Document/Exhibit Description Pages Size
1: 10-K Annual Report 63 419K
2: EX-3.6 By-Laws of Dqe 22 39K
5: EX-10.14 Non-Competition and Confidentiality Agreement 8 29K
3: EX-10.5 Dqe 1996 Stock Plan for Non-Employee Directors 9 27K
4: EX-10.7 Performance Incentive Program for Dqe 6 20K
6: EX-13.1 1996 Dqe Annual Report to Stockholders 5 34K
7: EX-23.1 Independent Auditors' Consent 1 7K
8: EX-27.1 Financial Data Schedule 2 8K
9: EX-99.1 Executive Compensation of Dqe Executive Officers 11 51K
10: EX-99.2 Directors of Dqe and Duquesne Light Company 2 10K
[CONFORMED]
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, 1996
-----------------
[ ] 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
----------------------
1-10290
DQE, Inc.
(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
----- ------
Aggregate market value of DQE Common Stock held by non-affiliates as of February
21, 1997 was $2,303,952,960. There were 77,281,441 shares of DQE Common Stock
outstanding as of February 21, 1997.
[ ] 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
DOCUMENTS INCORPORATED BY REFERENCE
Part of Form 10-K
Into Which Document
Description Is Incorporated
----------- --------------------
DQE Annual Report to Shareholders Parts I and II
for the year ended December 31, 1996
TABLE OF CONTENTS
Page
----
PART I
ITEM 1. BUSINESS
Corporate Structure 1
Results of Operations 2
Liquidity and Capital Resources 4
Rate Matters 6
Property, Plan and Equipment (PP&E) 8
Employees 10
Electric Utility Operations 10
Fossil Fuel 10
Nuclear Fuel 11
Nuclear Decommissioning 11
Nuclear Insurance 12
Spent Nuclear Fuel Disposal 13
Uranium Enrichment Decontamination and
Decommissioning 13
Environmental Matters 13
Outlook 14
Other 17
Executive Officers of the Registrant 18
ITEM 2. PROPERTIES 19
ITEM 3. LEGAL PROCEEDINGS 20
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF
SECURITY HOLDERS 20
PART II
ITEM 5. MARKET FOR REGISTRANT'S COMMON
EQUITY AND RELATED SHAREHOLDER
MATTERS 20
ITEM 6. SELECTED FINANCIAL DATA 21
ITEM 7. MANAGEMENT'S DISCUSSION AND
ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS 21
ITEM 8. CONSOLIDATED FINANCIAL STATEMENTS
AND SUPPLEMENTARY DATA 21
ITEM 9. CHANGES IN AND DISAGREEMENTS
WITH ACCOUNTANTS ON ACCOUNTING
AND FINANCIAL DISCLOSURE 21
Page
----
PART III
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS
OF THE REGISTRANT 21
ITEM 11. EXECUTIVE COMPENSATION 21
ITEM 12. SECURITY OWNERSHIP OF CERTAIN
BENEFICIAL OWNERS AND MANAGEMENT 21
ITEM 13. CERTAIN RELATIONSHIPS AND
RELATED TRANSACTIONS 21
PART IV
ITEM 14. EXHIBITS, FINANCIAL STATEMENT
SCHEDULES AND REPORTS ON FORM 8-K 22
SCHEDULE II 34
SIGNATURES 35
GLOSSARY 36
REPORT OF INDEPENDENT CERTIFIED
PUBLIC ACCOUNTANTS 37
FINANCIAL STATEMENTS 38
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 38 THROUGH 60 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 36
OF THIS REPORT.
DQE is an energy services holding company. Its subsidiaries are
Duquesne Light Company (Duquesne), Duquesne Enterprises (DE), DQE Energy
Services (DES), DQEnergy Partners and Montauk. DQE and its subsidiaries are
collectively referred to as "the Company."
Duquesne is an electric utility engaged in the production,
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 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 Partners was formed in December 1996 to
align DQE with strategic partners to capitalize on opportunities in the dynamic
energy services industry. These alliances 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.
The Company's Electric Service Territory
The Company's utility operations provide electric service to customers
in Allegheny County, including the City of Pittsburgh, Beaver County and
Westmoreland County. This 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.
Regulation
The Company is subject to the accounting and reporting requirements of
the United States Securities and Exchange Commission (SEC). In addition, the
Company's electric utility operations are subject to regulation by the
Pennsylvania Public Utility Commission (PUC) and the Federal Energy Regulatory
Commission (FERC) under the Federal Power Act with respect to rates for
interstate sales, transmission of electric power, accounting and other matters.
The Electricity Generation Customer Choice and Competition Act
(Customer Choice Act) went into effect in Pennsylvania on January 1, 1997. This
legislation provides for a gradual deregulation of the generation of
electricity, while maintaining regulation of the transmission and distribution
of electricity and related services to customers. (See "Rate Matters" and
"Competition" discussions on pages 6 and 14.)
The Company's electric utility operations are also subject to
regulation by the Nuclear Regulatory Commission (NRC) under the Atomic Energy
Act of 1954, as amended, with respect to the operation of its jointly
owned/leased nuclear power plants, Beaver Valley Unit 1 (BV Unit 1), Beaver
Valley Unit 2 (BV Unit 2) and Perry Unit 1.
The Company's consolidated financial statements report regulatory
assets and liabilities in accordance with Statement of Financial Accounting
Standards 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,
1
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 described above. (See "Rate Matters" and "Competition" discussions
on pages 6 and 14.) The Company currently believes its electricity generating
assets and related regulatory assets continue to satisfy these criteria in light
of the transition to competitive generation under the Customer Choice Act.
Should any portion of the Company's electric utility operations be deemed to no
longer meet the SFAS No. 71 criteria, the Company may be required to write off
any above-market cost assets, the recovery of which is uncertain, and any
regulatory assets or liabilities for those operations that no longer meet these
requirements.
Results of Operations
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Sales of Electricity to Customers
The increase in 1996 total operating revenues was $5.0 million, as
compared to 1995. Comparing 1995 total operating revenues to 1994, there was a
decrease of $3.7 million. Operating revenues are primarily derived from the
Company's sales of electricity. 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. (See "Rate Matters" and "Competition" discussions on pages 6 and
14.)
Electric Utility Sales by Customer Class (Kilowatt-Hours in Millions):
[Download Table]
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1996 1995 1994
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Residential 3,321 3,378 3,219
Commercial 5,737 5,729 5,563
Industrial 3,285 3,237 3,256
Miscellaneous 83 84 84
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Sales to Electric Utility Customers 12,426 12,428 12,122
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Sales to Other Utilities 3,310 2,975 3,212
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Total Sales 15,736 15,403 15,334
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Sales to residential and commercial customers are strongly 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 economic development. Sales to industrial customers are
influenced by national and global economic conditions. Customer revenues
fluctuate as a result of changes in sales volume and changes in fuel and other
energy costs.
Net Customer Revenues
Net customer revenues, reflected on the statement of consolidated
income, decreased $8.2 million or 0.8 percent in 1996 compared to 1995. The
variance can be attributed primarily to decreased residential customer kilowatt-
hour (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 the company's 20 largest customers
accounted for approximately 14 percent of customer revenues in 1996, 1995 and
1994.
In 1995 as compared to 1994, net customer revenues increased by $7.8
million, or 0.7 percent. The increase is the net result of higher KWH sales to
residential customers by 4.9 percent in response to extreme 1995 summer
temperatures, partially offset by lower fuel and other energy costs per KWH, the
benefits of which are passed through to the customers in the form of lower
rates. Revenues from electric sales to residential customers in 1995 exceeded
1994 residential revenues by $13.0 million.
2
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. The Company's electricity sales to other utilities in 1995 were less
than 1996 and 1994 due to the timing of generating station outages and the
fluctuating level of sales to the Company's electric utility customers. Future
levels of short-term sales to other utilities will be affected by the Company's
sale of its ownership interest in the Ft. Martin Power Station (Ft. Martin), the
possible sale of other generating stations, market rates, and by the outcome of
the Company's FERC filings requesting firm transmission access. (see "Mitigation
Plan" and "Transmission Access" discussions on pages 7 and 17.)
Other Operating Revenues
Other operating revenues include the Company's non-KWH utility revenues
and revenues from market-based operating activities. The increase of $10.9
million in other operating revenues when comparing 1996 and 1995 is primarily
due to increased revenues at Chester Engineers (Chester), a wholly owned
subsidiary of DE, and revenues of GSF Energy, a Montauk acquisition in the
fourth quarter of 1996. During 1997, GSF Energy is expected to contribute
approximately $20 million to other operating revenues, as compared to $2.8
million in 1996. Other operating revenues decreased $9.2 million in 1995 when
compared to the prior year. This decrease largely reflects the restructuring of
Chester.
The discussion in the preceding paragraph regarding GSF Energy contains
forward-looking statements subject to certain risks and uncertainties that
could cause actual results to differ materially from those projected. Estimates
of GSF Energy's contribution to operating revenues will depend on gas prices
and operational effectiveness.
Operating Expenses
Fuel and purchased power expense fluctuations 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 Energy Cost
Rate Adjustment Clause (ECR), changes in fuel and purchased power costs did not
impact earnings in 1996, 1995 and 1994.
Fuel and purchased power expense increased in 1996 compared to 1995 as
a result of a 33 percent increase in purchased power prices. This increase was
partially offset by lower nuclear fuel costs. Fuel and purchased power expense
decreased in 1995 compared to 1994 due to lower nuclear fuel costs, a more
favorable generation mix and a 2.7 percent decline in KWH generation.
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 GSF
Energy, acquired in the fourth quarter of 1996. In 1995, other operating expense
decreased $36.2 million when compared to 1994. This 1995 reduction reflects the
restructuring of Chester and cost savings attributable to the Company's electric
utility operations.
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 Mitigation Plan.
Depreciation and amortization expense increased $36.6 million in 1995, primarily
due to the change in the Company's electric utility operations' composite
depreciation rate from 3.0 percent to 3.5 percent effective January 1, 1995. The
Company did not seek a rate increase to recover the additional costs. (See
"Mitigation Plan" discussion on page 7.)
3
Other Income
The increase of $22.5 million in other income, when comparing 1996 to
1995, was primarily the result of income from long-term investments made during
late 1995 and 1996. Other income increased $9.4 million in 1995 when compared to
1994 primarily due to additional investing activity, including the one-time gain
recognized at the merger of International Power Machines Corporation (IPM) and
Exide Electronics Group, Inc. (Exide).
Interest and Other Charges
The increase in interest and other charges in 1996 from 1995 was $2.7
million despite the payment of $7.9 million in dividends related to preferred
stock issued in May 1996 and $2.5 million of interest on new term loans. The
interest expense increase was offset by a decrease due to the retirement of
long-term debt and preferred stock of subsidiaries during 1995. Interest and
other charges were lower in 1995 when compared to 1994 also due to the
retirement of long-term debt and preferred stock of subsidiaries. The Company's
interest on long-term debt and other interest declined to $99.4 million in 1996
from $102.4 million in 1995 and $105.1 million in 1994.
Income Taxes
Income taxes decreased in 1996 when compared to 1995 by $9.3 million,
primarily due to reduced taxable income. In 1995, taxable income was greater
than in 1994, resulting in increased income taxes of $3.7 million.
Liquidity and Capital Resources
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Capital Expenditures
The Company spent approximately $101.2 million in 1996, $94.2 million
in 1995 and $121.1 million in 1994 for capital expenditures, of which $88.5
million in 1996, $78.7 million in 1995 and $94.3 million in 1994 was spent for
electric utility construction. The remaining capital expenditures were related
to the Company's market-driven real estate investments. The Company's capital
expenditures for electric utility construction focus on improving and/or
expanding electric utility production, transmission and distribution systems.
