumer Advocate). In
addition, the Company proposed that such a final market valuation be conducted
in 2003, and that an annual competitive market solicitation be used to set the
CTC in the interim. The 2003 final market valuation would be performed by an
independent panel of experts using the best available market evidence at that
time. The Stand-Alone Plan filing also provided for certain triggers that would
accelerate the date of this final market valuation. Prior to the final
valuation, the Company would sell a substantial amount of power to the highest
bidder in an annual competitive solicitation. The annual market price
established by the solicitation would be used to set competitive generation
credits and determine the CTC as a residual from the generation rate cap under
the Rate Cap Provision. During the transition period, the Company committed to
accelerate amortization and depreciation of its generation-related assets and
cap its return on equity through a return on equity spillover mechanism, in
exchange for being allowed to charge existing rates under the Rate Cap
Provision. The Company committed to a minimum of $1.7 billion of amortization
and depreciation of generation-related assets by the end of 2005. Under the
proposed return on equity spillover mechanism, additional amortization and
depreciation in excess of this minimum $1.7 billion commitment would be recorded
in order to comply with the return on equity cap. The generation rate cap would
apply to the sum of the CTC and the competitive generation credit determined in
the annual competitive solicitation. The Stand-Alone Plan also proposed to
redesign individual tariffs to encourage more efficient consumption and further
mitigate transition costs during the transition period. Consistent with the
Company's long-standing commitment to economic development, the rate redesign
provides for a significant reduction in the cost of electricity for incremental
consumption. Application of the rate redesign to the CTC would also have the
potential to maximize mitigation of transition costs during the transition
period.
As an alternative to a market-based valuation in 2003, if the PUC finds that a
determination of market value as of December 31, 1998 is required by the
Customer Choice Act, then the Company has agreed that the PUC may order an
immediate auction of the Company's generation at that time.
Restructuring Plan
The Restructuring Plan incorporates the benefits of the merger with AYE, such
as anticipated savings to the Company, on a nominal basis, of $365 million in
generation-related costs over 20 years, and $9 million in transmission-related
costs and $173 million in distribution-related costs over 10 years. The Company
plans to use the generation-related portion of its share of net operating
synergy savings to shorten the transition cost recovery period. In addition, the
anticipated cost savings are expected to permit the Company to increase its
minimum depreciation and amortization commitment by $160 million, reduce
distribution rates by $25 million in
19
2001, and freeze distribution rates at this reduced level until 2005. The
merger-related synergies are expected to enable the Company to reduce its
transition costs in 2005 by $200 million. (See "Forward-Looking Statements"
discussion below.) The Restructuring Plan also incorporates the market-based
approach to determining stranded costs proposed by the Company in its Stand-
Alone Plan. The 2003 final market valuation will be performed by an independent
panel of experts using the best available market evidence at that time,
including a potential sale of a portion of the combined company's generating
assets. Certain triggers will accelerate the date of this final market valuation
if market prices rise significantly or the minimum amortization commitment is
satisfied prior to 2003. The annual market price established by the Company's
solicitation would be used to set competitive generation credits and to
determine the CTC as a residual from the generation rate cap under the Rate Cap
Provision. The Company's minimum amortization commitment of $1.7 billion in the
proposed Stand-Alone Plan has been increased under the Restructuring Plan. As in
the Stand-Alone Plan, the determination of transition costs in 2003 will compare
the book value of generating assets in 2005 (after netting the increased minimum
commitment to depreciation and amortization and any return on equity spillover)
with the market value of the generating assets in 2005. The opposing parties
believe that there should be a one-time valuation of the generating assets
performed at January 1, 1999. Any merger-related synergies relating to
generation would then be used to reduce the Company's transition costs as of
that date. These parties also believe that the Company's proposed distribution
rate decrease should be effective January 1, 1999, as well.
Additional Restructuring Plan Commitments
The Restructuring Plan also contains a number of commitments by the merged
DQE/AYE entity. First, the merged entity will open up its transmission system to
all parties on a reciprocal non-discriminatory basis and eliminate multiple rate
charges across the combined transmission system. Second, the merged entity will
join a recently proposed Midwest Independent System Operator (ISO) or other
then-existing ISO, or form its own ISO if no existing ISO offers acceptable
rules, including marginal cost transmission rates. Several utilities have
applications pending before the FERC to form ISOs. Third, the merged entity has
committed to make a report, 18 months after consummation of the merger, to the
PUC regarding its progress on the ISO commitment. The PUC may, at its option,
require the merged entity to relinquish control of 300 MW of generating capacity
to alleviate concerns over market power. The form of relinquishment would be at
the option of the merged entity; possible forms of relinquishment include an
energy swap, entering a power sale contract, divestiture of generating assets
and a bidding trust.
The Federal Filings
In addition to the PUC filings of the Restructuring Plan and the Stand-Alone
Plan, on August 1, 1997, the Company and AYE filed their joint merger
application with the FERC (the FERC Filing). Pursuant to the FERC Filing, the
Company and AYE have committed to forming or joining an ISO that meets the
entity's requirements, including marginal cost transmission pricing, following
the merger. In addition, the Company and AYE have stated in the FERC Filing that
following the merger the combined entity's market share will not violate the
market power conditions and requirements set by the FERC. On January 20, 1998,
the Company and AYE filed merger applications with the Antitrust Division of the
Department of Justice and the Federal Trade Commission. These applications are
currently pending.
Forward-Looking Statements
The foregoing paragraphs contain forward-looking statements (within the
meaning of the Private Securities Litigation Reform Act of 1995) regarding the
financial impact, consequences and benefits of the Customer Choice Act, the
pilot program, the Stand-Alone Plan, the Restructuring Plan and the merger with
AYE. Such forward-looking statements involve known and unknown risks and
uncertainties that may cause the actual results and benefits to materially
differ from those implied by such statements. Such risks and uncertainties
include, but are not limited to, the substance of PUC approvals regarding the
Stand-Alone Plan or the Restructuring Plan, general economic and business
conditions, industry capacity, changes in technology, integration of the
operations of AYE and the Company, regulatory conditions to the merger, the loss
of any significant customers, and changes in business strategy or development
plans.
Item 7A. Quantitative and Qualitative Disclosures About Market Risk.
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, 1997 totaled approximately $47.1 million. The
amount funded into the trusts is based on estimated returns which, if not
achieved as projected, could require additional unanticipated funding
requirements.
20
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 sheet of DQE, Inc. and
its subsidiaries as of December 31, 1997 and 1996, and the related consolidated
statements of income, retained earnings, and cash flows for each of the three
years in the period ended December 31, 1997. These financial statements are the
responsibility of the Company's management. Our responsibility is to express an
opinion on the financial statements based on our audits.
We conducted our audits in accordance with generally accepted auditing
standards. Those standards require that we plan and perform the audit to obtain
reasonable assurance about whether the financial statements are free of material
misstatement. An audit includes examining, on a test basis, evidence supporting
the amounts and disclosures in the financial statements. An audit also includes
assessing the accounting principles used and significant estimates made by
management, as well as evaluating the overall financial statement presentation.
We believe that our audits provide a reasonable basis for our opinion.
In our opinion, such consolidated financial statements present fairly, in all
material respects, the financial position of DQE, Inc. and its subsidiaries as
of December 31, 1997 and 1996, and the results of their operations and their
cash flows for each of the three years in the period ended December 31, 1997 in
conformity with generally accepted accounting principles.
/s/ Deloitte & Touche LLP
Pittsburgh, Pennsylvania
January 27, 1998
21
Statement of Consolidated Income
- ---------------------------------------------------------------------------------------------------------------------
(Thousands of Dollars, Except Per Share Amounts)
---------------------------------------------------
Year Ended December 31,
- ---------------------------------------------------------------------------------------------------------------------
1997 1996 1995
- ---------------------------------------------------------------------------------------------------------------------
Operating Revenues:
Sales of Electricity:
Residential $ 405,915 $ 405,392 $ 414,291
Commercial 494,834 489,646 491,789
Industrial 198,708 190,723 190,689
Provision for doubtful accounts (11,000) (10,582) (13,430)
- ---------------------------------------------------------------------------------------------------------------------
Net customer revenues 1,088,457 1,075,179 1,083,339
Utilities 24,861 58,292 55,963
- ---------------------------------------------------------------------------------------------------------------------
Total Sales of Electricity 1,113,318 1,133,471 1,139,302
Other 105,856 92,724 80,860
- ---------------------------------------------------------------------------------------------------------------------
Total Operating Revenues 1,219,174 1,226,195 1,220,162
- ---------------------------------------------------------------------------------------------------------------------
Operating Expenses:
Fuel and purchased power 223,411 236,924 231,968
Other operating 306,747 298,977 292,997
Maintenance 82,869 78,386 81,516
Depreciation and amortization 242,843 222,928 202,558
Taxes other than income taxes 82,567 85,974 88,658
- ---------------------------------------------------------------------------------------------------------------------
Total Operating Expenses 938,437 923,189 897,697
- ---------------------------------------------------------------------------------------------------------------------
Operating Income 280,737 303,006 322,465
- ---------------------------------------------------------------------------------------------------------------------
Other Income:
Long-term investment income 64,464 49,636 28,975
Gain on dispositions 34,364 5,119 9,129
Interest and other income 30,979 19,035 14,210
- ---------------------------------------------------------------------------------------------------------------------
Total Other Income 129,807 73,790 52,314
- ---------------------------------------------------------------------------------------------------------------------
Interest and Other Charges 115,638 110,270 107,555
- ---------------------------------------------------------------------------------------------------------------------
Income Before Income Taxes 294,906 266,526 267,224
- ---------------------------------------------------------------------------------------------------------------------
Income Taxes 95,805 87,388 96,661
- ---------------------------------------------------------------------------------------------------------------------
Net Income $ 199,101 $ 179,138 $ 170,563
=====================================================================================================================
Average Number of Common Shares
Outstanding (Thousands of Shares) 77,492 77,349 77,674
=====================================================================================================================
Basic Earnings Per Share of Common Stock $2.57 $2.32 $2.20
=====================================================================================================================
Diluted Earnings Per Share of Common Stock $2.54 $2.29 $2.17
=====================================================================================================================
Dividends Declared Per Share of Common Stock $1.38 $1.30 $1.21
=====================================================================================================================
See notes to consolidated financial statements.
Statement of Consolidated Retained Earnings
- ---------------------------------------------------------------------------------------------------------------------
(Thousands of Dollars)
-----------------------------------------------
As of December 31,
------------------------------------------------
1997 1996 1995
- ---------------------------------------------------------------------------------------------------------------------
Balance at beginning of year $ 777,607 $ 698,986 $ 622,072
Net income 199,101 179,138 170,563
Dividends declared (106,959) (100,517) (93,649)
- ---------------------------------------------------------------------------------------------------------------------
Balance at end of year $ 869,749 $ 777,607 $ 698,986
=====================================================================================================================
See notes to consolidated financial statements.
22
Consolidated Balance Sheet
- --------------------------------------------------------------------------------------------------------------------
(Thousands of Dollars)
------------------------------
As of December 31,
------------------------------
1997 1996
- ---------------------------------------------------------------------------------------------------------------------
ASSETS
Current Assets:
Cash and temporary cash investments $ 356,412 $ 410,978
- ---------------------------------------------------------------------------------------------------------------------
Receivables:
Electric customer accounts receivable 90,149 92,475
Other utility receivables 23,106 22,402
Other receivables 33,472 33,936
Less: Allowance for uncollectible accounts (15,016) (18,688)
- ---------------------------------------------------------------------------------------------------------------------
Total Receivables--Net 131,711 130,125
- ---------------------------------------------------------------------------------------------------------------------
Materials and supplies (at average cost):
Coal 20,418 19,097
Operating and construction 53,088 52,669
- ---------------------------------------------------------------------------------------------------------------------
Total Materials and Supplies 73,506 71,766
- ---------------------------------------------------------------------------------------------------------------------
Other current assets 7,727 9,359
- ---------------------------------------------------------------------------------------------------------------------
Total Current Assets 569,356 622,228
- ---------------------------------------------------------------------------------------------------------------------
Long-Term Investments:
Leveraged leases 349,129 134,133
Affordable housing 137,860 150,270
Gas reserves 92,645 79,916
Other leases 69,329 85,893
Other 73,823 68,477
- ---------------------------------------------------------------------------------------------------------------------
Total Long-Term Investments 722,786 518,689
- ---------------------------------------------------------------------------------------------------------------------
Property, Plant and Equipment:
Electric plant in service 4,335,149 4,275,110
Construction work in progress 56,471 45,059
Property held under capital leases 113,662 99,608
Property held for future use 3,980 190,821
Other 115,866 176,872
- ---------------------------------------------------------------------------------------------------------------------
Gross property, plant and equipment 4,625,128 4,787,470
Less: Accumulated depreciation and amortization (1,962,794) (1,969,945)
- ---------------------------------------------------------------------------------------------------------------------
Total Property, Plant and Equipment--Net 2,662,334 2,817,525
- ---------------------------------------------------------------------------------------------------------------------
Other Non-Current Assets:
Regulatory assets 680,885 636,816
Other 59,041 43,734
- ---------------------------------------------------------------------------------------------------------------------
Total Other Non-Current Assets 739,926 680,550
- ---------------------------------------------------------------------------------------------------------------------
Total Assets $ 4,694,402 $ 4,638,992
=====================================================================================================================
See notes to consolidated financial statements.
23
- --------------------------------------------------------------------------------------------------------------------
(Thousands of Dollars)
------------------------------
As of December 31,
------------------------------
1997 1996
- ---------------------------------------------------------------------------------------------------------------------
LIABILITIES AND CAPITALIZATION
Current Liabilities:
Notes payable $ -- $ 749
Current maturities and sinking fund requirements 97,844 72,831
Accounts payable 85,085 96,230
Accrued liabilities 54,386 58,044
Dividends declared 30,312 28,633
Other 14,339 4,075
- ---------------------------------------------------------------------------------------------------------------------
Total Current Liabilities 281,966 260,562
- ---------------------------------------------------------------------------------------------------------------------
Non-Current Liabilities:
Deferred income taxes--net 693,215 759,089
Deferred income 225,107 189,293
Deferred investment tax credits 97,782 106,201
Capital lease obligations 37,540 28,407
Other 255,467 240,763
- ---------------------------------------------------------------------------------------------------------------------
Total Non-Current Liabilities 1,309,111 1,323,753
- ---------------------------------------------------------------------------------------------------------------------
- ---------------------------------------------------------------------------------------------------------------------
Commitments and Contingencies (Notes B through M)
- ---------------------------------------------------------------------------------------------------------------------
Capitalization:
Long-Term Debt 1,376,121 1,439,746
- ---------------------------------------------------------------------------------------------------------------------
Preferred and Preference Stock of Subsidiaries:
Non-redeemable preferred stock 216,156 213,608
Non-redeemable preference stock 28,295 28,997
- ---------------------------------------------------------------------------------------------------------------------
Total preferred and preference stock before deferred employee
stock ownership plan (ESOP) benefit 244,451 242,605
- ---------------------------------------------------------------------------------------------------------------------
Deferred ESOP benefit (16,400) (19,533)
- ---------------------------------------------------------------------------------------------------------------------
Total Preferred and Preference Stock of Subsidiaries 228,051 223,072
- ---------------------------------------------------------------------------------------------------------------------
Common Shareholders' Equity:
Common stock--no par value (authorized--187,500,000
shares; issued--109,679,154 shares) 1,001,225 990,502
Retained earnings 869,749 777,607
Treasury stock (at cost) (31,998,723 and 32,406,135 shares) (371,821) (376,250)
- ---------------------------------------------------------------------------------------------------------------------
Total Common Shareholders' Equity 1,499,153 1,391,859
- ---------------------------------------------------------------------------------------------------------------------
Total Capitalization 3,103,325 3,054,677
- ---------------------------------------------------------------------------------------------------------------------
Total Liabilities and Capitalization $ 4,694,402 $ 4,638,992
=====================================================================================================================
See notes to consolidated financial statements.
24
Statement of Consolidated Cash Flows
- -----------------------------------------------------------------------------------------------------------
(Thousands of Dollars)
------------------------------------------------
Year Ended December 31,
------------------------------------------------
1997 1996 1995
- -----------------------------------------------------------------------------------------------------------
CASH FLOWS FROM OPERATING ACTIVITIES
Net income $ 199,101 $ 179,138 $ 170,563
Principal non-cash charges (credits) to net income:
Depreciation and amortization 242,843 222,928 202,558
Capital lease, nuclear fuel and investment amortization 67,671 53,166 38,847
Deferred income taxes and investment tax credits--net 60,811 (43,170) (10,921)
Gain on disposition of investments (34,364) (5,119) (9,129)
Investment income (66,246) (57,429) (31,054)
Changes in working capital other than cash (37,229) 2,915 34,875
(Increase) decrease in ECR (25,318) (3,948) 11,652
Other (40,038) 34,445 48,731
- ------------------------------------------------------------------------------------------------------------
Net Cash Provided from Operating Activities 367,231 382,926 456,122
- ------------------------------------------------------------------------------------------------------------
CASH FLOWS FROM INVESTING ACTIVITIES
Long-term investments (219,122) (77,147) (191,719)
Capital expenditures (118,338) (101,150) (94,164)
Proceeds from disposition of investments 86,300 18,100 1,929
Sale of generating station -- 169,100 --
Payment for purchase of GSF Energy, net of cash acquired -- (24,234) --
Other (4,938) (1,898) (3,854)
- ------------------------------------------------------------------------------------------------------------
Net Cash Used in Investing Activities (256,098) (17,229) (287,808)
- ------------------------------------------------------------------------------------------------------------
CASH FLOWS FROM FINANCING ACTIVITIES
Dividends on common stock (106,959) (100,517) (93,649)
Reductions of long-term obligations:
Long-term debt (52,100) (50,812) (56,114)
Capital leases (13,551) (19,326) (26,373)
Preferred and preference stock -- -- (29,732)
Repurchase of common stock (30) (11,717) (21,271)
Issuance of preferred stock -- 150,000 --
Issuance of long-term debt -- 85,000 65,000
Decrease in notes payable -- (28,637) (20,236)
Other 6,941 (3,477) (11,230)
- ------------------------------------------------------------------------------------------------------------
Net Cash (Used in) Provided from Financing Activities (165,699) 20,514 (193,605)
- ------------------------------------------------------------------------------------------------------------
Net (decrease) increase in cash and temporary cash
investments (54,566) 386,211 (25,291)
Cash and temporary cash investments at beginning of year 410,978 24,767 50,058
- ------------------------------------------------------------------------------------------------------------
Cash and temporary cash investments at end of year $ 356,412 $ 410,978 $ 24,767
============================================================================================================
Supplemental Cash Flow Information
- ------------------------------------------------------------------------------------------------------------
CASH PAID DURING THE YEAR
Interest (net of amount capitalized) $ 95,413 $ 95,702 $ 99,954
- ------------------------------------------------------------------------------------------------------------
Income taxes $ 66,703 $ 91,641 $ 82,884
- ------------------------------------------------------------------------------------------------------------
NON-CASH INVESTING
AND FINANCING ACTIVITIES
Capital lease obligations recorded $ 27,514 $ 13,050 $ 14,961
Equity funding obligations recorded $ 5,441 $ 36,716 $ 21,827
Equity funding obligations cancelled $ 9,107 $ -- $ --
Preferred stock issued in conjunction with long-term
investments $ 2,548 $ -- $ 3,000
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.
=============================================================================================================
See notes to consolidated financial statements.
25
Notes to Consolidated Financial Statements
A. Summary of Significant Accounting Policies
Consolidation and Proposed Merger
DQE, Inc. (DQE) is an energy services holding company. Its subsidiaries are
Duquesne Light Company (Duquesne); Duquesne Enterprises, Inc. (DE); DQE Energy
Services, Inc. (DES); DQEnergy Partners, Inc. (DQEnergy); and Montauk, Inc.
(Montauk). DQE and its subsidiaries are collectively referred to as "the
Company."
Duquesne is an electric utility engaged in the generation, transmission,
distribution and sale of electric energy and is the largest of DQE's
subsidiaries. DE makes strategic investments beneficial to DQE's core energy
business. These investments are intended to enhance DQE's capabilities as an
energy provider, increase asset utilization, and act as a hedge against changing
business conditions. DES is a diversified energy services company offering a
wide range of energy solutions for industrial, utility and consumer markets
worldwide. DES initiatives include energy facility development and operation,
domestic and international independent power production, and the production and
supply of innovative fuels. DQEnergy was formed to align DQE with strategic
partners to capitalize on opportunities in the energy services industry. These
alliances are intended to enhance the utilization and value of DQE's strategic
investments and capabilities while establishing DQE as a total energy provider.
Montauk is a financial services company that makes long-term investments and
provides financing for the Company's other market-driven businesses and their
customers.
All material intercompany balances and transactions have been eliminated in
the preparation of the consolidated financial statements.
On August 7, 1997, the shareholders of the Company and Allegheny Energy, Inc.
(AYE), approved a proposed tax-free, stock-for-stock merger. Upon consummation
of the merger, DQE will be a wholly owned subsidiary of AYE. Immediately
following the merger, Duquesne, DE, DES, DQEnergy and Montauk will remain wholly
owned subsidiaries of DQE. The transaction is intended to be accounted for as a
pooling of interests. Under the pooling of interests method of accounting for a
business combination, the recorded assets, liabilities and equity of each of the
combining companies are carried forward to the combined corporation at their
recorded amounts. Accordingly, no goodwill, including the related future
earnings impact of goodwill amortization, results from a transaction accounted
for as a pooling of interests. In order to qualify for pooling treatment, many
requirements must be met by each of the combining companies for a period of time
before and after the combination occurs. Examples of the requirements prior to
the merger include limitations on: dividends paid on common stock, stock
repurchases, stock compensation plan activity and sales of significant assets.