The Company estimates that it will spend, excluding allowance for funds used
during construction (AFC) and nuclear fuel, approximately $110 million, $110
million and $95 million for electric utility construction during 1997, 1998 and
1999. These estimates also exclude any potential expenditures for reliability
enhancements to the Brunot Island (BI) Unit 3 combustion turbine. (See
"Mitigation Plan" discussion on page 7.) The Company expects that funds
generated from operations will continue to be sufficient to fund a large part of
its capital needs.
Long-term Investments
The Company has made market-driven long-term investments in the
following areas: leases, affordable housing, gas reserves, real estate, energy
solutions and engineering services. Investing activities during 1996 included
approximately $50 million in lease investments, $30 million in gas reserve
investments, $15 million in affordable housing investments, and $3 million in
energy solution investments. Investing activities of approximately $188 million
and $67 million during 1995 and 1994 were balanced between investment types.
Financing
The Company expects to meet its current obligations and debt maturities
through the year 2001 with funds generated from operations and through new
financings. At December 31, 1996, the Company was in compliance with all of its
debt covenants.
4
On May 14, 1996, Duquesne Capital L.P., a Delaware special-purpose
limited partnership the sole general partner of which is Duquesne, issued $150
million principal amount of 8-3/8 percent Cumulative Monthly Income Preferred
Securities (MIPS), Series A, with a stated liquidation value of $25.00. A
portion of the proceeds was used to retire $50 million of long-term debt
maturing May 15, 1996. The Company intends to continue to apply the remaining
proceeds to the purchase or redemption of outstanding securities and for general
corporate purposes.
During 1996, the Company entered into five-year bank term loans
totaling $85 million with fixed interest rates averaging 7.25 percent. These
loans pay interest semi-annually.
In November 1997, $50 million of mortgage bonds will mature. The
Company expects to retire these bonds with available cash or to refinance the
bonds.
Short-Term Borrowings
At December 31, 1996, the Company had two extendible revolving credit
arrangements, including a $125 million facility expiring in June 1997 and a $150
million facility expiring in October 1997. 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, 1996, there were no short-term borrowings
outstanding. At December 31, 1995, short-term borrowings were $35 million. The
weighted average interest rate applied to such borrowings was 6.5 percent.
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, 1996. At December 31, 1995, the Company had sold $7 million
of receivables to the unaffiliated corporation. The accounts receivable sales
agreement, which expires in June 1997, is one of many sources of funds available
to the Company. The Company has not determined, but may attempt to extend the
agreement or to replace the facility with a similar arrangement or to 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, 1996, the amount of nuclear fuel financed by the Company under this
arrangement totaled approximately $35 million. The Company plans to continue
leasing nuclear fuel to fulfill its requirements at least through September
1998, the remaining term of the leasing arrangement.
Dividends
The Company has continuously paid dividends on common stock since 1953
and in each of the last 10 years has increased its dividend paid per share. The
Company's annualized dividends per share were $1.36, $1.28 and $1.17 at December
31, 1996, 1995 and 1994. The annual dividends paid have increased by an average
compounded rate of 5.9 percent over the past five years, even though the Company
has maintained a lower payout ratio than the electric utility industry in
general. During 1996, the Company paid a quarterly dividend of $0.32 per share
on each of January 1, April 1, July 1 and October 1. The quarterly dividend
declared in the fourth quarter of 1996 was increased from $0.32 to $0.34 per
share payable January 1, 1997. 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
5
regulatory matters experienced by the electric utility industry generally. (See
"Competition" discussion on page 14.) The Company's stock price was $29.00 at
the end of 1996. The book value per share of common stock was $18.01 at
December 31, 1996, which represents a 5.1 percent increase in book value since
December 31, 1995.
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. 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 shareholders'
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 to its
common shareholders. No part of the retained earnings of the Company was
restricted at December 31, 1996.
[Download Table]
Changes in the Number of Shares of DQE Common Stock Outstanding
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1996 1995 1994
(Amounts in Thousands of Shares)
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Outstanding as of January 1 77,556 78,459 79,518
Reissuance from treasury stock 157 83 116
Repurchase of common stock (440) (986) (1,175)
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Outstanding as of December 31 77,273 77,556 78,459
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Rate Matters
Customer Choice Act
Under the Customer Choice Act, which went into effect on January 1,
1997, Pennsylvania has become a leader in customer choice. The Customer Choice
Act will enable Pennsylvania's electric utility customers to purchase
electricity at market prices from a variety of electric generation suppliers
(customer choice). Electric utility restructuring will be accomplished through a
two-stage process consisting of a pilot period (running through 1998) and a
phase-in period (1999 through 2001). The pilot period will give 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. Duquesne filed a pilot program with the PUC on
February 27, 1997, which proposes unbundling transmission, distribution,
electricity and competitive transition charges and offers participating
customers the same options that will be available in a competitive generation
market.
The pilot program will comprise approximately 5 percent of Duquesne's
residential, commercial and industrial demand beginning September 1, 1997.
Customers participating in the pilot will have two basic options. First,
customers can choose to continue taking bundled service from Duquesne under
approved tariffs. Second, customers can choose unbundled service with their
electricity provided by an alternative electric generation supplier. All
customers that choose unbundled electric service will be subject to unbundled
distribution charges approved by the PUC and unbundled transmission charges
pursuant to Duquesne's FERC-approved tariff. Each customer that elects
unbundled service also will be required to pay a non-bypassable access fee
(competitive transition charge) that provides Duquesne with a reasonable
opportunity to recover transition costs.
The Company must file a restructuring plan with the PUC by August 1,
1997 setting forth its proposals for the transition to customer choice and the
recovery of transition costs. (See "Competition" discussion on page 14.) The
phase-in to competition begins on January 1, 1999 when 33 percent of consumers
will have customer choice (including consumers covered by the pilot program); 66
percent of consumers will have customer choice by January 1, 2000; and all
consumers will have customer choice by January 1, 2001. 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
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utility. Delivery of electricity (including transmission, distribution and
customer service) will continue to be regulated in substantially the current
manner.
Mitigation Plan
The Company has taken a number of steps to mitigate its potential
transition costs. (See "Competition" discussion on page 14.) In addition to the
steps taken during the last 10 years to prepare for competition, effective
January 1, 1995, the Company accelerated its rate of depreciation on its fixed
nuclear assets without seeking a rate increase to recover the additional costs.
On October 31, 1996, the sale of the Company's ownership interest in Ft. Martin
was completed. Ft. Martin Unit 1 was owned 50 percent by Duquesne and 50 percent
by its operator, Allegheny Power System (APS). The sale and a plan, to be funded
in part by the proceeds of the Ft. Martin transaction, were approved by the PUC
on May 23, 1996. Under the approved plan, the Company will not increase its base
rates for a period of five years through May 2001. In addition, the Company
recorded in October 1996 a one-time reduction of approximately $130 million in
the book value of the Company's nuclear plant investment. The proceeds from the
sale are expected to be used to fund reliability enhancements to the BI Unit 3
combustion turbine and to reduce the Company's capitalization. The approved plan
also provides for incremental increases of $25 million in depreciation and
amortization expense in 1996, 1997 and 1998 related to the Company's nuclear
investment, as well as additional annual contributions to its nuclear plant
decommissioning funds of $5 million, without any increase in existing electric
rates. Also, the Company will record an annual $5 million credit to the ECR
during the plan period to compensate the Company's electric utility customers
for lost profits from any short-term power sales foregone by the sale of its
ownership interest in Ft. Martin. In addition, the Company will cap energy
costs, beginning April 1, 1997 through the remainder of the plan period, at a
historical five-year average of 1.47 cents per KWH. In accordance with the
approved plan, the Company has expensed $9 million related to the depreciation
portion of the deferred rate synchronization costs associated with BV Unit 2 and
Perry Unit 1. The Company's approved plan provides for the amortization of the
remaining deferred rate synchronization costs over a 10-year period. At December
31, 1996, the unamortized portion of these costs totaled $41.4 million, net of
deferred fuel savings related to the two units. (See "Deferred Rate
Synchronization Costs" below.) Finally, the Company's approved plan also
provides for annual assistance of $0.5 million to low-income customers.
Deferred Rate Synchronization Costs
In 1987, the PUC approved the Company's petition to defer initial
operating and other costs of BV Unit 2 and Perry Unit 1. The Company deferred
the costs incurred from November 1987, when the units went into commercial
operation, until March 1988, when a rate order was issued. In its rate order,
the PUC postponed ruling on whether these costs would be recoverable from the
Company's electric utility customers. The Company is not earning a return on the
deferred costs. (See "Mitigation Plan" discussion above.)
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).
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. (See "Fossil Fuel" discussion on page 10.)
7
Under the Customer Choice Act, the Company may replace the ECR
effective April 1, 1997 by rolling its ECR energy costs into its base rates. The
effect of this change would be to provide to the Company an opportunity to
further mitigate its deferred energy costs based upon its ability to manage its
energy costs. Under the Company's PUC-approved Mitigation Plan, the level of
energy cost recovery is capped at 1.47 cents per KWH through May 2001. To the
extent that projections do not support recovery of previously deferred costs
through this pricing mechanism, these costs would become transition costs
subject to recovery through a competitive transition charge (CTC). (See
"Competition" discussion on page 14.)
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, 1996 and 1995, are as follows:
PP&E and Related Accumulated Depreciation at December 31
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(Amounts in Thousands of Dollars)
1996 1995
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Accumulated Net Accumulated Net
Investment Depreciation Investment Investment Depreciation Investment
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Electric Production $2,467,786 $1,092,928 $1,374,858 $2,501,974 $ 885,389 $1,616,585
Electric Transmission 299,895 114,406 185,489 296,953 110,242 186,711
Electric Distribution 1,176,738 374,180 802,558 1,143,111 347,399 795,712
Electric General 324,366 168,470 155,896 314,844 141,133 173,711
Property Held for Future Use 190,821 82,737 108,084 216,633 94,283 122,350
Property Held Under Capital Leases 99,608 47,670 51,938 133,381 74,874 58,507
Other 228,256 89,554 138,702 139,217 32,557 106,660
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Total $4,787,470 $1,969,945 $2,817,525 $4,746,113 $1,685,877 $3,060,236
=================================================================================================================
Joint Interests in Generating Units
The Company has various contracts with 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. To provide the
parties with the opportunity to settle their claims, the court has postponed
litigation proceedings until April 1, 1997.
8
Joint Interests in Nuclear Power Stations
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Beaver Valley Perry
Unit 1 Unit 2 Unit 1
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Duquesne * 47.50% * 13.74%(c) 13.74%
Ohio Edison Company 35.00% 41.88% 30.00%
Pennsylvania Power Company (a) 17.50% -- 5.24%
CEI (b) -- 24.47% * 31.11%
Toledo Edison Company (b) -- 19.91% 19.91%
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* Denotes Operator
(a) Subsidiary of Ohio Edison Company
(b) Subsidiary of Centerior Energy Corporation
(c) 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
total sales price of $537.9 million was the appraised value of the Company's
interest in the property. 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.
Joint Interests in Fossil Power Stations
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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%
Ohio Edison Company * 48.00% 60.00% 39.30% 35.60% --
Pennsylvania Power Company (a) 20.80% * 4.20% * 6.80% * 6.28% --
CEI (b) -- 6.50% 28.60% 24.47% * 68.80%
Toledo Edison Company (b) -- -- 17.30% 19.91% --
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* Denotes Operator
(a) Subsidiary of Ohio Edison Company
(b) Subsidiary of Centerior Energy Corporation
On September 13, 1996, Ohio Edison Company and Centerior Energy
Corporation entered into an agreement and plan of merger to form FirstEnergy
Corporation. The regulatory approval process for the proposed merger is expected
to take approximately 12 to 18 months.
Property Held for Future Use
In 1986, the PUC approved the Company's request to remove Phillips
Power Station (Phillips) and a portion of BI from service and from rate base. In
accordance with the Company's Mitigation Plan, 112 MWs related to BI Units 2a
and 2b were moved from property held for future use to electric plant in service
in 1996. The Company expects to recover its investment in BI Units 3 and 4,
which remain in property held for future use through future electricity sales.
The Company believes its investment in BI will be necessary in order to meet
future business needs. A portion of the proceeds of the sale of Ft. Martin is
expected to be used to fund reliability enhancements to the BI Unit 3 combustion
turbine. The reliability enhancements are contingent upon the projects meeting a
least-cost test versus other potential sources of peaking capacity. (See
"Mitigation Plan" discussion on page 7.) The Company is analyzing the effects of
customer choice on its future generating requirements. The Company is planning
to seek recovery of its investment and associated costs of Phillips through a
CTC. (See "Competition" discussion on page 14.) In the event that market demand,
transmission access or rate recovery do not support the utilization of these
plants, the Company may have to write off part or all of these investments and
associated costs. At December 31, 1996, the Company's net of tax investment in
Phillips and BI held for future use was $53.6 million and $17.2 million.
9
Employees
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At December 31, 1996, DQE and its subsidiaries had 3,810 employees,
including 1,157 employees at the Company-operated Beaver Valley Power Station
(BVPS). In November 1996, the Company reached an agreement on a three-year
contract extension through September 30, 2001 with the International Brotherhood
of Electrical Workers, which represents approximately 2,000 of the Company's
employees.
Electric Utility Operations
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The Company's fossil plants operated at 76 percent availability in 1996
and 1995. The Company's nuclear plants operated at 76 percent availability in
1996 and 83 percent in 1995. The timing and duration of scheduled maintenance
and refueling outages, as well as the duration of forced outages, affect the
availability of power stations. The Company normally experiences its peak demand
in the summer. The 1996 customer system peak demand of 2,463 MW occurred on
August 7, 1996.
The Company's plan for optimizing generation resources is designed to
reduce under-utilized generating capacity and employ cost-effective sources of
peaking capacity. The sale of the Company's ownership interest in Ft. Martin
reduced in-service capacity by 276 MW. In conjunction with the sale, the Company
returned 112 MW of peaking capacity at BI to electric plant in service.
Additionally, through potential reliability enhancements to the BI Unit 3
combustion turbine, the Company could return to service another 56 MW of oil-
fired peaking capacity. (See "Property Held for Future Use" discussion on page
9.)
The Company has a 13.74 percent ownership interest in Perry Unit 1, a
nuclear generating unit located in Ohio and operated by CEI. CEI management has
advised the Company that the Perry Course of Action (PCA), an action plan
submitted to the NRC in 1993, was completed at the end of the unit's fifth
refueling outage in the spring of 1996. Perry Unit 1 has followed the PCA with
the Perry Plan for Excellence, which is the long-term phase of the unit's
performance improvement program. The Company will continue to monitor closely
the status of the performance improvement program.
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 1996, approximately 2.4 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
approximately 83 river miles from Pittsburgh. At December 31, 1996, the
Company's net investment in the mine was $11.4 million. The Company estimates
that, at December 31, 1996, its economically recoverable coal reserves at
Warwick Mine were in excess of 1.5 million tons. The unaffiliated contract
operator at Warwick Mine notified the Company that its financial circumstances
and geologic conditions caused it to cease operations late in 1996. Therefore,
the Company is pursuing its remedies and is currently negotiating to retain an
operator for the mine as a smaller sized operation. Additionally, the Company
will continue to purchase coal on the open market. This change should not impact
the Company's ability to recover all of its investment in Warwick Mine, the $2.6
million of unrecovered system-wide cost of coal which excludes the Bruce
Mansfield Power Station (Bruce Mansfield), or to accrue funds for future
liabilities. It is anticipated that this effort will be successfully completed
by March 31, 2000 when the system-wide coal cost cap expires. 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
$20.2 million toward these costs.
During 1996, 69 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 four long-term contracts in effect at
December 31, 1996 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
10
renewing these contracts as they expire from 1997 through 2002. At December 31,
1996, the Company's wholly owned and jointly owned generating units had on hand
an average coal supply of 45 days.
The PUC has established two market price coal cost standards for the
Company. One applies only to coal delivered at Bruce Mansfield. The other, the
system-wide coal cost standard, applies to coal delivered to the remainder of
the Company's system. Both standards are updated monthly to reflect prevailing
market prices of similar coal. 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.
The PUC allows deferred amounts to be recovered from customers when the
delivered costs of coal fall below such PUC-determined prevailing market prices.
The Company's obligations to pay certain debt service costs associated with the
Bruce Mansfield coal supply will end on January 1, 2000. The Bruce Mansfield
coal cost-capping mechanism does not expire until the recovery of all deferrals
has been resolved. The Company believes that Bruce Mansfield deferrals may
increase through the end of this decade and then be reduced to zero by the end
of the year 2002. The unrecovered cost of Bruce Mansfield coal was $9.6 million
and the unrecovered cost of the remainder of the system-wide coal was $2.6
million at December 31, 1996. The Company believes that all deferred coal costs
will be recovered.
Nuclear Fuel
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The cycle of production and utilization of nuclear fuel consists of (1)
mining and milling of uranium ore and processing the ore into uranium
concentrates, (2) converting uranium concentrates to uranium hexafluoride, (3)
enriching the uranium hexafluoride, (4) fabricating fuel assemblies, (5)
utilizing the nuclear fuel in the generating station reactor and (6) storing and
disposing of spent fuel.
Adequate supplies of uranium and conversion services are under contract
for the Company's requirements for its jointly owned/leased nuclear units
through June and December 1997, respectively. Enrichment services are supplied
under a 1984 United States Enrichment Corporation Utility Services Contract
entered into for a period of 30 years by the Company for joint interests in
Perry Unit 1, BV Unit 1 and BV Unit 2. Under the terms and conditions of this
contract, the Company is committed to 100 percent of its enrichment needs
through 1999; the Company has terminated, at zero cost, all of its enrichment
services requirements for fiscal years 2000 through 2005. The Company continues
to review the need for further enrichment services for the years 2006 through
2014 and may terminate these future years' services under the contract. Fuel
fabrication contracts are in place to supply reload requirements for the next
18-month cycle for BV Unit 1 and BV Unit 2 and the next fifteen 18-month cycles
for Perry Unit 1. The Company will make arrangements for future uranium supply
and related services, as required.
Each utility company is responsible for financing its proportionate
share of the costs of nuclear fuel for each nuclear unit in which it has an
ownership or leasehold interest. The Company's nuclear fuel costs, which are
amortized to reflect fuel consumed, are charged to fuel expense and are
currently recovered through rates. The Company estimates that, over the next
three years, the expenditures for new fuel will exceed the amortization of
nuclear fuel consumed by approximately $4.4 million. The actual nuclear fuel
costs to be financed and amortized will be influenced by such factors as changes
in interest rates; lengths of the respective fuel cycles; reload cycle design;
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.
Nuclear Decommissioning
--------------------------------------------------------------------------------
The PUC ruled that recovery of the decommissioning costs for BV Unit 1
could begin in 1977, and that recovery for BV Unit 2 and Perry Unit 1 could
begin in 1988. 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.
11
Based on site-specific studies finalized in 1992 for BV Unit 2, and in
1994 for BV Unit 1 and Perry Unit 1, the Company's share of the total estimated
decommissioning costs, including removal and decontamination costs, currently
being used to determine the Company's cost of service, is $122 million for BV
Unit 1, $35 million for BV Unit 2, and $67 million for Perry Unit 1. A study
will be performed in 1997 to update the Company's estimated decommissioning
costs of BV Unit 1 and BV Unit 2.
On July 18, 1996, the PUC issued a Proposed Policy Statement Regarding
Nuclear Decommissioning Cost Estimation and Cost Recovery for the purpose of
obtaining comments from the public. The proposed policy includes guidelines for
a site-specific study to estimate the cost of decommissioning. Guidelines
require that studies be performed at least every five years, address
radiological and non-radiological costs, and include a contingency factor of not
more than 10 percent. Under the proposed policy, annual decommissioning funding
levels are based on an annuity calculation recognizing inflation in the cost
estimates and earnings on fund assets. 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, the Company has increased its nuclear decommissioning
funding by $5 million under the PUC-approved plan for the sale of the Company's
ownership interest in Ft. Martin. (See "Mitigation Plan" discussion on page 7.)
These additional annual contributions bring the total annual funding to
approximately $9 million. Also, on October 17, 1996, the PUC adopted an
Accounting Order filed by the Company to recognize the increased funding as part
of the Company's cost of service. The Company expects to receive 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.
The Company records nuclear decommissioning expense under the category
of depreciation and amortization expense and accrues a liability, equal to that
amount, for nuclear decommissioning costs. Funding for nuclear decommissioning
costs is deposited in external, segregated trust accounts and may be invested in
a portfolio of corporate common stock and debt securities, municipal bonds,
certificates of deposit and United States government securities. Trust fund
earnings increase the fund balance and the recorded liability. The market value
of the aggregate trust fund balances at December 31, 1996 totaled approximately
$33.7 million. 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.
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 funds prove insufficient to pay claims, the United
States Congress could impose other revenue-raising measures on the nuclear
industry.
The Company's share of insurance coverage for property damage,
decommissioning and decontamination liability is $1.2 billion. The Company would
be responsible for its share of any damages in excess of insurance coverage. In
addition, if the property damage reserves of Nuclear Electric Insurance Limited
(NEIL), an industry mutual insurance company that provides a portion of this
coverage, are inadequate to cover claims arising from an incident at any United
States nuclear site covered by that insurer, the Company could be assessed
retrospective premiums totaling a maximum of $7.3 million.
In addition, the Company participates in a NEIL program that provides
insurance for the increased cost of generation and/or purchased power resulting
from an accidental outage of a nuclear unit. Subject to the policy limit, the
coverage provides for 100 percent of the estimated incremental costs per week
during the 52-week period starting 21 weeks after an accident and 80 percent of
such estimate per week for the following 104 weeks, 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 $3.5 million.
12
Spent Nuclear Fuel Disposal
--------------------------------------------------------------------------------
The Nuclear Waste Policy Act of 1982 established a 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. On July 23, 1996, the U.S. Court of Appeals for the District of
Columbia Circuit, in response to a suit brought by 25 electric utilities and 18
states and state agencies, unanimously ruled that the DOE has a legal obligation
to begin taking spent nuclear fuel by January 31, 1998. The DOE has not yet
established an interim or permanent storage facility, and has indicated that it
will be unable to begin acceptance of spent nuclear fuel for disposal by January
31, 1998. Further, Congress is considering amendments to the Nuclear Waste
Policy Act of 1982 that could give the DOE authority to proceed with the
development of a federal interim storage facility. In the event the DOE does not
begin accepting spent nuclear fuel, 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 2016 (end of operating license), 2013 and 2011, respectively.
On January 31, 1997, the Company joined 35 other electric utilities and
46 states, state agencies and regulatory commissions in filing a suit in the
U.S. Court of Appeals for the District of Columbia against the DOE. The suit
requests 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. Significant additional expenditures
for the storage of spent nuclear fuel at BV Unit 2 and Perry Unit 1 could be
required if the DOE does not fulfill its obligation to accept spent nuclear
fuel.
Uranium Enrichment Decontamination and Decommissioning
--------------------------------------------------------------------------------
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, 1996, the Company's liability for contributions was approximately
$9.3 million (subject to an inflation adjustment). Contributions, when made, are
currently recovered from electric utility customers through the ECR.