Management has focused and will continue to focus on meeting the pooling
requirements as they relate to the Company prior to the merger.
Under the terms of the transaction, the Company's shareholders will receive
1.12 shares of AYE common stock for each share of the Company's common stock and
AYE's dividend in effect at the time of the closing of the merger. The
transaction is expected to close in mid-1998, subject to approval of applicable
regulatory agencies, including the public utility commissions in Pennsylvania
and Maryland, the Securities and Exchange Commission (SEC), the Federal Energy
Regulatory Commission (FERC) and the Nuclear Regulatory Commission (NRC).
In September 1997, the City of Pittsburgh filed a federal antitrust suit
seeking to prevent the merger and asking for monetary damages. Although the
United States District Court for the District of Western Pennsylvania dismissed
the suit in January 1998, the City of Pittsburgh filed an appeal and asked for
expedited review. The Company anticipates a decision on whether the appeal has
been granted by late March 1998. Unless otherwise indicated, all information
presented in this Annual Report relates to the Company only and does not take
into account the proposed merger between the Company and AYE.
Basis of Accounting
The Company is subject to the accounting and reporting requirements of the
SEC. In addition, the Company's electric utility operations are subject to
regulation by the Pennsylvania Public Utility Commission (PUC), including
regulation under the Pennsylvania Electricity Generation Customer Choice and
Competition Act (Customer Choice Act), and the FERC under the Federal Power Act
with respect to rates for interstate sales, transmission of electric power,
accounting and other matters.
The Company's consolidated financial statements report regulatory assets and
liabilities in accordance with Statement of Financial Accounting Standards
(SFAS) No. 71, Accounting for the Effects of Certain Types of Regulation (SFAS
No. 71), and reflect the effects of the current ratemaking process. In
accordance with SFAS No. 71, the Company's consolidated financial statements
reflect regulatory assets and liabilities consistent with cost-based, pre-
competition ratemaking regulations. (See "Rate Matters," Note E, on page 31.)
26
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.
Revenues from Sales of Electricity
The Company's electric utility operations provide service to customers in
Allegheny County, including the City of Pittsburgh; Beaver County; and
Westmoreland County. (See "Rate Matters," Note E, on page 31.) This territory
represents approximately 800 square miles in southwestern Pennsylvania, located
within a 500-mile radius of one-half of the population of the United States and
Canada. 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.
Meters are read monthly and electric utility customers are billed on the same
basis. Revenues are recorded in the accounting periods for which they are
billed, with the exception of energy cost recovery revenues. (See "Energy Cost
Rate Adjustment Clause (ECR)" discussion below.)
Energy Cost Rate Adjustment Clause (ECR)
Through the ECR, the Company recovers (to the extent that such amounts are not
included in base rates) nuclear fuel, fossil fuel and purchased power expenses
and, also through the ECR, passes to its customers the profits from short-term
power sales to other utilities (collectively, ECR energy costs). Under the
Company's mitigation plan approved by the PUC in June 1996, the level of energy
cost recovery is capped at 1.47 cents per kilowatt-hour (KWH) through May 2001.
The rate currently being recovered is 1.28 cents per KWH, based upon estimated
1996 costs. To the extent that current fuel and purchased power costs, in
combination with previously deferred fuel and purchased power costs, are not
projected to be recoverable through this pricing mechanism, these costs would
become transition costs subject to recovery through a competitive transition
charge (CTC). (See "Rate Matters," Note E, on page 31.) Nuclear fuel expense is
recorded on the basis of the quantity of electric energy generated and includes
such costs as the fee imposed by the United States Department of Energy (DOE)
for future disposal and ultimate storage and disposition of spent nuclear fuel.
Fossil fuel expense includes the costs of coal, natural gas and fuel oil used in
the generation of electricity.
On the Company's statement of consolidated income, these ECR revenues are
included as a component of operating revenues. For ECR purposes, the Company
defers fuel and other energy expenses for recovery, or refunding, in subsequent
years. The deferrals reflect the difference between the amount that the Company
is currently collecting from customers and its actual ECR energy costs. The PUC
annually reviews the Company's ECR energy costs for the fiscal year April
through March, compares them to previously projected ECR energy costs, and
adjusts the ECR for over- or under-recoveries and for two PUC-established coal
cost standards. This adjustment was not made during 1997, despite a projected
increase of 0.13 cents per KWH, pending the outcome of the Company's
Restructuring Plan or Stand-Alone Plan (as defined in "Rate Matters," Note E, on
page 31).
Over- or under-recoveries from customers have been recorded in the
consolidated balance sheet as payable to, or receivable from, customers. Based
on Duquesne's Restructuring Plan and Stand-Alone Plan, the 1997 under-recoveries
were reclassified as a regulatory asset and may be recovered through a CTC. At
December 31, 1997, $23.5 million was receivable from customers. At December 31,
1996, $1.8 million was payable to customers and shown as other current
liabilities.
Maintenance
Incremental maintenance costs incurred for refueling outages at the Company's
nuclear units are deferred for amortization over the period between refueling
outages (generally 18 months). The Company accrues, 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 are charged to expense as such costs are incurred.
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. Amortization of other intangibles is recorded on a
straight-line basis over a five-year period. Amortization of
27
interests in 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.
In 1987, the Company sold its 13.74 percent interest in Beaver Valley Unit 2
and leased it back. The lease is accounted for as an operating lease. In May
1997, the Company accelerated the recognition of expense related to the lease.
The accelerated expense recognition accounted for $16.1 million of total
amortization expense for 1997. Due to the above-market price of the lease, the
Company has proposed in its Restructuring Plan and Stand-Alone Plan (as defined
in "Rate Matters," Note E, on page 31) to recover the remaining above-market
lease costs through a CTC.
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 I, on page 37.)
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.
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 electric utility operations, 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 E on page 31, and "Income
Taxes," Note G, on page 35.)
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 electric utility property generally are deferred. Such
credits are subsequently reflected, over the lives of the related assets, as
reductions to income tax expense.
Other Operating Revenues and Other Income
Other operating revenues include the Company's non-KWH utility revenues and
revenues from market-based operating activities. Other income primarily is made
up of income from long-term investments entered into by the market-driven
businesses. 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 electric utility properties are stated at
original construction cost, which includes related payroll taxes, pensions and
other fringe benefits, as well as administrative and general 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 electric utility
properties that are retired (plus removal costs and less any salvage value) are
charged to accumulated depreciation and amortization.
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.
28
Earnings Per Share
SFAS No. 128, Earnings Per Share (SFAS No. 128), establishes standards for
computing and presenting earnings per share and makes the standards comparable
to international earnings per share standards. It replaces the presentation of
primary earnings per share, as found in Accounting Principles Board (APB)
Opinion No. 15, Earnings per Share, with a presentation of basic earnings per
share. It also requires dual presentation of basic and diluted earnings per
share on the statement of consolidated income for all entities with complex
capital structures. 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
statement is effective for financial statements issued for periods ending after
December 15, 1997.
The preference stock of the ESOP, as described in Note M, "Employee Benefits,"
was the primary cause for the dilution of earnings per share for the years ended
December 31, 1997, 1996 and 1995 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 for the three years presented was a $0.03 dilutive effect in each year.
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 1996 and 1995 consolidated financial statements have been reclassified to
conform with accounting presentations adopted during 1997.
Recent Accounting Pronouncements
SFAS No. 130, Reporting Comprehensive Income (SFAS No. 130) and SFAS No. 131,
Disclosures about Segments of an Enterprise and Related Information (SFAS No.
131), have been issued and are effective for fiscal years beginning after
December 15, 1997. SFAS No. 130 defines comprehensive income and outlines
certain reporting and disclosure requirements related to comprehensive income.
SFAS No. 131 requires certain disclosures about business segments of an
enterprise, if applicable. The adoption of SFAS No. 130 and SFAS No. 131 is not
expected to have a significant impact on the Company's financial statements or
disclosures.
B. Changes in Working Capital Other than Cash
Changes in Working Capital Other than Cash
(Net of 1997 Chester Disposition and 1996 GSF Energy Acquisition)
- -----------------------------------------------------------------------------------------------------
1997 1996 1995
(Amounts in Thousands of Dollars)
- -----------------------------------------------------------------------------------------------------
Receivables $(14,947) $(1,946) $ 34,341
Materials and supplies (1,740) 1,286 9,994
Other current assets (519) (948) 3,126
Accounts payable (4,993) 4,691 7,087
Other current liabilities (15,030) (168) (19,673)
- -----------------------------------------------------------------------------------------------------
Total $(37,229) $ 2,915 $ 34,875
=====================================================================================================
C. Property, Plant and Equipment
In addition to its wholly owned generating units, the Company, together with
FirstEnergy Corporation, 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.
29
Generating Units at December 31, 1997
- ---------------------------------------------------------------------------------------
Generating Net Utility Fuel
Unit Capability Plant Source
(Megawatts) (Millions of Dollars)
- ---------------------------------------------------------------------------------------
Cheswick 570 $ 120.4 Coal
Elrama (a) 487 96.5 Coal
Eastlake Unit 5 186 35.6 Coal
Sammis Unit 7 187 46.7 Coal
Bruce Mansfield Unit 1 (a) 228 62.5 Coal
Bruce Mansfield Unit 2 (a) 62 18.2 Coal
Bruce Mansfield Unit 3 (a) 110 47.9 Coal
Beaver Valley Unit 1 (b) 385 195.9 Nuclear
Beaver Valley Unit 2 (c)(d) 113 14.0 Nuclear
Beaver Valley Common Facilities 149.5
Perry Unit 1 (e) 164 387.1 Nuclear
Brunot Island Units 2a and 2b 178 21.9 Fuel Oil
- ---------------------------------------------------------------------------------------
Total Generating Units 2,670 $1,196.2
=======================================================================================
(a) The unit is 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. The lease is accounted for as an operating lease.
Amounts shown represent facilities not sold and subsequent leasehold
improvements.
(d) The NRC has granted a license to operate through May 2027.
(e) The NRC has granted a license to operate through March 2026.
D. Long-Term Investments
The Company makes equity investments in affordable housing and gas reserve
partnerships as a limited partner. At December 31, 1997, the Company had
investments in 27 affordable housing funds and eight gas reserve partnerships.
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 estimated to be
approximately 2 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
$950 million and $553 million at December 31, 1997 and 1996.
Net Leveraged Lease Investments at December 31
- -----------------------------------------------------------------------------------------
1997 1996
(Amounts in Thousands of Dollars)
- -----------------------------------------------------------------------------------------
Rentals receivable (net of non-recourse debt) $ 638,030 $ 215,358
Estimated residual value of leased assets 22,029 22,029
Less: Unearned income (310,930) (103,254)
- -----------------------------------------------------------------------------------------
Leveraged lease investments 349,129 134,133
Less: Deferred taxes arising from leveraged leases (115,383) (59,781)
- -----------------------------------------------------------------------------------------
Net Leveraged Lease Investments $ 233,746 $ 74,352
=========================================================================================
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. 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 $8.1 million ($4.7
million net of tax) at December 31, 1997. The amount of unrealized holding
losses related to marketable securities was $4.4 million ($2.6 million net of
tax) at December 31, 1996. 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.