Environmental Matters
--------------------------------------------------------------------------------
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 United States Environmental Protection Agency (EPA) informed the
Company of its potential involvement in three hazardous waste sites. The Company
reached agreements to make de minimus financial payments in 1995 related to two
sites in order to resolve any associated liability. Related to the remaining
site, the Company believes that available defenses, along with other factors
(including overall limited involvement, low estimated remediation costs and
other solvent, potentially responsible parties) will limit any potential
liability that the Company may have for cleanup costs. The Company believes that
any settlement or associated costs related to the remaining site will not have a
materially 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. These applications are
still pending approval. The Company also filed its Title IV Phase II Clean Air
Act compliance plan with the PUC on December 27, 1995.
Although the Company believes it has satisfied all of the Phase I Acid
Rain Program requirements of the Clean Air Act, Phase II Acid Rain Program
requires significant additional reductions of sulfur dioxide (SO\\2) and oxides
of nitrogen (NO\\X) by the year 2000. The Company currently has 662 MW of
nuclear capacity and
13
1,187 MW of coal capacity equipped with SO\\2 emission-reducing equipment
(including 300 MW of property held for future use 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.
In addition to the Title IV Acid Rain Program requirements, the Company
is responsible for additional NO\\X reduction requirements to meet Ozone Ambient
Air Quality Standards under Title I of the Clean Air Act. Flue gas conditioning
and post-combustion NO\\X reduction technologies may be employed if economically
justified. Also, the Company is examining and developing innovative emissions
technologies designed to reduce costs. The Company 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 potential 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. The Company expects the
Pennsylvania Department of Environmental Protection (DEP) to finalize in 1997 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. Since other potential programs are in various stages of
discussion and consideration, it is impossible to make reasonable estimates of
the potential costs and impacts, if any. The Company currently estimates that
additional capital costs to comply with Clean Air Act requirements through the
year 2000 will be approximately $20 million.
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 and Elrama. An Artificial Neural
Network control system enhancement, co-sponsored by the Electric Power Research
Institute and the Company, will be demonstrated at Cheswick. The Gas Research
Institute and the Company are sponsoring a targeted natural gas reburn
demonstration at Elrama. Both demonstrations were initiated in 1996 and will be
completed in 1997.
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 $2.5
million were incurred by the Company in 1996 to comply with these DEP
regulations. Based on information currently available, an additional $2.8
million will be spent in 1997. The additional capital cost of compliance through
the year 2000 is estimated, based on current information, to be $15 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.
Outlook
--------------------------------------------------------------------------------
Competition
The electric utility industry continues to undergo fundamental change
in response to open transmission access and increased availability of energy
alternatives. Under historical PUC ratemaking, 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. As a result of this historical ratemaking
process, utilities have assets recorded on their balance sheets at above-market
costs and have commitments to purchase power at above-market prices (transition
costs).
14
In Pennsylvania, under the Customer Choice Act which became effective
on January 1, 1997, consumers in a utility's traditional franchised territory
will ultimately be able to purchase electricity at market prices from a variety
of electric generation suppliers. 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 price they currently charge
customers. The PUC will determine what portion of a utility's remaining
transition costs will be recoverable from customers through a CTC. This charge
will be paid by consumers who choose alternative generation suppliers as well as
customers who choose their franchised utility. The CTC could last as long as
2005, providing a utility a total of up to nine years to recover transition
costs. An overall four-and-one-half year price cap 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 prices as long as transition costs are being recovered, with
certain exceptions. If a utility ultimately is unable to recover its transition
costs within this pricing structure and timeframe, the costs will be written
off.
The Company has already been effective in mitigating its exposure to
transition costs. As the following table demonstrates, generating plant,
decommissioning and related regulatory asset costs have been reduced by
approximately $400 million during the past two years. These reductions have
resulted from a variety of strategies, such as selling generating assets,
accelerating recovery of fixed costs, increasing nuclear decommissioning charges
and reducing capitalized costs. The Company expects to continue these steps to
address its remaining transition costs. The Customer Choice Act provides another
option to mitigate transition costs. With PUC approval, utilities are permitted
to issue transition bonds with a maturity of 10 years or less. Proceeds can be
used to reduce transition costs. The Company is currently reviewing this
alternative as well as others to further mitigate its transition costs. (See
"Regulation" and "Rate Matters" discussions on pages 1 and 6.)
Potential Transition Costs
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[Download Table]
December 31, January 1,
1996 1995
(Amounts in Millions of Dollars)
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Nuclear plant $ 910.5 $1,149.0
Generation-related regulatory assets 417.9 495.8
BV Unit 2 lease 399.1 401.0
Unfunded generating plant decommissioning 299.5 371.0
Phillips 78.3 78.3
Warwick Mine 15.3 25.0
Purchase power contracts -- --
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Total $2,120.6 $2,520.1
================================================================================
Any estimate of transition costs, including those in the table above,
is forward-looking and is highly dependent on estimates of the future market
prices for electric power. Higher market prices for electricity reduce
transition cost exposure, while lower market prices increase exposure. As part
of its transition filing, the Company is proposing to make a long-term sale of
electricity during the transition period to determine the market rate for power.
In addition to market-related impacts, any estimate of the ultimate level of
transition costs also depends on, among other things, the extent to which such
costs are deemed recoverable by the PUC, the ongoing level of Duquesne's costs
of operations, regional and national economic conditions, and growth of
Duquesne's sales. Duquesne anticipates making its transition filing, including
the identification of potential transition costs, as required by the PUC by
August 1, 1997. The PUC is expected to rule on the Company's ability to recover
these costs through a CTC by May 1, 1998. The Company believes, based upon prior
rulings of the PUC, that it is entitled to recover substantially all of its
transition costs, but cannot predict the outcome of this regulatory process. In
the event that the PUC rules that any or all of these 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. 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.
15
In addition to the mitigation of transition costs, the Company has been
preparing for competition in a variety of ways. In 1989, a holding company
structure was formed to add flexibility to the Company's strategy for managing
assets. With this structure the Company has been able to pursue new business
opportunities that have capitalized on the Company's leadership in engineering,
energy production and the application of technology. The Company's market-driven
businesses have grown in a manner that complements its core business. The
Company has also been building its financial strength through the retirement and
refinancing of long-term debt and the repurchase of stock. In 1995, the
Company's restrictive first mortgage bond indenture was replaced with a new
indenture with more flexible provisions and the Company completed a 3-for-2
stock split. In 1996, the Company issued MIPS to further add to its financial
flexibility and creditworthiness.
Meanwhile, the Company has better positioned its electric utility
business for competition through improving operations and enhancing customer
relations. In recognition of impending industry competition and in an effort to
optimize its generation resources, in 1989 the Company signed a contract with
Delmarva Power for a bulk power sale for a period of 20 years. This initiative
would have resulted in the refurbishment and return to service of the Company's
cold-reserved generating stations. Following the plan's failure to receive
regulatory approval, in 1990 the Company announced a second long-term power sale
initiative to restart these power plants. This plan would have provided
significant impetus to economic development in Pennsylvania as well as providing
the Company's customers with substantial benefits in the form of lower rates.
The Company's efforts to upgrade and maintain the cold-reserved units have
enabled the Company to utilize the BI units to meet peak demand during periods
of extreme weather in recent years and have enabled the BI units to more quickly
return to service as part of the Ft. Martin sale. In 1991, Duquesne reorganized
into strategic business units along market lines and instituted cost reduction
targets for capital, operation and maintenance, and inventory expenditures. As
part of this process, workforce reductions were achieved primarily through
attrition; since 1989 Duquesne has reduced its number of employees by 25
percent. Recently, Duquesne signed a three-year contract extension with its
bargaining unit employees through September 2001. Throughout the period,
Duquesne has been aggressively reducing its fuel costs, achieving a 13 percent
reduction in the unit cost of fuel since 1990. These measures have enabled
Duquesne to reduce its rates by nearly 36 percent, in real terms, since 1990.
When considering the price freeze component of Duquesne's Mitigation Plan,
prices will have declined by nearly 50 percent in real terms during the decade
of the 1990s. From a customer relations standpoint, Duquesne negotiated long-
term contracts with more than 30 key industrial and commercial customers and was
recognized in 1996 for its economic development efforts in attracting major new
industrial expansions. In 1995, Duquesne became one of the first electric
utilities in the country to offer a full customer service guarantee and also
guaranteed to match any competing electricity supplier's price for new
businesses or for the expansion of existing businesses. Duquesne also is
offering to customers increased bill-paying options, including an advanced
technology service that enables customers to electronically receive and pay
their electric bills. This service assists major customers just as its earlier
Electricheck option helped smaller commercial and residential customers.
Additionally, Duquesne will be positioned to offer customers a wide range of new
services with the Customer Advanced Reliability System (CARS). Utility customers
will be linked to CARS by encoder receiver transmitters contained in new or
retrofitted electric meters. Data communications offered by this technology are
expected to result in improved reliability, security, and customer satisfaction.
At the national level, in 1996 the FERC issued two related final rules
that address the terms on which electric utilities will be required to provide
wholesale suppliers of electric energy with non-discriminatory access to the
utility's wholesale transmission system. The first rule, Order No. 888, requires
each public utility that owns, controls or operates interstate transmission
facilities to file a tariff offering unbundled transmission services containing
non-rate terms that conform to the FERC's pro forma tariff. Order No. 888 also
allows full recovery of prudently incurred costs from departing customers. FERC
deferred to state regulators with respect to retail access, recovery of retail
transition costs and the scope of state regulatory jurisdiction. The second
rule, Order No. 889, prohibits transmission owners and their affiliates from
gaining preferential access to information concerning transmission and
establishes a code of conduct to ensure the complete separation of a utility's
wholesale power marketing and transmission operation functions.
Finally, the FERC simultaneously issued a new Notice of Proposed
Rulemaking (NOPR) on Capacity Reservation Open Access Transmission Tariffs
(CRT), which would require all market participants to reserve firm capacity
rights between designated receipt and delivery points. If adopted, the CRT would
replace the open access pro forma tariff implemented in Order No. 888. (See
"Transmission Access" discussion on page 17.)
16
The Company is aware of the foregoing state and federal regulatory and
business uncertainties and is attempting to position itself to effectively
operate in a more competitive environment.
Transmission Access
In March 1994, the Company submitted, pursuant to the Federal Power
Act, two separate "good faith" requests for transmission service with APS and
the Pennsylvania-New Jersey-Maryland Interconnection Association (PJM
Companies). Because of a lack of progress on pricing and other issues, the
Company subsequently filed with the FERC applications for transmission service.
In May 1995, the FERC instructed APS and the PJM Companies to provide
transmission service to the Company and directed the parties to negotiate
specific rates, terms and conditions. No terms were agreed to, and briefs were
filed with the FERC outlining the areas of disagreement. The matter is now
pending before the FERC. In July 1996, the Company filed with the FERC a request
for acceptance of a capacity reservation tariff to replace the previously filed
FERC Order No. 888 pro forma tariff. (See "Competition" discussion on page 14.)
The Company's tariff proposes to adopt marginal cost pricing for transmission
service on the Company's transmission system. In February 1997, the FERC
rejected the Company's tariff filing, but permitted the Company to request a
hearing to determine whether the Company's tariff is just and reasonable as well
as consistent with or superior to the Order No. 888 pro forma tariff. The
Company has requested such a hearing.
The Company is currently evaluating the impact of FERC regulatory
actions on these proceedings. The Company cannot predict the final outcome of
these proceedings.
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. The units continue to
have the capability to operate at 100 percent reactor power although 15 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.
Other
--------------------------------------------------------------------------------
Retirement Plan Measurement Assumptions
The Company increased the discount rate used to determine the projected
benefit obligation on the Company's retirement plans at December 31, 1996 to 7.5
percent. The assumed change in future compensation levels and assumed rate of
return on plan assets were also increased to reflect current market and economic
conditions. The effects of these changes on the Company's retirement plan
obligations are reflected in the amounts shown in "Employee Benefits," Note N to
the consolidated financial statements, on page 57. The resulting change in
related expenses for subsequent years is not expected to be material.