30
In 1997, the Company acquired 100 percent of the Class A Stock of AquaSource,
Inc. (AquaSource), which was formed to acquire small and mid-sized water,
wastewater and water services companies, with its initial focus in Texas. 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 K, on page 41.) At
December 31, 1997, the Company had invested approximately $7 million (of which
approximately $1.5 million was in the form of DQE Preferred Stock) to acquire
the stock or assets of seven water, wastewater and water services companies. In
February 1998, the Company issued 159,732 shares of DQE Preferred Stock,
representing an investment of approximately $16 million in a water company. The
Company has committed approximately $24 million for additional investments in
water, wastewater and water services companies for the first quarter of 1998.
E. 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 have assets recorded on their
balance sheets at above-market costs, thus creating transition or stranded
costs.
In Pennsylvania, the Customer Choice Act went into effect 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, delivery of the
electricity from the generation supplier to the customer will remain the
responsibility of the existing franchised utility. The Customer Choice Act also
provides that the existing franchised utility may recover, through a CTC, an
amount of transition or stranded 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 (running through 1998) and a phase-in to competition period
(beginning in 1999). For the first stage, the Company filed a pilot program with
the PUC on February 27, 1997. For the second stage, the Company filed on August
1, 1997 its restructuring and merger plan (the Restructuring Plan) and its
stand-alone restructuring plan (the Stand-Alone Plan) with the PUC. (See the
detailed discussion of these plans on pages 32 and 33.)
Customer Choice Pilots
The pilot period gives utilities an opportunity to examine a wide range of
technical and administrative details related to competitive markets, including
metering, billing, and cost and design of unbundled electric services. The
Company pilot filing proposed unbundling transmission, distribution, generation
and competitive transition charges and offered participating customers the same
options that were to be available in a competitive generation market. The pilot
was designed to comprise approximately 5 percent of the Company's residential,
commercial and industrial demand. The 28,000 customers participating in the
pilot may choose unbundled service, with their electricity provided by an
alternative generation supplier, and will be subject to unbundled distribution
and CTC charges approved by the PUC and unbundled transmission charges pursuant
to the Company's FERC-approved tariff. On May 9, 1997, the PUC issued a
Preliminary Opinion and Order approving the Company's filing in part, and
requiring certain revisions. The Company and other utilities objected to several
features of the PUC's Preliminary Opinion and Order. Hearings on several key
issues were held in July. The PUC issued its final order on August 29, 1997,
approving a revised pilot program for the Company. On September 8, 1997, the
Company appealed the determination of the market price of generation set forth
in this order to the Commonwealth Court of Pennsylvania. The Company expects a
hearing to be scheduled for mid-1998. Although this appeal is pending, the
Company complied with the PUC's order to implement the pilot program that began
on November 3, 1997.
Phase-In to Competition
The phase-in to competition begins on January 1, 1999, when 33 percent of
customers will have customer choice (including customers covered by the pilot
program); 66 percent of customers will have customer choice no later than
January 1, 2000; and all customers will have customer choice
31
no later than January 1, 2001. However, in its sole order to date (the PECO
Order), the PUC ordered the phase-in provisions of the Customer Choice Act to
require the acceleration of the second and third phases to January 2, 1999 and
January 2, 2000, respectively. As they are phased-in, customers that have chosen
an electricity generation supplier other than the Company will pay that supplier
for generation charges, and will pay the Company a CTC (discussed below) and
unbundled charges for transmission and distribution. Customers that continue to
buy their generation from the Company will pay for their service at current
regulated tariff rates divided into unbundled generation, transmission and
distribution charges. The PECO Order concluded that under the Customer Choice
Act, an electric distribution company, such as Duquesne, is to remain a
regulated utility and may only offer PUC-approved, tariffed rates (including
unbundled generation rates). Delivery of electricity (including transmission,
distribution and customer service) will continue to be regulated in
substantially the same manner as under current regulation.
Rate Cap and Transition Cost Recovery
Before the phase-in to customer choice begins in 1999, the PUC expects
utilities to take vigorous steps to mitigate transition costs as much as
possible without increasing the rates they currently charge customers. The
Company has mitigated in excess of $350 million of transition costs during the
past three years through accelerated annual depreciation and a one-time write-
down of nuclear generating station costs, accelerated recognition of nuclear
lease costs, increased nuclear decommissioning funding, and amortization of
various regulatory assets. This relative level of transition cost reduction,
while holding rates constant, is unmatched within Pennsylvania.
The PUC will determine what portion of a utility's transition or stranded
costs that remain at January 1, 1999 will be recoverable through a CTC from
customers. The CTC recovery period could last through 2005, providing a utility
a total of up to nine years beginning January 1, 1997 to recover transition
costs, unless this period is extended as part of a utility's PUC-approved
transition plan. An overall four-and-one-half-year rate cap from January 1, 1997
will be imposed on the transmission and distribution charges of electric utility
companies. Additionally, electric utility companies may not increase the
generation price component of rates as long as transition costs are being
recovered, with certain exceptions. The Company has requested recovery of
transition costs of approximately $2 billion, net of deferred taxes, beginning
January 1, 1999. Of this amount, $0.5 billion represents regulatory assets and
$1.5 billion represents potentially uneconomic plant and plant decommissioning
costs. Any estimate of the ultimate level of transition costs for the Company
depends on, among other things, the extent to which such costs are deemed
recoverable by the PUC, the ongoing level of the cost of Duquesne's operations,
regional and national economic conditions, and growth of the Company's sales.
(See Item 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS "Financial Exposure to Transition Cost Recovery"
discussion on page 18; see also "Regulatory Assets and Emerging Issues Task
Force" discussion on page 34).
Timetable for Restructuring Plan and Stand-Alone Plan Approval
On August 1, 1997, the Company filed the Restructuring Plan and the Stand-
Alone Plan with the PUC. Although the provisions of the Customer Choice Act
require a PUC decision nine months from the filing date (which would be April
30, 1998), the Pennsylvania Attorney General's Office requested an extension in
order to conduct an investigation into certain competition issues relating to
the Restructuring Plan. Pursuant to an arrangement among the Company, the PUC
and the Attorney General, the Company anticipates a decision by the PUC (with
respect to the Restructuring Plan if the merger is approved, or with respect to
the Stand-Alone Plan if the merger is not approved) on or before May 29, 1998 or
such later date as the parties may agree.
Stand-Alone Plan
In the event the merger with AYE is not consummated under the filed
Restructuring Plan, the Company has sought approval for restructuring and
recovery of its own transition costs through a CTC under the Stand-Alone Plan.
The Company proposed that any finding of market value for the Company's
generating assets should be based on market evidence and not on an
administrative determination of that value based on price forecasts (the PECO
Order determined the market value of PECO Energy Company's generation based on
the price forecast sponsored by the Pennsylvania Office of Consumer Advocate).
In addition, the Company proposed that such a final market valuation be
conducted in 2003, and that an annual competitive market solicitation be used to
set the CTC in the interim. The 2003 final market valuation would be performed
by an independent panel of experts using the best available market evidence at
that time. The Stand-Alone Plan filing also provided for certain triggers that
would accelerate the date of this final market valuation. Prior to the
32
final valuation, the Company would sell a substantial amount of power to the
highest bidder in an annual competitive solicitation. The annual market price
established by the solicitation would be used to set competitive generation
credits and determine the CTC as a residual from the generation rate cap under
the Rate Cap Provision. (See Item 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS "Financial Impact of Pilot Program
Order" discussion on page 17.) During the transition period, the Company
committed to accelerate amortization and depreciation of its generation-related
assets and cap its return on equity through a return on equity spillover
mechanism, in exchange for being allowed to charge existing rates under the Rate
Cap Provision. The Company committed to a minimum of $1.7 billion of
amortization and depreciation of generation-related assets by the end of 2005.
Under the proposed return on equity spillover mechanism, additional amortization
and depreciation in excess of this minimum $1.7 billion commitment would be
recorded in order to comply with the return on equity cap. The generation rate
cap would apply to the sum of the CTC and the competitive generation credit
determined in the annual competitive solicitation. The Stand-Alone Plan also
proposed to redesign individual tariffs to encourage more efficient consumption
and further mitigate transition costs during the transition period. Consistent
with the Company's long-standing commitment to economic development, the rate
redesign provides for a significant reduction in the cost of electricity for
incremental consumption. Application of the rate redesign to the CTC would also
have the potential to maximize mitigation of transition costs during the
transition period.
As an alternative to a market-based valuation in 2003, if the PUC finds that a
determination of market value as of December 31, 1998 is required by the
Customer Choice Act, then the Company has agreed that the PUC may order an
immediate auction of the Company's generation at that time.
Restructuring Plan
The Restructuring Plan incorporates the benefits of the merger with AYE, such
as anticipated savings to the Company, on a nominal basis, of $365 million in
generation-related costs over 20 years, and $9 million in transmission-related
costs and $173 million in distribution-related costs over 10 years. The Company
plans to use the generation-related portion of its share of net operating
synergy savings to shorten the transition cost recovery period. The
Restructuring Plan also incorporates the market-based approach to determining
transition costs proposed by the Company in its Stand-Alone Plan. The 2003 final
market valuation will be performed by an independent panel of experts using the
best available market evidence at that time, including a potential sale of a
portion of the combined company's generating assets. Certain triggers will
accelerate the date of this final market valuation if market prices rise
significantly or the minimum amortization commitment is satisfied prior to 2003.
The annual market price established by the Company's solicitation would be used
to set competitive generation credits and to determine the CTC as a residual
from the generation rate cap under the Rate Cap Provision. The Company's minimum
amortization commitment of $1.7 billion in the proposed Stand-Alone Plan has
been increased under the Restructuring Plan. As in the Stand-Alone Plan, the
determination of transition costs in 2003 will compare the book value of
generating assets in 2005 (after netting the increased minimum commitment to
depreciation and amortization and any return on equity spillover) with the
market value of the generating assets in 2005. The opposing parties believe that
there should be a one-time valuation of the generating assets performed at
January 1, 1999. Any merger-related synergies relating to generation would then
be used to reduce the Company's transition costs as of that date. These parties
also believe that the Company's proposed distribution rate decrease should be
effective January 1, 1999, as well.
Additional Restructuring Plan Commitments
The Restructuring Plan also contains a number of commitments by the
merged DQE/AYE entity. First, the merged entity will open up its transmission
system to all parties on a reciprocal non-discriminatory basis and eliminate
multiple rate charges across the combined transmission system. Second, the
merged entity will join a recently proposed Midwest Independent System Operator
(ISO) or other then-existing ISO, or form its own ISO if no existing ISO offers
acceptable rules, including marginal cost transmission rates. Several utilities
have applications pending before the FERC to form ISOs. Third, the merged entity
has committed to make a report, 18 months after consummation of the merger, to
the PUC regarding its progress on the ISO commitment. The PUC may, at its
option, require the merged entity to relinquish control of 300 MW of generating
capacity to alleviate concerns over market power. The form of relinquishment
would be at the option of the merged entity; possible forms of relinquishment
include an energy swap, entering a power sale contract, divestiture of
generating assets and a bidding trust.
33
The Federal Filings
In addition to the PUC filings of the Restructuring Plan and the Stand-Alone
Plan, on August 1, 1997, the Company and AYE filed their joint merger
application with the FERC (the FERC Filing). Pursuant to the FERC Filing, the
Company and AYE have committed to forming or joining an ISO that meets the
entity's requirements, including marginal cost transmission pricing, following
the merger. In addition, the Company and AYE have stated in the FERC Filing that
following the merger the combined entity's market share will not violate the
market power conditions and requirements set by the FERC. On January 20, 1998,
the Company and AYE filed merger applications with the Antitrust Division of the
Department of Justice and the Federal Trade Commission. These applications are
currently pending.
Regulatory Assets and Emerging Issues Task Force
As a result of the application of SFAS No. 71, the Company records regulatory
assets on its consolidated balance sheet. 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.
A company's electric utility operations, or a portion of such operations,
could cease to meet the SFAS No. 71 criteria for various reasons, including a
change in the FERC regulations or the competition-related changes in the PUC
regulations. (See "Competition and the Customer Choice Act," on page 31.) The
Emerging Issues Task Force of the Financial Accounting Standards Board (EITF)
has determined that once a transition plan has been approved, application of
SFAS No. 71 to the generation portion of a utility must be discontinued and
replaced by the application of SFAS No. 101, Regulated Enterprises - Accounting
for the Discontinuation of Application of FASB Statement No. 71 (SFAS No. 101).
The consensus reached by the EITF provides further guidance that the regulatory
assets and liabilities of the generation portion of a utility to which SFAS No.
101 is being applied should be 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. Under the Customer Choice Act, the Company believes
that its generation-related regulatory assets will be recovered through a CTC
collected in connection with providing transmission and distribution services,
and the Company will continue to apply SFAS No. 71. Fixed assets related to the
generation portion of a utility will be evaluated including the cash flows
provided by the CTC, in accordance with SFAS No. 121, Accounting for the
Impairment of Long-Lived Assets and for Long-Lived Assets to Be Disposed Of
(SFAS No. 121). The Company believes that all of its regulatory assets continue
to satisfy the SFAS No. 71 criteria in light of the transition to competitive
generation under the Customer Choice Act and the ability to recover these
regulatory assets through a CTC. Once any portion of the Company's electric
utility operations is deemed to no longer meet the SFAS No. 71 criteria, or is
not recovered through a CTC, the Company will be required to write off assets
(to the extent their net book value exceeds fair value), the recovery of which
is uncertain, and any regulatory assets or liabilities for those operations that
no longer meet these requirements. Any such write-off of assets could be
materially adverse to the financial position, results of operations and cash
flows of the Company.
The Company's regulatory assets related to generation, transmission and
distribution as of December 31, 1997 were $561.9 million, $33.2 million and
$85.8 million, respectively. At December 31, 1996, the Company's regulatory
assets related to generation, transmission and distribution were $492.6 million,
$41.4 million and $102.8 million, respectively. The components of all regulatory
assets for the periods presented are as follows:
34
Regulatory Assets at December 31
- --------------------------------------------------------------------------------
- -------------------------------------------------------------------------------------------------
1997 1996
(Amounts in Thousands of Dollars)
- -------------------------------------------------------------------------------------------------
Regulatory tax receivable (Note A) $301,664 $394,131
Brunot Island and Phillips cold reserve units (a) 105,693 --
Unamortized debt costs (b) 87,915 93,299
Deferred rate synchronization costs (c) 37,231 41,446
Beaver Valley Unit 2 sale/leaseback premium (Note H) 28,554 30,059
Deferred employee costs (d) 25,130 29,589
Deferred energy costs (Note A) 23,514 --
Deferred nuclear maintenance outage costs (Note A) 17,013 13,462
Deferred coal costs (e) 15,711 12,191
DOE decontamination and decommissioning receivable (Note I) 8,847 9,779
Other (f) 29,613 12,860
- --------------------------------------------------------------------------------------------
Total Regulatory Assets $680,885 $636,816
============================================================================================
(a) Through its analysis of customer choice in the Restructuring Plan and Stand-
Alone Plan, the Company determined that Phillips and a portion of Brunot
Island would not be cost-effective in the production of electricity in the
face of a competitive marketplace.
(b) The premiums paid to reacquire debt prior to scheduled maturity dates are
deferred for amortization over the life of the debt issued to finance the
reacquisitions.
(c) Initial operating costs of Beaver Valley Unit 2 and Perry Unit 1 were
deferred and are currently being recovered over a 10-year period.
(d) Includes amounts for recovery of accrued compensated absences and accrued
claims for workers' compensation.
(e) The PUC has directed the Company to defer recovery of the delivered cost of
coal to the extent that such cost exceeds generally prevailing market prices
for similar coal, as determined by the PUC.
(f) 1997 amounts include $6.8 million related to Statement of Position 96-1,
Environmental Remediation Liabilities for the ongoing monitoring of certain
of the Company's sites and $6.8 million of one-time costs for the 1997 early
retirement plan recorded in accordance with SFAS No. 88, Employers'
Accounting for Settlements and Curtailments of Defined Benefit Pension Plans
and for Termination Benefits and SFAS No. 106, Employers' Accounting for
Postretirement Benefits Other Than Pensions. (See "Employee Benefits," Note
M, on page 43.)
F. Short-Term Borrowing and Revolving Credit Arrangements
At December 31, 1997, the Company had two extendible revolving credit
arrangements, including a $125 million facility expiring in June 1998 and a $150
million facility expiring in October 1998. 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, 1997 and December 31, 1996, there were no short-
term borrowings outstanding.
G. 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 Company's 1993 and 1994 returns, and the tax years 1995 and 1996
remain subject to IRS review. The Company does not believe that final settlement
of the federal income tax returns for the years 1990 through 1996 will have a
materially adverse effect on its financial position, results of operations or
cash flows.
Deferred Tax Assets (Liabilities) at December 31
- --------------------------------------------------------------------------------
1997 1996
(Amounts in Thousands of Dollars)
- -----------------------------------------------------------------------------------------
Tax benefit--long-term investments $ 210,394 $ 175,427
Gain on sale/leaseback of BV Unit 2 58,137 61,131
Investment tax credits unamortized 40,573 44,067
Unbilled revenue 19,637 19,222
Other 65,210 50,648
- -----------------------------------------------------------------------------------------
Deferred tax assets 393,951 350,495
- -----------------------------------------------------------------------------------------
Property depreciation (712,247) (783,851)
Regulatory assets (125,171) (150,346)
Leveraged leases (115,383) (59,781)
Loss on reacquired debt unamortized (31,360) (33,331)
Deferred coal and energy costs (15,910) (5,054)
Other (87,095) (77,221)
- -----------------------------------------------------------------------------------------
Deferred tax liabilities (1,087,166) (1,109,584)
- -----------------------------------------------------------------------------------------
Net Deferred Tax Liabilities $ (693,215) $ (759,089)
=========================================================================================
35
Income Taxes
- --------------------------------------------------------------------------------
1997 1996 1995
(Amounts in Thousands of Dollars)
- ------------------------------------------------------------------------------------------
Currently payable: Federal $ 3,911 $ 85,976 $ 77,667
State 31,083 44,582 29,915
Deferred--net: Federal 69,324 (18,737) 2,550
State (93) (14,874) (5,640)
Investment tax credits deferred--net (8,420) (9,559) (7,831)
- ------------------------------------------------------------------------------------------
Income Taxes $ 95,805 $ 87,388 $ 96,661
==========================================================================================
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
- --------------------------------------------------------------------------------
1997 1996 1995
(Amounts in Thousands of Dollars)
- -----------------------------------------------------------------------------------------------
Computed federal income tax at statutory rate $103,217 $ 93,284 $93,528
Increase (decrease) in taxes resulting from:
State income taxes, net of federal income tax benefits 20,143 19,310 15,779
Investment tax benefits--net (17,831) (15,116) (5,478)
Amortization of deferred investment tax credits (8,420) (9,559) (7,831)
Other (1,304) (531) 663
- -----------------------------------------------------------------------------------------------
Total Income Tax Expense $ 95,805 $ 87,388 $96,661
===============================================================================================
H. 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 at December 31
- --------------------------------------------------------------------------------
1997 1996
(Amounts in Thousands of Dollars)
- -----------------------------------------------------------------------------------
Nuclear fuel $ 92,901 $ 79,103
Electric plant 20,761 20,505
- -----------------------------------------------------------------------------------
Total 113,662 99,608
Less: Accumulated amortization (50,725) (47,670)
- -----------------------------------------------------------------------------------
Property Held Under Capital Leases--Net (a) $ 62,937 $ 51,938
===================================================================================
(a) Includes $2,874 in 1997 and $2,618 in 1996 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 is accounted for as an
operating lease. 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 and reduce the annual lease payments. The bonds were
originally issued in 1987 for the purpose of partially financing the lease of BV
Unit 2. In accordance with the BV Unit 2 lease agreement, the Company paid the
premiums of approximately $36.4 million as a supplemental rent payment to the
lessors. This amount was deferred and is being amortized over the remaining
lease term. At December 31, 1997, the deferred balance was approximately $28.6
million.
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, see "Depreciation and Amortization," Note A, on
page 27). These lease-related expenses are charged to operating expenses on the
statement of consolidated income.
36
Summary of Rental Payments
- -------------------------------------------------------------------------------
1997 1996 1995
(Amounts in Thousands of Dollars)
- --------------------------------------------------------------------------------------------------------------
Operating leases $ 60,684 $ 59,503 $ 57,617
Amortization of capital leases 16,847 19,378 26,705
Interest on capital leases 3,435 3,703 4,332
- --------------------------------------------------------------------------------------------------------------
Total Rental Payments $ 80,966 $ 82,584 $ 88,654
==============================================================================================================
Future Minimum Lease Payments
- -------------------------------------------------------------------------------
Operating Leases Capital Leases
Year Ended December 31, (Amounts in Thousands of Dollars)
- -----------------------------------------------------------------------------------------------
1998 $ 54,326 $ 26,401
1999 54,319 16,417
2000 54,280 10,446
2001 54,195 4,717
2002 55,746 3,342
2003 and thereafter 810,097 16,469
- -----------------------------------------------------------------------------------------------
Total Minimum Lease Payments $1,082,963 $ 77,792
- -----------------------------------------------------------------------------------------------
Less: Amount representing interest (17,729)
- -----------------------------------------------------------------------------------------------
Present value of minimum lease payments for capital leases (a) $ 60,063
===============================================================================================
(a) Includes current obligations of $22.5 million at December 31, 1997.