Subsequent Event
The Company signed a sale agreement on March 18, 1997, for the sale of
Chester. In 1996, Chester earned net income of $2.4 million on net revenues of
$31 million. Pursuant to this transaction, the Company will realize proceeds of
approximately $44 million from its investment in Chester. The sale is expected
to close on May 1, 1997.
------------------------------
17
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.
Executive Officers of the Registrant
--------------------------------------------------------------------------------
Set forth below are the names, ages as of March 1, 1997, 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 64 of DQE's Annual Report to Shareholders for the year ended December
31, 1996. The information is incorporated here by reference.
[Enlarge/Download Table]
Name Age Office
----------------- --- --------------------------------------------------------------
David D. Marshall 44 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 51 Executive Vice President and Chief Financial Officer
since February 1995. Vice President from January 1990
to February 1995 and Treasurer from July 1989 to
August 1996.
James D. Mitchell 45 Vice President since February 1995. Assistant
Treasurer from January 1990 to February 1995.
Victor A. Roque 50 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 36 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 42 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.
Dianna L. Green 50 Senior Vice President since April 1996. Senior Vice
President -- Customer Operations of Duquesne
Light Company since April 1995, Senior Vice
President -- Administration from February 1995 to
April 1995, and Vice President -- Administrative
Services from August 1988 to February 1995.
18
[Enlarge/Download Table]
Name Age Office
----------------- --- --------------------------------------------------------------
Jack E. Saxer, Jr. 53 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.
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.
[Download Table]
Company's
Share of Net Plant Output
Capacity Year Ended
(Megawatts) December 31, 1996
Name and Location Type Summer Winter (Megawatt-hours)
----------------- ---- ------ ------ ------------------
Cheswick Coal 562 570 3,101,155
Springdale, Pa.
Elrama Coal 474 487 2,572,107
Elrama, Pa.
Sammis Unit 7 (1) Coal 187 187 1,058,157
Stratton, Ohio
Eastlake Unit 5 (1) Coal 186 186 972,750
Eastlake, Ohio
Beaver Valley Unit 1 (1) Nuclear 385 385 2,713,594
Shippingport, Pa.
Beaver Valley Unit 2 (1) Nuclear 113 113 674,893
Shippingport, Pa.
Perry Unit 1 (1) Nuclear 161 164 1,026,442
North Perry, Ohio
Bruce Mansfield Unit 1 (1) Coal 228 228 965,248
Shippingport, Pa.
Bruce Mansfield Unit 2 (1) Coal 62 62 285,792
Shippingport, Pa.
Bruce Mansfield Unit 3 (1) Coal 110 110 480,342
Shippingport, Pa.
Ft. Martin Unit 1 (2) Coal 276 276 1,215,111
Brunot Island Oil 166 178 (6,846)
Brunot Island, Pa.
----- ----- ----------
Total 2,910 2,946 15,058,745
==========
Property held for future use:
Brunot Island Oil 92 128
Phillips Coal 300 300
----- -----
Total 3,302 3,374
===== =====
(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).
(2) Amount represents the Company's share of the unit, which was sold on October
31, 1996.
19
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, approximately 83 river miles from Pittsburgh. (See
Item 1. BUSINESS "Fossil Fuel" discussion on page 10.)
Additional information relating to Item 2. PROPERTIES, is set forth in
Note D, "Property, Plant and Equipment," on page 45 of this Report. The
information is incorporated here by reference.
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 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. To provide the
parties with the opportunity to settle their claims, the court has postponed
litigation proceedings until April 1, 1997.
Proceedings involving the Company's rates are reported in Item 1.
BUSINESS "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 on page 1 and inside of the back
cover of the DQE Annual Report to Shareholders for the year ended December 31,
1996 and on page 6, page 57 in Note M and page 60 in Note O hereto. The
information is incorporated here by reference. At February 21, 1997, there were
approximately 76,005 holders of record of the Common Stock of DQE.
20
Item 6. Selected Financial Data.
Selected financial data for each year of the eleven-year period ended
December 31, 1996, are set forth on pages 17 and 18 of the DQE Annual Report to
Shareholders for the year ended December 31, 1996. The information is
incorporated here by reference.
Item 7. Management's Discussion and Analysis of Financial Condition and Results
of Operations.
Management's discussion and analysis of financial condition and results
of operations are set forth in Item 1. BUSINESS here on pages 1 through 18 of
this Report. The discussion and analysis are incorporated here by reference.
Item 8. Consolidated Financial Statements and Supplementary Data.
The Consolidated Balance Sheet of DQE and its Subsidiaries as of
December 31, 1996 and 1995, and the related Statements of Consolidated Income,
Retained Earnings and Cash Flows for each of the three years in the period ended
December 31, 1996, together with the Report of Independent Certified Public
Accountants dated January 28, 1997, are set forth here on pages 37 through 60.
The financial statements and report are incorporated here by reference.
Quarterly financial information is included here on page 60 in Note O to the
consolidated financial statements and is incorporated here by reference.
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.
21
Part IV
Item 14. Exhibits, Financial Statement Schedules and Reports on Form 8-K.
(a)(1) The following information is set forth here on pages 37 through
60 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,
1996.
Consolidated Balance Sheet, December 31, 1996 and 1995.
Statement of Consolidated Cash Flows for the Three Years Ended December
31, 1996.
Statement of Consolidated Retained Earnings for the Three Years Ended
December 31, 1996.
Notes to Consolidated Financial Statements.
(a)(2) The following financial statement schedule and the related
Report of Independent Certified Public Accountants (See page 37.) are filed here
as a part of this Report:
Schedule for the Three Years Ended December 31, 1996:
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 on pages 23 through
33, incorporated here by reference. Documents other than those designated as
being filed here are incorporated here by reference. Documents incorporated by
reference to a DQE Annual Report on Form 10-K, a Quarterly Report on Form 10-Q
or a Current Report on Form 8-K are at Securities and Exchange Commission File
No. 1-10290. Documents incorporated by reference to a Duquesne Light Company
Annual Report on Form 10-K, a Quarterly Report on Form 10-Q or a Current Report
on Form 8-K are at Securities and Exchange Commission File No. 1-956. The
Exhibits include the management contracts and compensatory plans or arrangements
required to be filed as exhibits to this Form 10-K by Item 601(10)(iii) of
Regulation S-K.
(b) Reports on Form 8-K filed during the twelve months ended December
31,1996:
(1) May 13, 1996 - The following event was reported by
Duquesne Light Company:
Item 7. Exhibit 12.2 - Statement re: Calculation of Ratio of
Earnings to Combined Fixed Charges and Preferred
and Preference Stock Dividend Requirements.
No financial statements were filed with this report.
22
Exhibit Index
[Enlarge/Download Table]
Exhibit Method of
No. Description Filing
------- ----------------------------------------------------------- ----------------------------
3.1 Articles of Incorporation of DQE effective January 5, 1989. Exhibit 3.1 to the Form 10-K
Annual Report of DQE for the
year ended December 31, 1989.
3.2 Articles of Amendment of DQE effective April 27, 1989. Exhibit 3.2 to the Form 10-K
Annual Report of DQE for the
year ended December 31, 1989.
3.3 Articles of Amendment of DQE effective February 8, 1993. Exhibit 3.3 to the Form 10-K
Annual Report of DQE for the
year ended December 31, 1992.
3.4 Articles of Amendment of DQE effective May 24, 1994. Exhibit 3.4 to the Form 10-K
Annual Report of DQE for the
year ended December 31, 1994.
3.5 Articles of Amendment of DQE effective April 20, 1995. Exhibit 3.5 to the Form 10-K
Annual Report of DQE for the
year ended December 31, 1995.
3.6 By-Laws of DQE, as amended through December 18, 1996 Filed here.
and as currently in effect.
4.1 Indenture dated March 1, 1960, relating to Duquesne Exhibit 4.3 to the Form 10-K
Light Company's 5% Sinking Fund Debentures. Annual Report of DQE for the
year ended December 31, 1989.
4.2 Indenture of Mortgage and Deed of Trust dated as of Exhibit 4.3 to Registration
April 1, 1992, securing Duquesne Light Company's Statement (Form S-3)
First Collateral Trust Bonds. No. 33-52782.
4.3 Supplemental Indentures supplementing the said
Indenture of Mortgage and Deed of Trust -
Supplemental Indenture No. 1. Exhibit 4.4 to Registration
Statement (Form S-3)
No. 33-52782.
Supplemental Indenture No. 2 through Supplemental Exhibit 4.4 to Registration
Indenture No. 4. Statement (Form S-3)
No. 33-63602.
Supplemental Indenture No. 5 through Supplemental Exhibit 4.6 to the Form 10-K
Indenture No. 7. Annual Report of Duquesne
Light Company for the year
ended December 31, 1993.
Supplemental Indenture No. 8 and Supplemental Exhibit 4.6 to the Form 10-K
Indenture No. 9. Annual Report of Duquesne
Light Company for the year
ended December 31, 1994.
23
[Enlarge/Download Table]
Exhibit Method of
No. Description Filing
------- ----------------------------------------------------------- ----------------------------
Supplemental Indenture No. 10 through Supplemental Exhibit 4.4 to the Form 10-K
Indenture No. 12. Annual Report of Duquesne
Light Company for the year
ended December 31, 1995.
Supplemental Indenture No. 13. Exhibit 4.3 to the Form 10-K
Annual Report of Duquesne
Light Company for the year
ended December 31, 1996.
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. Filed here.
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 Filed here.
Subsidiaries. Formerly known as the Duquesne Light
Company Performance Incentive Program.
10.8 Employment Agreement dated as of December 15, Exhibit 10.5 to the Form 10-K
1992 between DQE, Duquesne Light Company and Annual Report of DQE for the
Wesley W. von Schack. year ended December 31, 1992.
24
[Enlarge/Download Table]
Exhibit Method of
No. Description Filing
------- ------------------------------------------------------ ----------------------------
10.9 First Amendment dated as of October 25, 1994 to Exhibit 10.8 to the Form 10-K
Employment Agreement dated as of December 15, Annual Report of DQE for the
1992 between DQE, Duquesne Light Company and year ended December 31, 1994.
Wesley W. von Schack.
10.10 Resignation Agreement between DQE and Duquesne Exhibit 10.1 to the Form 10-Q
Light Company and Wesley W. von Schack. Quarterly Report of DQE for
the quarter ended
September 30, 1996.
10.11 Employment Agreement dated as of August 30, 1994 Exhibit 10.9 to the Form 10-K
between DQE, Duquesne Light Company and Annual Report of DQE for the
David D. Marshall. year ended December 31, 1994.
10.12 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.
10.13 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.
10.14 Non-Competition and Confidentiality Agreement dated Filed here.
as of October 3, 1996 by and among DQE, Inc., Duquesne
Light Company and David D. Marshall, together with a
schedule listing substantially identical agreements
with Dianna L. Green, Victor A. Roque, James D.
Mitchell and James E. Cross.
Material Contracts relating to Duquesne Light Company
Agreements relating to Jointly Owned Generating Units:
10.15 Administration Agreement dated as of September 14, Exhibit 5.8 to Registration
1967. Statement (Form S-7) No. 2-43106.
10.16 Transmission Facilities Agreement dated as of Exhibit 5.9 to Registration
September 14, 1967. Statement (Form S-7)
No. 2-43106.
10.17 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.
10.18 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.
10.19 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.
25
[Enlarge/Download Table]
Exhibit Method of
No. Description Filing
------- ---------------------------------------------------------- ----------------------------
10.20 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.
10.21 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.
10.22 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.
10.23 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.
10.24 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.