Future minimum lease payments for capital leases are related principally to
the estimated use of nuclear fuel financed through leasing arrangements and
building leases. Future minimum lease payments for operating leases are related
principally to BV Unit 2 and certain corporate offices.
Future payments due to the Company, as of December 31, 1997, under subleases
of certain corporate office space are approximately $5.9 million in 1998, $6.0
million in 1999 and $27.6 million thereafter.
I. Commitments and Contingencies
Construction and Investments
The Company estimates that it will spend, excluding AFC and nuclear fuel,
approximately $130 million during 1998 and $100 million in each of 1999 and 2000
for electric utility construction.
In 1997, the Company formed a strategic alliance with CQ Inc. to produce
E-Fuel(TM), a coal-based synthetic fuel. The first six plants to produce
E-Fuel(TM) are under construction, and are expected to be in operation by mid-
1998. The Company estimates the cost of this construction to be approximately
$25 million in 1998.
In February 1998, the Company issued 159,732 shares of DQE Preferred Stock,
representing an investment of approximately $16 million in a water company. The
Company has committed approximately $24 million for additional investments in
water, wastewater and water services companies for the first quarter of 1998.
In 1997, the Company entered into a partnership with MCI Communications
Corporation. The Company expects this partnership will lead to investment
opportunities in the expanding telecommunications business.
Nuclear-Related Matters
The Company has an ownership 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. 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.
37
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. The
Company is seeking recovery of any potential shortfall in decommissioning
funding as part of either its Restructuring Plan or its Stand-Alone Plan. (See
"Rate Matters," Note E, on page 31.)
With respect to the transition to a competitive generation market, the
Customer Choice Act requires that utilities include a plan to mitigate any
shortfall in decommissioning trust fund payments for the life of the facility
with any future decommissioning filings. Consistent with this requirement, in
1997 the Company increased its annual contributions to the decommissioning
trusts by $5 million to approximately $9 million. The Company has received
approval from the IRS for qualification of 100 percent of additional nuclear
decommissioning trust funding for BV Unit 2 and Perry Unit 1, and 79 percent for
BV Unit 1.
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, 1997 and 1996, totaled approximately $47.1 million and $33.7
million, respectively.
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 $8.9
billion. The maximum available private primary insurance of $200 million has
been purchased by the Company. Additional protection of $8.7 billion would be
provided by an assessment of up to $79.3 million per incident on each nuclear
unit in the United States. The Company's maximum total possible assessment,
$59.4 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 $5.8 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 21 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 $3.4 million.
Beaver Valley Power Station (BVPS) Steam Generators. 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 continues 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 2 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 to 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
38
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
scheduled refueling outage is the fall of 2000.
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. The next refueling outage for BV
Unit 1 is scheduled to begin in April 1999, and the next refueling outage for BV
Unit 2 is currently scheduled to begin in September 1998. Both outages will
include inspection of 100 percent of each unit's steam generator tubes. The
Company will continue to monitor and evaluate the condition of the BVPS steam
generators.
BV Unit 1 went off-line on September 27, 1997, for a scheduled refueling
outage, and returned to service on January 21, 1998. Perry Unit 1 completed a
refueling outage on October 23, 1997. This outage lasted 40 days, a record for
Perry Unit 1. The next refueling outage for Perry Unit 1 is currently scheduled
to begin in March 1999.
BV Unit 1 went off-line January 30, 1998, due to an issue identified in a
technical review recently completed by the Company. BV Unit 2 went off-line
December 16, 1997, to repair the emergency air supply system to the control room
and has remained off-line due to other issues identified by a similar technical
review of BV Unit 2. These technical reviews are in response to a 1997
commitment made by the Company to the NRC. The Company is one of many utilities
faced with these technical issues, some of which date back to the original
design of BVPS. Both BVPS units remain off-line for a revalidation of technical
specification surveillance testing requirements of various plant systems. Based
on the current status of the revalidation process, the Company currently
anticipates that both BVPS units will remain off-line through March 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 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 2017, 2011 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, was not entirely in favor of the DOE or the utilities. The court
permitted the DOE to pursue alternative dispute resolution, but prohibited it
from using its lack of a spent fuel repository as a defense. The DOE has
requested a rehearing on the matter, which has yet to be scheduled.
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 (NEPA) and are to be paid by such utilities over a 15-year period.
At December 31, 1997 and 1996, the Company's liability for contributions was
approximately $7.2 million and $8.1 million, respectively (subject to an
inflation adjustment). (See "Rate Matters," Note E, on page 31.)
Fossil Decommissioning
In Pennsylvania, current ratemaking does not allow utilities to recover future
decommissioning costs through depreciation charges during the operating life of
fossil-fired generating stations. Based on studies conducted in 1997, this
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 final unit's operations. The Company
has submitted these estimates to the PUC, and is seeking to recover these costs
as part of either its Restructuring Plan or its Stand-Alone Plan. (See "Rate
Matters," Note E, on page 31.)
39
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, 1997, the Company's share
of these guarantees was $15.1 million. The prices paid for the coal by the
companies under this contract are expected to be sufficient to meet debt and
lease obligations to be satisfied in the year 2000. The minimum future payments
to be made by the Company solely in relation to these obligations are $6.2
million in 1998, $5.8 million in 1999, and $4.6 million in 2000. The Company's
total payments for coal purchased under the contract were $38.3 million in 1997,
$26.9 million in 1996, and $28.9 million in 1995.
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 the underlying housing projects, the Company believes that such
deferrals are ample for this purpose.
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. Capital costs of $2.8 million and $2.5 million were
incurred by the Company in 1997 and 1996, respectively, to comply with these DEP
regulations. The additional capital cost of compliance through the year 2000 is
estimated, based on current information, to be $16 million. This estimate is
subject to the results of groundwater assessments and DEP final approval of
compliance plans.
Employees
The Company is party to a labor contract expiring in September 2001 with the
International Brotherhood of Electrical Workers (IBEW), which represents
approximately 2,000 of the Company's employees. The contract provides, among
other things, employment security, income protection and 3 percent annual wage
increases through September 2000.
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.
J. 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 at December 31
- --------------------------------------------------------------------------------
Principal Outstanding
Interest (Amounts in Thousands of Dollars)
Rate Maturity 1997 1996
- -------------------------------------------------------------------------------------------
First mortgage bonds 5.85%-8.75% 1998-2025 $ 778,000(a) $ 853,000(b)
Pollution control notes (c) 2009-2030 417,985 417,985
Sinking fund debentures 5% 2010 2,791 4,891
Term loans 6.47%-7.47% 2000-2001 150,000 150,000
Miscellaneous 31,017 17,785
Less: Unamortized debt discount
and premium--net (3,672) (3,915)
- -------------------------------------------------------------------------------------------
Total Long-Term Debt $1,376,121 $1,439,746
===========================================================================================
(a) Excludes $75.0 million related to current maturities during 1998.
(b) Excludes $50.0 million related to a current maturity during 1997.
(c) The pollution control notes have adjustable interest rates. The interest
rates at year-end averaged 3.9 percent in 1997 and 3.7 percent in 1996.
40
At December 31, 1997, sinking fund requirements and maturities of long-term
debt outstanding for the next five years were $75.3 million in 1998, $80.6
million in 1999, $165.2 million in 2000, $85.2 million in 2001, and $0.3 million
in 2002.
Total interest and other charges were $115.6 million in 1997, $110.3 million
in 1996, and $107.6 million in 1995. Interest costs attributable to long-term
debt and other interest were $101.2 million, $99.4 million and $102.4 million in
1997, 1996 and 1995, respectively. Of these amounts, $2.3 million in 1997, $1.2
million in 1996, and $0.7 million in 1995 were capitalized as AFC. Debt discount
or premium and related issuance expenses are amortized over the lives of the
applicable issues.
During 1994, the Company's BV Unit 2 lease arrangement was amended to reflect
an increase in federal income tax rates. At the same time, the associated letter
of credit securing the lessor's equity interest in the unit was increased from
$188 million to $194 million and the term of the letter of credit was extended
to 1999. If certain specified events occur, the letter of credit could be drawn
down by the owners, the leases could terminate, and collateralized lease bonds
($381.5 million at December 31, 1997) would become direct obligations of the
Company.
At December 31, 1997, 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 $1,474.6
million. The principal amount included in the Company's consolidated balance
sheet is $1,455.1 million.
At December 31, 1997 and 1996, the Company was in compliance with all of its
debt covenants. (See "Rate Matters," Note E, on page 31.)
K. Preferred and Preference Stock
Preferred and Preference Stock at December 31
- --------------------------------------------------------------------------------
(Shares and Amounts in Thousands)
-------------------------------------
1997 1996
Call Price -------------------------------------
Per Share Shares Amount Shares Amount
- ------------------------------------------------------------------------------------------------
Preferred Stock of DQE:
4.3% Series A Preferred Stock (a) (b) -- 12 $ 1,172 -- --
4.2% Series A Preferred Stock (a) (b) -- 4 376 -- --
- ------------------------------------------------------------------------------------------------
Preferred Stock Series of Subsidiaries:
3.75% (c) (d) (e) $51.00 148 7,407 148 $ 7,407
4.00% (c) (d) (e) 51.50 550 27,486 550 27,486
4.10% (c) (d) (e) 51.75 120 6,012 120 6,012
4.15% (c) (d) (e) 51.73 132 6,643 132 6,643
4.20% (c) (d) (e) 51.71 100 5,021 100 5,021
$2.10 (c) (d) (e) 51.84 159 8,039 159 8,039
9.00% (f) -- -- 3,000 -- 3,000
8.375% (g) -- 6,000 150,000 6,000 150,000
6.5% (h) -- -- 1,000 -- --
- ------------------------------------------------------------------------------------------------
Total Preferred Stock 7,225 216,156 7,209 213,608
- ------------------------------------------------------------------------------------------------
Preference Stock Series of Subsidiaries: (i)
Plan Series A (e) (j) 36.90 799 28,295 817 28,997
- ------------------------------------------------------------------------------------------------
Total Preference Stock 799 28,295 817 28,997
- ------------------------------------------------------------------------------------------------
Deferred ESOP benefit (16,400) (19,533)
- ------------------------------------------------------------------------------------------------
Total Preferred and Preference Stock $228,051 $223,072
================================================================================================
(a) Preferred Stock: 4,000,000 authorized shares; Securities, no par value
(b) Convertible; $100 liquidation preference per share
(c) Preferred stock: 4,000,000 authorized shares; $50 par value; cumulative
(d) $50 per share involuntary liquidation value
(e) Non-redeemable
(f) 500 authorized shares; 10 issued $300,000 par value; involuntary
liquidation value $300,000 per share; mandatory redemption beginning August
2000; cumulative
(g) Cumulative Monthly Income Preferred Securities, Series A (MIPS): 6,000,000
authorized shares; $25 involuntary liquidation value
(h) 1,500 authorized shares; 10 issued, $100,000 par value; $100,000
involuntary liquidation value
(i) Preference stock: 8,000,000 authorized shares; $1 par value; cumulative
(j) $35.50 per share involuntary liquidation value
41
On July 30, 1997, the Company authorized and registered 1,000,000 shares of
DQE Preferred Stock. As of December 31, 1997, 15,480 shares of DQE Preferred
Stock had been issued and were outstanding. An additional 159,732 shares of DQE
Preferred Stock were issued on February 19, 1998. The DQE Preferred Stock ranks
senior to the Company's common stock as to the payment of dividends and as to
the distribution of assets on liquidations, dissolution or winding-up of the
Company. The 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 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. If the proposed merger
with AYE occurs prior to any conversion, each share of DQE Preferred Stock will
be convertible into AYE common stock, using the same methodology to calculate
the number of shares.
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, and in the fourth quarter of 1997 the Company
declared an initial quarterly dividend of $1.075 per share, payable January 1,
1998. 3,760 shares of DQE Preferred Stock are entitled to an annual dividend of
4.2 percent, and in the first quarter of 1998 the Company declared a dividend
for the period of December 16, 1997 through March 31, 1998 of $1.237 per share,
payable April 1, 1998. The recently issued 159,732 shares are entitled to a 4.0
percent annual dividend, and in the first quarter of 1998 the Company declared a
dividend for the period February 19, 1998 through March 31, 1998 of $0.444 per
share, payable April 1, 1998.
In October 1997, a Duquesne subsidiary issued 10 shares of preferred stock,
par value $100,000 per share. 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, 1997, Duquesne had made all dividend
payments. Preferred and preference dividends of subsidiaries included in
interest and other charges were $16.7 million, $12.1 million and $5.9 million in
1997, 1996 and 1995. Total preferred and preference stock had involuntary
liquidation values of $244.4 million and $242.5 million, which exceeded par by
$27.6 million and $28.2 million at December 31, 1997 and 1996.
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 M, on page 43.) 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,
1997, $16.4 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
42
cash contributions from the Company are used to repay the ESOP note. The Company
made cash contributions of approximately $1.1 million for 1997, $1.4 million for
1996, and $1.6 million for 1995. These cash contributions were the difference
between the ESOP debt service and the amount of dividends on ESOP shares ($2.3
million in 1997, 1996 and 1995). 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 $3.2
million in 1997 and $2.3 million in 1996 and 1995. 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.
L. Common Stock
Changes in the Number of Shares of DQE Common Stock Outstanding
- -------------------------------------------------------------------------------
1997 1996 1995
(Amounts in Thousands of Shares)
- -------------------------------------------------------------------------------
Outstanding as of January 1 77,273 77,556 78,459
Reissuance from treasury stock 408 157 83
Repurchase of common stock (1) (440) (986)
- -------------------------------------------------------------------------------
Outstanding as of December 31 77,680 77,273 77,556
===============================================================================
The Company has continuously paid dividends on common stock since 1953. The
Company's annualized dividends per share were $1.44, $1.36 and $1.28 at December
31, 1997, 1996 and 1995. During 1997, the Company paid a quarterly dividend of
$0.34 per share on each of January 1, April 1, July 1 and October 1. The
quarterly dividend declared in the fourth quarter of 1997 was increased from
$0.34 to $0.36 per share payable January 1, 1998.
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, 1997. (See "Rate Matters," Note E, on pages 31 through 35.)
M. Employee Benefits
Retirement Plans
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 (ERISA) but that does not exceed the
maximum tax-deductible amount for the year. Pension costs charged to expense or
construction were $12.7 million for 1997, $11.9 million for 1996, and $6.1
million for 1995.
In 1997, the Company offered an early retirement plan to its bargaining unit
employees meeting certain age and service criteria. In accordance with SFAS No.
88, Employers' Accounting for Settlements and Curtailments of Defined Benefit
Pension Plans and for Termination Benefits and SFAS No. 106, Employers'
Accounting for Postretirement Benefits Other Than Pensions, the Company recorded
$6.8 million of one-time costs as a regulatory asset and other non-current
liability on the consolidated balance sheet.
43
Funded Status of the Retirement Plans and Amounts Recognized on the
Consolidated Balance Sheet at December 31
- --------------------------------------------------------------------------------
1997 1996
(Amounts in Thousands of Dollars)
- -------------------------------------------------------------------------------------------------------------------------
Actuarial present value of benefits rendered to date:
Vested benefits $460,483 $413,109
Non-vested benefits 25,080 22,551
- -------------------------------------------------------------------------------------------------------------------------
Accumulated benefits obligations based on compensation to date 485,563 435,660
Additional benefits based on estimated future salary levels 68,739 61,438
- -------------------------------------------------------------------------------------------------------------------------
Projected benefits obligation 554,302 497,098
Fair market value of plan assets 605,457 525,871
- -------------------------------------------------------------------------------------------------------------------------
Projected benefits obligation under plan assets $ 51,155 $ 28,773
=========================================================================================================================
Unrecognized net gain $153,682 $128,382
Unrecognized prior service cost (39,800) (43,790)
Unrecognized net transition liability (12,039) (13,853)
Net pension liability per consolidated balance sheet (50,688) (41,966)
- -------------------------------------------------------------------------------------------------------------------------
Total $ 51,155 $ 28,773
=========================================================================================================================
Assumed rate of return on plan assets 8.00% 8.25%
- -------------------------------------------------------------------------------------------------------------------------
Discount rate used to determine projected benefits obligation 7.00% 7.50%
- -------------------------------------------------------------------------------------------------------------------------
Assumed change in compensation levels 4.75% 5.25%
- -------------------------------------------------------------------------------------------------------------------------
Pension assets consist primarily of common stocks, United States obligations
and corporate debt securities.
Components of Net Pension Cost
- --------------------------------------------------------------------------------
1997 1996 1995
(Amounts in Thousands of Dollars)
- ------------------------------------------------------------------------------------------------------------------------------------
Service cost (benefits earned during the year) $ 12,340 $ 12,209 $ 9,953
Interest on projected benefits obligation 36,570 32,597 30,063
Return on plan assets (95,444) (58,173) (99,246)
Net amortization and deferrals 65,801 25,312 65,316
- ------------------------------------------------------------------------------------------------------------------------------------
Net Pension Cost $ 19,267 $ 11,945 $ 6,086
====================================================================================================================================
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 1997 incentive target for management was 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 K, on page 41.)
The 401(k) Retirement Savings Plan for IBEW Represented Employees provides
that, beginning in 1995, 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 1997, the incentive target was accomplished.
The Company's shareholders have approved a long-term incentive plan through
which the Company may grant management employees options to purchase, during the
years 1987 through 2006, up to a total of 7.5 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, 1997, approximately two million of
these shares were available for future grants.
44
As of December 31, 1997, 1996 and 1995, active grants totaled 1,084,041;
1,698,000; and 2,159,000 shares. Exercise prices of these options ranged from
$15.8334 to $33.7813 at December 31, 1997; from $8.2084 to $30.875 at December
31, 1996; and from $8.2084 to $27.625 at December 31, 1995. Expiration dates of
these grants ranged from 2000 to 2007 at December 31, 1997; from 1997 to 2006 at
December 31, 1996; and from 1997 to 2005 at December 31, 1995. As of December
31, 1997, 1996 and 1995, stock appreciation rights (SARs) had been granted in
connection with 635,995; 984,000; and 1,202,000 of the options outstanding.
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. During 1995,
367,000 SARs were exercised; 133,000 options were exercised at prices ranging
from $8.2084 to $21.6667; and 28,000 options were cancelled. Of the active
grants at December 31, 1997, 1996 and 1995, 402,816; 668,000; and 929,000 were
not exercisable.
Other Postretirement Benefits
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 liability over 20 years.
Components of Postretirement Cost
- --------------------------------------------------------------------------------
1997 1996
(Amounts in Thousands of Dollars)
- --------------------------------------------------------------------------------------------
Service cost (benefits earned during the period) $1,603 $1,182
Interest cost on accumulated benefit obligation 3,048 2,046
Amortization of the transition obligation over 20 years 1,686 1,700
Other 218 (812)
- ----------------------------------------------------------------------------------------
Total Postretirement Cost $6,555 $4,116
========================================================================================
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.
Funded Status of Postretirement Plan at December 31
- --------------------------------------------------------------------------------
1997 1996
(Amounts in Thousands of Dollars)
- -----------------------------------------------------------------------------------------------------
Actuarial present value of benefits:
Retirees $ 8,150 $ 8,840
Fully eligible active plan
participants 5,966 3,829
Other active plan participants 32,214 26,352
- -----------------------------------------------------------------------------------------------------
Accumulated postretirement benefit obligation 46,330 39,021
Fair market value of plan assets -- --
- -----------------------------------------------------------------------------------------------------
Accumulated benefit obligation in excess of plan assets $(46,330) $(39,021)
- -----------------------------------------------------------------------------------------------------
Unrecognized net actuarial (loss) gains $ (1,208) $ 2,874
Unrecognized net transition liability (25,294) (27,198)
Postretirement liability per consolidated balance sheet (19,828) (14,697)
- -----------------------------------------------------------------------------------------------------
Total $(46,330) $(39,021)
- -----------------------------------------------------------------------------------------------------
Discount rate used to determine projected benefit obligation 7.00% 7.50%
- -----------------------------------------------------------------------------------------------------
Health care cost trend rates:
For year beginning January 1 6.58% 6.96%
Ultimate rate in the year 2001 5.50% 6.00%
- -----------------------------------------------------------------------------------------------------
Effect of a one percent increase in
health care cost trend rates:
On accumulated projected benefit obligation $ 5,234 $ 2,920
On aggregate of annual service and interest costs $ 581 $ 391
- ------------------------------------------------------------------------------------------------------
45
N. Quarterly Financial Information (Unaudited)
Summary of Selected Quarterly Financial Data (Thousands of Dollars,
Except Per Share Amounts)
- --------------------------------------------------------------------------------
[The quarterly data reflect seasonal weather variations in the utility's
service territory.]
- --------------------------------------------------------------------------------
1997 First Quarter Second Quarter Third Quarter Fourth Quarter
- ------------------------------------------------------------------------------------------------------------------------------------
Operating Revenues (a) $303,584 $285,861 $ 331,203 $ 298,526
Operating Income (a) 76,817 56,392 96,448 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
====================================================================================================================================
1996 First Quarter Second Quarter Third Quarter Fourth Quarter
- ------------------------------------------------------------------------------------------------------------------------------------
Operating Revenues (a) $300,518 $293,357 $ 335,430 $ 296,890
Operating Income (a) 71,316 67,385 104,891 59,414
Net Income 42,305 38,972 57,412 40,449
Basic Earnings Per Share 0.55 0.50 0.74 0.53
Diluted Earnings Per Share 0.54 0.49 0.74 0.52
Stock Price:
High 31 1/2 28 7/8 28 3/4 30 3/8
Low 27 1/2 25 3/4 27 27
====================================================================================================================================
(a) Restated to conform with presentations adopted during 1997.
46
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 Exhibit 99.2
hereto. 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 Exhibit 99.1
hereto. The information is incorporated here by reference.
Item 12. Security Ownership of Certain Beneficial Owners and Management.