10.25 Amendment No. 1 dated December 23, 1993 to Exhibit 10.11 to the Form 10-K
Transmission Facilities Agreement (as of January 1, 1993). Annual Report of Duquesne
Light Company for the year
ended December 31, 1993.
10.26 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.
10.27 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.
10.28 Fort Martin Power Station Asset Purchase Agreement Exhibit 10.17 to the Form 10-K
dated as of November 28, 1995. Annual Report of Duquesne
Light Company for the year
ended December 31, 1995.
Agreements relating to the Sale and Leaseback
of Beaver Valley Unit No. 2:
10.29 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 ended September 30, 1987.
with the sale and leaseback of its interest in Beaver
Valley Unit No. 2.
26
[Enlarge/Download Table]
Exhibit Method of
No. Description Filing
------- -------------------------------------------------------- ----------------------------
10.30 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.
x10.31 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.
y10.32 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.
x10.33 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.
y10.34 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.
x10.35 Amendment No. 2 dated as of November 15, 1992 to Exhibit 10.33 to the Form 10-K
Facility Lease dated as of September 15, 1987 between Annual Report of Duquesne
The First National Bank of Boston, as Owner Trustee Light Company for the year
under a Trust Agreement dated as of September 15, 1987 ended December 31, 1992.
with the limited partnership Owner Participant named
therein, Lessor, and Duquesne Light Company, Lessee.
y10.36 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.
x10.37 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.
27
[Enlarge/Download Table]
Exhibit Method of
No. Description Filing
------- ------------------------------------------------------- ----------------------------
y10.38 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.
x10.39 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.
y10.40 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.
x10.41 Amendment No. 1 dated as of December 1, 1987 to Exhibit 10.34 to the Form 10-K
Participation Agreement dated as of September 15, Annual Report of Duquesne
1987 among the limited partnership Owner Participant Light Company for the year
named therein, the Original Loan Participants listed ended December 31, 1987.
therein, as Original Loan Participants, DQU
Funding Corporation, as Funding Corp, The First
National Bank of Boston, as Owner Trustee, Irving
Trust Company, as Indenture Trustee and Duquesne
Light Company, as Lessee.
y10.42 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.
x10.43 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.
28
[Enlarge/Download Table]
Exhibit Method of
No. Description Filing
------- --------------------------------------------------- ----------------------------
y10.44 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.
x10.45 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.
y10.46 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.
x10.47 Amendment No. 4 dated as of October 13, 1994 to Exhibit 10.35 to the Form 10-K
Participation Agreement dated as of September 15, 1987 Annual Report of Duquesne
among the limited partnership Owner Participant named Light Company for the year
therein, DQU Funding Corporation, as Funding Corp, ended December 31, 1994.
DQU II Funding Corporation, as New Funding Corp,
The First National Bank of Boston, as Owner Trustee,
The Bank of New York, as Indenture Trustee and Duquesne
Light Company, as Lessee.
y10.48 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.
z10.49 Ground Lease and Easement Agreement dated as of Exhibit (28)(e) to Registration
September 15, 1987 between Duquesne Light Company, Statement (Form S-3)
Ground Lessor and Grantor, and The First National Bank No. 33-18144.
of Boston, as Owner Trustee under a Trust Agreement
dated as of September 15, 1987 with the limited
partnership Owner Participant named therein, Tenant
and Grantee.
29
[Enlarge/Download Table]
Exhibit Method of
No. Description Filing
------- ------------------------------------------------------- ----------------------------
z10.50 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.
z10.51 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.
z10.52 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.
z10.53 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.
z10.54 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.
z10.55 Amendment No. 2 dated as of October 13, 1994 to Tax Exhibit 10.43 to the Form 10-K
Indemnification Agreement dated as of September 15, Annual Report of Duquesne
1987 between the Owner Participant named therein and Light Company for the year
Duquesne Light Company, as Lessee. ended December 31, 1994.
z10.56 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.
x10.57 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.
30
[Enlarge/Download Table]
Exhibit Method of
No. Description Filing
------- ------------------------------------------------------ ------------------------------
y10.58 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.
x10.59 Supplemental Indenture No. 1 dated as of December 1, Exhibit 10.45 to the Form 10-K
1987 to Trust Indenture, Mortgage, Security Agreement Annual Report of Duquesne
and Assignment of Facility Lease dated as of September 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 limited partnership Owner
Participant named therein, and Irving Trust Company,
as Indenture Trustee.
y10.60 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.
x10.61 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.
y10.62 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 Light
and Assignment of Facility Lease dated as of September 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.
10.63 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.
10.64 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.
31
[Enlarge/Download Table]
Exhibit Method of
No. Description Filing
------- ------------------------------------------------------ ------------------------------
10.65 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.
x10.66 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.
y10.67 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.
x10.68 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.
y10.69 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.
13.1 Pages 1, 17, 18, 64 and the inside back cover of the DQE Filed here.
Annual Report to Shareholders for year ended
December 31, 1996. 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.
32
[Enlarge/Download Table]
Exhibit Method of
No. Description Filing
------- ------------------------------------------------------ ------------------------------
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 1996 and Security Ownership of DQE
Directors and Executive Officers as of February 21, 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.
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 21,
1997, subject to payment in advance of the cost of reproducing the exhibits
requested.
33
SCHEDULE II
SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS
For the Years Ended December 31, 1996, 1995 and 1994
(Thousands of Dollars)
[Enlarge/Download Table]
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, 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
------- ------- ------ ------- -------
Year Ended December 31, 1994
Reserve Deducted from the Asset
to which it applies:
Allowance for uncollectible accounts $13,688 $12,285 $3,837 (A) $13,988 (B) $15,822
------- ------- ------ ------- -------
Notes: (A) Recovery of accounts previously written off.
(B) Accounts receivable written off.
34
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 25, 1997 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.
[Enlarge/Download Table]
Signature Title Date
--------- ----- ----
/s/ David D. Marshall President, Chief Executive Officer and Director March 25, 1997
------------------------------
David D. Marshall
/s/ Gary L. Schwass Executive Vice President and Chief Financial March 25, 1997
------------------------------ Officer
Gary L. Schwass
/s/ Morgan K. O'Brien Controller and Principal Accounting Officer March 25, 1997
------------------------------
Morgan K. O'Brien
/s/ Daniel Berg Director March 25, 1997
------------------------------
Daniel Berg
/s/ Doreen E. Boyce Director March 25, 1997
------------------------------
Doreen E. Boyce
/s/ Robert P. Bozzone Director March 25, 1997
------------------------------
Robert P. Bozzone
/s/ Sigo Falk Director March 25, 1997
------------------------------
Sigo Falk
/s/ William H. Knoell Director March 25, 1997
------------------------------
William H. Knoell
/s/ Robert Mehrabian Director March 25, 1997
------------------------------
Robert Mehrabian
/s/ Thomas J. Murrin Director March 25, 1997
------------------------------
Thomas J. Murrin
/s/ Eric W. Springer Director March 25, 1997
------------------------------
Eric W. Springer
35
Glossary of Terms Following are explanations of certain financial and
operating terms used in our report.
Competitive Transition Charge (CTC)/
Intangible Transition Charge (ITC)
--------------------------------------------------------------------------------
During the electric utility restructuring from the traditional regulatory
framework to customer choice, utilities will have the opportunity to recover
transition costs from customers through a surcharge, or competitive transition
charge. Alternatively, if the utility gains PUC approval and securitizes
its transition costs, it may then charge an intangible transition charge.
Customer Choice
--------------------------------------------------------------------------------
The Pennsylvania Customer Choice Act (see "Customer Choice Act" discussion
on page 6) will give customers 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, dismantlement, 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.
Demand
--------------------------------------------------------------------------------
Demand is the amount of electricity delivered to consumers at any instant
or averaged over a period of time.
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 and passes to its customers the profits from short-term power
sales to other utilities.
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 natural gas and
electricity.
Kilowatt (KW)
--------------------------------------------------------------------------------
A kilowatt is equal to 1,000 watts. A watt is the rate at which electricity
is generated or consumed. A kilowatt-hour (KWH) is a measure of the quantity
of electricity generated or consumed in one hour.
Peak Demand
--------------------------------------------------------------------------------
Peak demand is the amount of electricity required during periods of highest
usage. Peak periods fluctuate by season and generally occur in the morning
hours in winter and in late afternoon during the summer.
Pennsylvania Public Utility Commission (PUC)
--------------------------------------------------------------------------------
The PUC is the Pennsylvania governmental body that regulates all utilities
(electric, gas, telephone, water, etc.) and is made up of five members
nominated by the governor and confirmed by the senate.
Regulatory Assets
--------------------------------------------------------------------------------
Regulatory assets are costs that the Company would otherwise have charged
to expense which are capitalized or deferred because these costs are currently
being recovered or because it is probable that the PUC and the FERC will
allow recovery of these costs through the ratemaking process. For example,
under traditional regulation, tax benefits associated with electric generating
assets were required to be immediately passed on to a utility's customers.
These same benefits later would be incurred as a tax cost, which the utility
would expect to collect from its customers under the traditional regulatory
framework.
Transition Costs
--------------------------------------------------------------------------------
Transition or 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 and which will remain following mitigation
efforts taken by such utility to recover the costs. Examples of potential
transition costs include regulatory assets; the unfunded portion of
decommissioning costs; costs of employee severance, retraining, early
retirement, and outplacement; and generation-related costs, including the
associated capital costs. The PUC will determine the level of transition
costs a utility may recover.
Unbundled Electric Service
--------------------------------------------------------------------------------
Electric utilities traditionally have been obligated to serve customers
from the generation through the delivery of electricity. Under the Pennsylvania
Customer Choice Act, electric service will be unbundled. Although customer
choice will give consumers their choice of electric generation suppliers,
delivery of the electricity from the generation supplier to the consumer
will remain the responsibility of the existing franchised utility.
36
Report of Independent Certified Public Accountants
To the Directors and Shareholders of DQE:
We have audited the accompanying consolidated balance sheet of DQE and its
subsidiaries as of December 31, 1996 and 1995, and the related consolidated
statements of income, retained earnings, and cash flows for each of the three
years in the period ended December 31, 1996. Our audits also included the
financial statement schedule listed in the Index at Item 14. These financial
statements and financial statement schedule are the responsibility of the
Company's management. Our responsibility is to express an opinion on these
financial statements and financial statement schedule based on our audits.
We conducted our audits in accordance with generally accepted auditing
standards. Those standards require that we plan and perform the audit to obtain
reasonable assurance about whether the financial statements are free of material
misstatement. An audit includes examining, on a test basis, evidence supporting
the amounts and disclosures in the financial statements. An audit also includes
assessing the accounting principles used and significant estimates made by
management, as well as evaluating the overall financial statement presentation.
We believe that our audits provide a reasonable basis for our opinion.
In our opinion, such consolidated financial statements present fairly, in all
material respects, the financial position of DQE and its subsidiaries as of
December 31, 1996 and 1995, and the results of their operations and their cash
flows for each of the three years in the period ended December 31, 1996 in
conformity with generally accepted accounting principles. Also, in our opinion,
such financial statement schedule, when considered in relation to the basic
consolidated financial statements taken as a whole, presents fairly in all
material respects the information set forth therein.