Information relating to the ownership of equity securities of DQE by DQE
directors, officers and certain beneficial owners is set forth under the caption
"Beneficial Ownership of Stock" in Exhibit 99.1 hereto. Information is
incorporated here by reference.
Item 13. Certain Relations and Related Transactions.
None.
Part IV
Item 14. Exhibits, Financial Statement Schedules and Reports on Form 8-K.
(a)(1) The following information is set forth here in Item 8 (Consolidated
Financial Statements and Supplementary Data) on pages 22 through 46 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, 1997.
Consolidated Balance Sheet, December 31, 1996 and 1997.
Statement of Consolidated Cash Flows for the Three Years Ended December 31,
1997.
Statement of Consolidated Retained Earnings for the Three Years Ended December
31, 1997.
Notes to Consolidated Financial Statements.
47
(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, 1997:
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 of S-K.
(b) No reports on Form 8-K were filed during the fiscal quarter ended December
31,1997.
Exhibit Index
Exhibit Method of
No. Description Filing
2.1 Agreement and Plan of Merger dated as Exhibit 2(a) to the Form 8-K
of April 5, 1997, among the Company, Current Report of DQE dated
AYE and AYP Sub, Inc. April 8, 1997.
2.2 Stock Option Agreement dated as of Exhibit 2(b) to the Form 8-K
April 5, 1997, between the Company Current Report of DQE dated
and AYE. April 8, 1997.
2.3 Letter Agreement dated as of April 5, Exhibit 2(c) to the Form 8-K
1997, between the Company Current Report of DQE dated
and AYE. April 8, 1997.
3.1 Articles of Incorporation of DQE Exhibit 3.1 to the Form 10-K
effective January 5, 1989. Annual Report of DQE for the
year ended December 31, 1989.
3.2 Articles of Amendment of DQE effective Exhibit 3.2 to the Form 10-K
April 27, 1989. Annual Report of DQE for the
year ended December 31, 1989.
3.3 Articles of Amendment of DQE effective Exhibit 3.3 to the Form 10-K
February 8, 1993. Annual Report of DQE for the
year ended December 31, 1992.
3.4 Articles of Amendment of DQE effective Exhibit 3.4 to the Form 10-K
May 24, 1994. Annual Report of DQE for the
year ended December 31, 1994.
48
Exhibit Method of
No. Description Filing
3.5 Articles of Amendment of DQE effective Exhibit 3.5 to the Form 10-K
April 20, 1995. Annual Report of DQE for the
year ended December 31, 1995.
3.6 Statement with respect to the Preferred Exhibit 3.1 to the Form 10-Q
Stock, Series A (Convertible), as filed Quarterly Report of DQE for
with the Pennsylvania Department the quarter ended Septem-
of State on August 29, 1997. ber 30, 1997.
3.7 By-Laws of DQE, as amended through Exhibit 3.6 to the Form 10-K.
December 18, 1996 and as Annual Report of DQE for the
currently in effect. year ended December 31, 1997.
4.1 Indenture dated March 1, 1960, relating Exhibit 4.3 to the Form 10-K
to Duquesne Light Company's 5% Annual Report of DQE for the
Sinking Fund Debentures. year ended December 31, 1989.
4.2 Indenture of Mortgage and Deed of Trust Exhibit 4.3 to Registration
dated as of April 1, 1992, securing Statement (Form S-3)
Duquesne Light Company's First No. 33-52782.
Collateral Trust Bonds.
4.3 Supplemental Indentures supplementing
the said Indenture of Mortgage and
Deed of Trust -
Supplemental Indenture No. 1. Exhibit 4.4 to Registration
Statement (Form S-3)
No. 33-52782.
Supplemental Indenture No. 2 through Exhibit 4.4 to Registration
Supplemental Indenture No. 4. Statement (Form S-3)
No. 33-63602.
Supplemental Indenture No. 5 through Exhibit 4.6 to the Form 10-K
Supplemental Indenture No. 7. Annual Report of Duquesne
Light Company for the year
ended December 31, 1993.
Supplemental Indenture No. 8 and Exhibit 4.6 to the Form 10-K
Supplemental Indenture No. 9. Annual Report of Duquesne
Light Company for the year
ended December 31, 1994.
Supplemental Indenture No. 10 Exhibit 4.4 to the Form 10-K
through Supplemental Indenture Annual Report of Duquesne
No. 12. 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.
49
Exhibit Method of
No. Description Filing
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.
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 10.6 to the Form 10-K
Annual Report of DQE for the
year ended December 31, 1992.
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.
50
Exhibit Method of
No. Description Filing
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 substantially identical
agreements with Gary R. Brandenberger and
Donald J. Clayton.
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 substantially
identical agreements with Gary R. Brandenberger and
Donald J. Clayton.
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.
Material Contracts relating to Duquesne Light Company
Agreements relating to Jointly Owned Generating Units:
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.
51
Exhibit Method of
No. Description Filing
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 Annual Report of Duquesne
companies 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.
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, Exhibit 10.10 to the Form 10-K
1993. 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, Annual Report of Duquesne
1993). 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.
52
Exhibit Method of
No. Description Filing
Agreements relating to the Sale and Leaseback
of Beaver Valley Unit No. 2:
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.
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.
53
Exhibit Method of
No. Description Filing
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.
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.
54
Exhibit Method of
No. Description Filing
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.
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.
55
Exhibit Method of
No. Description Filing
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) No. 33-18144.
Ground Lessor and Grantor, and The 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, Tenant and Grantee.
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.
56
Exhibit Method of
No. Description Filing
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.
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 Light
and Assignment of Facility Lease dated as of Company for the year ended
September 15, 1987 between The First National Bank December 31, 1987.
Bank of Boston, as 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.
y10.61 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 Light Company for the year
15, 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 Light Company for the year
15, 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.
57
Exhibit Method of
No. Description Filing
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 Light Company for the year
15, 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, 1992 Exhibit 10.59 to the Form 10-K
to Collateral Trust Indenture dated as of November 15, 1992 Annual Report of Duquesne
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, DQUII 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, DQUII 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.
58
Exhibit Method of
No. Description Filing
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, DQUII 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, DQUII 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.
12.1 Ratio of Earnings to Fixed Charges. Filed here.
13.1 Pages 21-23 and the inside back cover of the DQE Filed here.
Annual Report to Shareholders for the year ended
December 31, 1997. 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.
99.1 Executive Compensation of DQE Executive Filed here.
Officers for 1997 and Security Ownership of Certain
Beneficial Owners and DQE Directors and Executive
Officers as of December 31, 1997.
99.2 Directors of DQE and Duquesne Light Company. Filed here.
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.
59
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,
1998, subject to payment in advance of the cost of reproducing the exhibits
requested.
60
SCHEDULE II
SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS
For the Years Ended December 31, 1997, 1996 and 1995
(Thousands of Dollars)
Column A Column B Column C Column D Column E Column F
-------- ---------- ---------- ---------- ---------- --------
Additions
--------------------------
Balance at Charged to Charged to Balance
Beginning Costs and Other at End
Description of Year Expenses Accounts Deductions of Year
---------------- ---------- ---------- ---------- ---------- --------
Year Ended December 31, 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
------- ------- ------ ------- -------
Year Ended December 31, 1995
Reserve Deducted from the Asset
to which it applies:
Allowance for uncollectible accounts $15,822 $13,430 $3,567(A) $14,161(B) $18,658
------- ------- ------ ------- -------
Notes: (A) Recovery of accounts previously written off.
(B) Accounts receivable written off.
61
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 23, 1998 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.
Signature Title Date
/s/ David D. Marshall President, Chief Executive Officer and Director March 23, 1998
- ---------------------------
David D. Marshall
/s/ Gary L. Schwass Executive Vice President and Chief Financial March 23, 1998
- ---------------------------- Officer
Gary L. Schwass
/s/ Morgan K. O'Brien Vice President and Controller March 23, 1998
- ---------------------------- (Principal Accounting Officer)
Morgan K. O'Brien
/s/ Daniel Berg Director March 23, 1998
- ----------------------------
Daniel Berg
/s/ Doreen E. Boyce Director March 23, 1998
- ----------------------------
Doreen E. Boyce
/s/ Robert P. Bozzone Director March 23, 1998
- ----------------------------
Robert P. Bozzone
/s/ Sigo Falk Director March 23, 1998
- ----------------------------
Sigo Falk
/s/ William H. Knoell Director March 23, 1998
- ----------------------------
William H. Knoell
/s/ Thomas J. Murrin Director March 23, 1998
- ----------------------------
Thomas J. Murrin
- ---------------------------- Director
Eric W. Springer
62
Glossary of Terms
Competitive Generation Credit
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.
CTC or Competitive Transition Charge
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 surcharge, or competitive
transition charge.
Customer Choice
The Pennsylvania Electricity Generation Customer Choice and Competition Act (see
"Rate Matters" on page 17) will give 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 records
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
Transmission is the flow of electricity from generating stations over high
voltage lines. Distribution is the flow of electricity over lower voltage
facilities to the ultimate customer--usually businesses and homes.
Divestiture
The selling of major assets (power plants, transmission equipment or
distribution lines).
Energy Cost Rate Adjustment Clause (ECR)
The Company recovers through the ECR, to the extent that such amounts are 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.
Independent System Operator (ISO)
An organization formed by, but independent of, transmission-owning utilities
which is responsible for ensuring nondiscriminatory open transmission access and
the planning and security of the combined bulk transmission systems of utilities
within a given geographic region.
Market Power
When one company owns a sufficiently large percentage of generation,
transmission, or distribution capabilities in a region which allow 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.
Open Access
Gives all customers equal opportunity to access the transmission grid.
Peak Demand
Peak demand is the greatest amount of electricity demanded at any given time.
Pennsylvania Public Utility Commission (PUC)
The governmental body that regulates all utilities (electric, gas, telephone,
water, etc.) that do business in Pennsylvania.
Rate Base
The amount representing the value of assets approved by a regulatory agency for
inclusion in rates charged to rate-regulated customers.
Regulatory Assets
Historic 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 are
capitalized as regulatory assets by the regulated utility.
Restructuring Plan
In contemplation of the merger with Allegheny Energy being consummated, the
Company has filed this plan incorporating the merger benefits into its
restructuring and recovery of transition costs under the Customer Choice Act.
Stand-Alone Plan
In the event the merger with Allegheny Energy is not consummated, the Company
has filed this plan for restructuring and recovery of transition costs under the
Customer Choice Act.
Tariff
Public schedules that detail a utility's rates, rules, service territory and
terms of service that are filed for official approval with a regulatory agency.
Transition or Stranded Costs
Transition costs, also known as stranded costs, are the net present value of a
utility's known or measurable costs related to electric generation that are
recoverable under the current regulatory framework, but which may not be
recoverable in a competitive generation market. They are costs which remain
unrecovered following mitigation efforts taken by the utility.
Unbundled Charges
Separate charges for each of the generation, transmission and distribution of
electricity in accordance with the deregulation of generation under the Customer
Choice Act.
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.
63