/s/ Deloitte & Touche LLP
DELOITTE & TOUCHE LLP
Pittsburgh, Pennsylvania
January 28, 1997
37
Statement of Consolidated Income
[Enlarge/Download Table]
----------------------------------------------------------------------------------------------------------
(Thousands of Dollars, Except Per Share Amounts)
------------------------------------------------
Year Ended December 31,
----------------------------------------------------------------------------------------------------------
1996 1995 1994
----------------------------------------------------------------------------------------------------------
Operating Sales of Electricity:
Revenues Residential $ 405,392 $ 414,291 $ 401,246
Commercial 489,646 491,789 490,309
Industrial 190,723 190,689 195,852
Provision for doubtful accounts (10,582) (13,430) (11,890)
----------------------------------------------------------------------------------------------------------
Net customer revenues 1,075,179 1,083,339 1,075,517
Utilities 58,292 55,963 58,295
----------------------------------------------------------------------------------------------------------
Total Sales of Electricity 1,133,471 1,139,302 1,133,812
Other 91,724 80,860 90,098
----------------------------------------------------------------------------------------------------------
Total Operating Revenues 1,225,195 1,220,162 1,223,910
----------------------------------------------------------------------------------------------------------
Operating Fuel and purchased power 236,924 231,968 244,135
Expenses Other operating 298,977 292,997 329,177
Maintenance 78,386 81,516 79,488
Depreciation and amortization 222,928 202,558 165,912
Taxes other than income taxes 85,974 88,658 88,331
----------------------------------------------------------------------------------------------------------
Total Operating Expenses 923,189 897,697 907,043
----------------------------------------------------------------------------------------------------------
Operating Operating Income 302,006 322,465 316,867
Income ----------------------------------------------------------------------------------------------------------
Other Income 74,790 52,314 42,924
----------------------------------------------------------------------------------------------------------
Interest and Other Charges 110,270 107,555 110,002
----------------------------------------------------------------------------------------------------------
Income Before Income Taxes 266,526 267,224 249,789
----------------------------------------------------------------------------------------------------------
Income Taxes 87,388 96,661 92,973
----------------------------------------------------------------------------------------------------------
Net Income Net Income $ 179,138 $ 170,563 $ 156,816
==========================================================================================================
Average Number of Common Shares
Outstanding (Thousands of Shares) 77,349 77,674 79,046
==========================================================================================================
Earnings Earnings Per Share of Common Stock $2.32 $2.20 $1.98
Per Share ==========================================================================================================
Dividends Dividends Declared Per Share of Common Stock $1.30 $1.21 $1.13
Declared ==========================================================================================================
See notes to consolidated financial statements.
Statement of Consolidated Retained Earnings
[Enlarge/Download Table]
----------------------------------------------------------------------------------------------------------
(Thousands of Dollars)
------------------------------------------------
1996 1995 1994
----------------------------------------------------------------------------------------------------------
Balance at beginning of year $ 698,986 $ 622,072 $ 554,604
Net income 179,138 170,563 156,816
Dividends declared (100,517) (93,649) (89,348)
----------------------------------------------------------------------------------------------------------
Balance at end of year $ 777,607 $ 698,986 $ 622,072
==========================================================================================================
See notes to consolidated financial statements.
38
Consolidated Balance Sheet
[Enlarge/Download Table]
---------------------------------------------------------------------------------------
(Thousands of Dollars)
---------------------------
As of December 31,
---------------------------
1996 1995
---------------------------------------------------------------------------------------
Assets Current Assets:
Cash and temporary cash investments $ 410,978 $ 24,767
---------------------------------------------------------------------------------------
Receivables:
Electric customer accounts receivable 92,475 103,821
Other utility receivables 22,402 22,441
Other receivables 33,936 25,164
Less: Allowance for uncollectible accounts (18,688) (18,658)
---------------------------------------------------------------------------------------
Receivables less allowance for uncollectible accounts 130,125 132,768
Less: Receivables sold -- (7,000)
---------------------------------------------------------------------------------------
Total Receivables--Net 130,125 125,768
---------------------------------------------------------------------------------------
Materials and supplies (at average cost):
Coal 19,097 25,454
Operating and construction 52,669 53,298
---------------------------------------------------------------------------------------
Total Materials and Supplies 71,766 78,752
---------------------------------------------------------------------------------------
Other current assets 9,359 8,099
---------------------------------------------------------------------------------------
Total Current Assets 622,228 237,386
---------------------------------------------------------------------------------------
Long-Term Investments:
Affordable housing 150,270 116,784
Leveraged leases 134,133 87,834
Other leases 85,893 106,916
Gas reserves 79,916 69,435
Other 68,477 59,947
---------------------------------------------------------------------------------------
Total Long-Term Investments 518,689 440,916
---------------------------------------------------------------------------------------
Property, Plant and Equipment:
Electric plant in service 4,275,110 4,265,161
Construction work in progress 45,059 38,134
Property held under capital leases 99,608 133,381
Property held for future use 190,821 216,633
Other 176,872 92,804
---------------------------------------------------------------------------------------
Gross property, plant and equipment 4,787,470 4,746,113
Less: Accumulated depreciation and amortization (1,969,945) (1,685,877)
---------------------------------------------------------------------------------------
Total Property, Plant and Equipment--Net 2,817,525 3,060,236
---------------------------------------------------------------------------------------
Other Non-Current Assets:
Regulatory assets 636,816 678,700
Other 43,734 41,605
---------------------------------------------------------------------------------------
Total Other Non-Current Assets 680,550 720,305
---------------------------------------------------------------------------------------
Total Assets $ 4,638,992 $ 4,458,843
=======================================================================================
See notes to consolidated financial statements.
39
[Enlarge/Download Table]
---------------------------------------------------------------------------------------
(Thousands of Dollars)
---------------------------
As of December 31,
---------------------------
1996 1995
---------------------------------------------------------------------------------------
Liabilities and Current Liabilities:
Capitalization Notes payable $ 749 $ 35,098
Current maturities and sinking fund requirements 72,831 71,379
Accounts payable 96,230 90,941
Accrued liabilities 58,044 52,063
Dividends declared 28,633 27,825
Other 4,075 9,191
---------------------------------------------------------------------------------------
Total Current Liabilities 260,562 286,497
---------------------------------------------------------------------------------------
Non-Current Liabilities:
Deferred income taxes--net 759,089 801,631
Deferred investment tax credits 106,201 115,760
Capital lease obligations 28,407 34,546
Deferred income 189,293 221,740
Other 240,763 197,973
---------------------------------------------------------------------------------------
Total Non-Current Liabilities 1,323,753 1,371,650
---------------------------------------------------------------------------------------
---------------------------------------------------------------------------------------
Commitments and Contingencies (Notes B through N)
---------------------------------------------------------------------------------------
Capitalization:
Long-Term Debt 1,439,746 1,400,993
---------------------------------------------------------------------------------------
Preferred and Preference Stock of Subsidiaries:
Non-redeemable preferred stock 213,608 63,608
Non-redeemable preference stock 28,997 29,615
---------------------------------------------------------------------------------------
Total preferred and preference stock before deferred
employee stock ownership plan (ESOP) benefit 242,605 93,223
---------------------------------------------------------------------------------------
Deferred ESOP benefit (19,533) (22,257)
---------------------------------------------------------------------------------------
Total Preferred and Preference Stock of Subsidiaries 223,072 70,966
---------------------------------------------------------------------------------------
Common Shareholders' Equity:
Common stock--no par value (authorized--187,500,000
shares; issued--109,679,154 shares) 990,502 997,461
Retained earnings 777,607 698,986
Treasury stock (at cost) (32,406,135 and 32,123,601 shares) (376,250) (367,710)
---------------------------------------------------------------------------------------
Total Common Shareholders' Equity 1,391,859 1,328,737
---------------------------------------------------------------------------------------
Total Capitalization 3,054,677 2,800,696
---------------------------------------------------------------------------------------
Total Liabilities and Capitalization $4,638,992 $4,458,843
=======================================================================================
See notes to consolidated financial statements.
40
Statement of Consolidated Cash Flows
[Enlarge/Download Table]
--------------------------------------------------------------------------------------------------------
(Thousands of Dollars)
------------------------------------
Year Ended December 31,
------------------------------------
1996 1995 1994
--------------------------------------------------------------------------------------------------------
Cash Flows from Net income $ 179,138 $ 170,563 $ 156,816
Operating Principal non-cash charges (credits) to net income:
Activities Depreciation and amortization 222,928 202,558 165,912
Capital lease, nuclear fuel and investment amortization 53,166 38,847 36,320
Deferred income taxes and investment tax credits--net (60,719) (22,120) (11,342)
Phase-in revenues and carrying charges recovered -- -- 28,621
Investment income (16,125) (3,475) (4,227)
Changes in working capital other than cash (1,033) 46,527 (31,891)
Other--net 282 21,151 29,418
--------------------------------------------------------------------------------------------------------
Net Cash Provided from Operating Activities 377,637 454,051 369,627
--------------------------------------------------------------------------------------------------------
Cash Flows from Sale of generating station 169,100 -- --
Investing Capital expenditures (101,150) (94,164) (121,085)
Activities Long-term investments (71,419) (187,719) (66,698)
Proceeds from disposition of investments 17,661 -- --
Payment for purchase of GSF Energy, net of cash acquired (24,234) -- --
Other--net (1,898) (3,854) (12,321)
--------------------------------------------------------------------------------------------------------
Net Cash Used in Investing Activities (11,940) (285,737) (200,104)
--------------------------------------------------------------------------------------------------------
Cash Flows from Issuance of long-term debt 85,000 65,000 114,110
Financing Issuance of preferred stock 150,000 -- --
Activities (Decrease) increase in notes payable (28,637) (20,236) 32,530
Dividends on common stock (100,517) (93,649) (89,348)
Repurchase of common stock (11,717) (21,271) (23,307)
Reductions of long-term obligations:
Preferred and preference stock -- (29,732) (39,958)
Long-term debt (50,812) (56,114) (114,835)
Capital leases (19,326) (26,373) (33,522)
Other--net (3,477) (11,230) 2,631
--------------------------------------------------------------------------------------------------------
Net Cash Provided from (Used in) Financing Activities 20,514 (193,605) (151,699)
--------------------------------------------------------------------------------------------------------
Net increase (decrease) in cash and temporary cash
investments 386,211 (25,291) 17,824
Cash and temporary cash investments at beginning of year 24,767 50,058 32,234
--------------------------------------------------------------------------------------------------------
Cash and temporary cash investments at end of year $ 410,978 $ 24,767 $ 50,058
========================================================================================================
Supplemental Cash Flow Information
--------------------------------------------------------------------------------------------------------
Cash Paid During Interest (net of amount capitalized) $ 95,702 $ 99,954 $ 105,900
the Year --------------------------------------------------------------------------------------------------------
Income taxes $ 91,641 $ 82,884 $ 84,753
--------------------------------------------------------------------------------------------------------
Non-Cash Capital lease obligations recorded $ 13,050 $ 14,961 $ 16,909
Investing Equity funding obligations recorded $ 36,716 $ 21,827 $ --
and Financing Preferred stock issued in conjunction with long-term
Activities investments $ -- $ 3,000 $ --
========================================================================================================
See notes to consolidated financial statements.
41
Notes to Consolidated Financial Statements
A. Summary of
Significant
Accounting
Policies
Consolidation
--------------------------------------------------------------------------------
DQE is an energy services holding company. Its subsidiaries are
Duquesne Light Company (Duquesne), Duquesne Enterprises (DE), DQE Energy
Services (DES), DQEnergy Partners and Montauk. DQE and its subsidiaries are
collectively referred to as "the Company."
Duquesne is an electric utility engaged in the production,
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 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 Partners was formed in December 1996 to
align DQE with strategic partners to capitalize on opportunities in the dynamic
energy services industry. These alliances 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.
Basis of Accounting
--------------------------------------------------------------------------------
The Company is subject to the accounting and reporting requirements of
the United States Securities and Exchange Commission (SEC). In addition, the
Company's electric utility operations are subject to regulation by the
Pennsylvania Public Utility Commission (PUC) and the Federal Energy Regulatory
Commission (FERC) under the Federal Power Act with respect to rates for
interstate sales, transmission of electric power, accounting and other matters.
The Company's consolidated financial statements report regulatory
assets and liabilities in accordance with Statement of Financial Accounting
Standards 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 F, on page
46.)
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
--------------------------------------------------------------------------------
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 on page 43.)
The Company's Electric Service Territory
--------------------------------------------------------------------------------
The Company's utility operations provide electric service to customers
in Allegheny County, including the City of Pittsburgh, Beaver County and
Westmoreland County. This 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.
42
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).
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. (See "Deferred Coal Costs" and "Warwick
Mine Costs" discussions, Note F, on page 48.)
Over- or under-recoveries from customers are recorded in the
consolidated balance sheet as payable to, or receivable from, customers. At
December 31, 1996 and 1995, $1.8 million and $5.8 million were payable to
customers and shown as other current liabilities.
Under the Electricity Generation Customer Choice and Competition Act
(Customer Choice Act), the Company may replace the ECR effective April 1, 1997
by rolling its ECR energy costs into its base rates. The effect of this change
would be to provide to the Company an opportunity to further mitigate its
deferred energy costs based upon its ability to manage its energy costs. Under
the Company's PUC-approved Mitigation Plan, the level of energy cost recovery
is capped at 1.47 cents per kilowatt-hour (KWH) through May 2001. To the extent
that projections do not support recovery of previously deferred costs through
this pricing mechanism, these costs would become transition costs subject to
recovery through a competitive transition charge (CTC). (See "Customer Choice
Act" and "Mitigation Plan" discussions, Note F, on page 46.)
Maintenance
--------------------------------------------------------------------------------
Incremental maintenance expense incurred for refueling outages at
the Company's nuclear units is deferred for amortization over the period between
refueling outages (generally 18 months). The Company accrues, over the periods
between outages, anticipated expenses 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. Depreciation and amortization of
other properties are calculated on various bases.
The Company records 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. (See "Nuclear Decommissioning" discussion, Note J, on page 51.)
The Company's electric utility operations' composite depreciation rate
increased from 3.5 percent to 4.25 percent effective May 1, 1996 and 3.0 percent
to 3.5 percent effective January 1, 1995. Also in 1996, the Company expensed $9
million related to the depreciation portion of deferred rate synchronization
costs in conjunction with the Company's Mitigation Plan.
43
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 F, and "Income
Taxes," Note H, on pages 46 and 49.)
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.
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.
Asset Impairment
--------------------------------------------------------------------------------
The effects of adopting Statement of Financial Accounting Standards
No. 121, Accounting for the Impairment of Long-Lived Assets and for Long-Lived
Assets to Be Disposed Of (SFAS No. 121), on January 1, 1996 did not have a
material impact on the Company's financial position, results of operations or
cash flows, based on the current regulatory structure in which it operates. As
competitive factors influence pricing in the utility industry, this assessment
may change in the future. The general requirements of SFAS No. 121 apply to non-
current assets and require impairment to be considered whenever evidence
suggests that it is no longer probable that future cash flows in an amount at
least equal to the asset book value will result.
Stock-Based Compensation
--------------------------------------------------------------------------------
Statement of Financial Accounting Standards No. 123, Accounting for
Stock-Based Compensation (SFAS No. 123) encourages, but does not require,
companies to record compensation cost for stock-based employee compensation
plans at fair value. The Company has chosen to continue to account for stock-
based compensation using the intrinsic value method prescribed in Accounting
Principles Board Opinion No. 25, Accounting for Stock Issued to Employees, and
related interpretations. Accordingly, compensation cost for stock options is
measured as the excess, if any, of the quoted market price of DQE's stock at the
date of the grant over the amount an 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.
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.
Reclassifications
-------------------------------------------------------------------------------
The 1995 and 1994 consolidated financial statements have been
reclassified to conform with accounting presentations adopted during 1996.
44
B. Receivables
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, 1996. At December 31, 1995, the Company had sold $7
million of receivables to the unaffiliated corporation. The accounts receivable
sales agreement, which expires in June 1997, is one of many sources of funds
available to the Company. The Company has not determined, but may attempt to
extend the agreement or to replace the facility with a similar arrangement or
to eliminate it upon expiration.
C. Changes
in Working
Capital Other
Than Cash
[Download Table]
Changes in Working Capital Other than Cash (Net of GSF Energy Acquisition)
--------------------------------------------------------------------------------
1996 1995 1994
(Amounts in Thousands of Dollars)
--------------------------------------------------------------------
Receivables $ (1,946) $ 34,341 $ 9,928
Materials and supplies 1,286 9,994 2,932
Other current assets (948) 3,126 (25,701)
Accounts payable 4,691 7,087 (4,455)
Other current liabilities (4,116) (8,021) (14,595)
--------------------------------------------------------------------
Total $ (1,033) $ 46,527 $(31,891)
====================================================================
D. Property,
Plant and
Equipment
In addition to its wholly owned generating units, the Company,
together with other electric utilities, 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.
[Enlarge/Download Table]
Generating Units at December 31, 1996
--------------------------------------------------------------------------------------------
Generating Net Utility Fuel
Unit Capability Plant Source
(Megawatts) (Millions of Dollars)
--------------------------------------------------------------------------------------------
Cheswick 570 $ 120.2 Coal
Elrama (a) 487 98.0 Coal
Eastlake Unit 5 186 39.4 Coal
Sammis Unit 7 187 49.5 Coal
Bruce Mansfield Unit 1 (a) 228 65.5 Coal
Bruce Mansfield Unit 2 (a) 62 18.9 Coal
Bruce Mansfield Unit 3 (a) 110 49.8 Coal
Beaver Valley Unit 1 (b) 385 215.9 Nuclear
Beaver Valley Unit 2 (c)(d) 113 14.3 Nuclear
Beaver Valley Common Facilities 153.2
Perry Unit 1 (e) 164 398.5 Nuclear
Brunot Island (f) 178 23.1 Fuel Oil
--------------------------------------------------------------------------------------------
Total 2,670 1,246.3
Property held for future use:
Brunot Island (f) 128 28.5 Fuel Oil
Phillips (a) 300 78.3 Coal
--------------------------------------------------------------------------------------------
Total Generating Units 3,098 $1,353.1
============================================================================================
(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) On October 2, 1987, the Company sold its 13.74 percent interest in Beaver
Valley Unit 2 and leased it back; the sale was exclusive of transmission
and common facilities. 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.
(f) A portion of the proceeds of the sale of the Ft. Martin Power Station is
expected to be used to fund reliability enhancements to the Brunot Island
(BI) Unit 3 combustion turbine. The reliability enhancements are
contingent upon the projects meeting a least-cost test versus other
potential sources of peaking capacity. BI Units 2a and 2b were moved from
property held for future use to electric plant in service in 1996, in
accordance with the Company's Mitigation Plan. (See "Mitigation Plan"
discussion, Note F, on page 46.)
45
E. Long-Term
Investments
The Company makes equity investments in affordable housing and
gas reserve partnerships as a limited partner. At December 31, 1996, the
Company had investments in 26 affordable housing funds and five gas reserve
partnerships. The Company is the lessor in six leveraged lease arrangements
involving mining equipment, rail equipment, a fossil generating station,
a waste-to-energy facility and natural gas processing equipment. These leases
expire in various years beginning in 2004 through 2033. The residual value
of the equipment at the end of the lease terms is approximately 3 percent
of the original cost. The Company's aggregate investment represents 16 percent
of the aggregate original cost of the property and is secured by guarantees
of each lessee's parent of affiliate. The remaining 84 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 $553 million and $364 million at December 31, 1996 and
1995.
[Download Table]
Net Leveraged Lease Investments at December 31
--------------------------------------------------------------------------------
1996 1995
(Amounts in Thousands of Dollars)
--------------------------------------------------------------------------------
Rentals receivable (net of non-recourse debt) $ 215,358 $113,641
Estimated residual value of leased assets 22,029 26,470
Less: Unearned income (103,254) (52,277)
--------------------------------------------------------------------------------
Leveraged lease investments 134,133 87,834
Less: Deferred taxes arising from leveraged leases (59,781) (42,392)
--------------------------------------------------------------------------------
Net Leveraged Lease Investments $ 74,352 $ 45,442
================================================================================
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, primarily of Exide
Electronics Group, Inc. In accordance with Statement of Financial Accounting
Standards 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 losses related to marketable securities at both December 31, 1996
and 1995 was $4.4 million ($2.6 million net of tax). Deferred income primarily
relates to the Company's other lease investments. Deferred amounts will
be recognized as income over the lives of the underlying investments over
periods generally not exceeding five years.
F. Rate Matters
Customer Choice Act
-------------------------------------------------------------------------------
Under the Customer Choice Act, which went into effect on January 1,
1997, Pennsylvania has become a leader in customer choice. The Customer Choice
Act will enable Pennsylvania's electric utility customers to purchase
electricity at market prices from a variety of electric generation suppliers
(customer choice). Electric utility restructuring will be accomplished through a
two-stage process consisting of a pilot period (running through 1998) and a
phase-in period (1999 through 2001). 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 price they currently
charge customers. The PUC will determine what portion of a utility's remaining
transition costs will be recoverable from customers through a CTC. This charge
will be paid by consumers who choose alternative generation suppliers as well as
customers who choose their franchised utility. The CTC could last as long as
2005, providing a utility a total of up to nine years to recover transition
costs. An overall four-and-one-half year price cap 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 prices as long as transition costs are being recovered, with
certain exceptions. If a utility ultimately is unable to recover its transition
costs within this pricing structure and timeframe, the costs will be written
off.
Mitigation Plan
-------------------------------------------------------------------------------
The Company has taken a number of steps to mitigate its potential
transition costs. In addition to the steps taken during the last 10 years to
prepare for competition, effective January 1, 1995, the Company accelerated its
rate of depreciation on its fixed nuclear assets without seeking a rate increase
to recover the additional costs. On October 31, 1996, the sale of the Company's
ownership interest in the Ft. Martin
46
Power Station (Ft. Martin) was completed. Ft. Martin Unit 1 was owned 50 percent
by Duquesne and 50 percent by its operator, Allegheny Power System. The sale and
a plan, to be funded in part by the proceeds of the Ft. Martin transaction, were
approved by the PUC on May 23, 1996. Under the approved plan, the Company will
not increase its base rates for a period of five years through May 2001. In
addition, the Company recorded in October 1996 a one-time reduction of
approximately $130 million in the book value of the Company's nuclear plant
investment. The proceeds from the sale are expected to be used to fund
reliability enhancements to the BI Unit 3 combustion turbine and to reduce the
Company's capitalization. The approved plan also provides for incremental
increases of $25 million in depreciation and amortization expense in 1996, 1997
and 1998 related to the Company's nuclear investment, as well as additional
annual contributions to its nuclear plant decommissioning funds of $5 million,
without any increase in existing electric rates. Also, the Company will record
an annual $5 million credit to the ECR during the plan period to compensate the
Company's electric utility customers for lost profits from any short-term power
sales foregone by the sale of its ownership interest in Ft. Martin. In addition,
the Company will cap energy costs, beginning April 1, 1997 through the remainder
of the plan period, at a historical five-year average of 1.47 cents per KWH. In
accordance with the approved plan, the Company has expensed $9 million related
to the depreciation portion of the deferred rate synchronization costs
associated with Beaver Valley Unit 2 (BV Unit 2) and Perry Unit 1. The Company's
approved plan provides for the amortization of the remaining deferred rate
synchronization costs over a 10-year period. At December 31, 1996, the
unamortized portion of these costs totaled $41.4 million, net of deferred fuel
savings related to the two units. (See "Deferred Rate Synchronization Costs"
discussion on page 48.) Finally, the Company's approved plan also provides for
annual assistance of $0.5 million to low-income customers.
Regulatory Assets
-------------------------------------------------------------------------------
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 "Customer Choice Act" discussion on page 46.) The Company
currently believes its electricity generating assets and related regulatory
assets continue to satisfy these criteria in light of the transition to
competitive generation under the Customer Choice Act. Should any portion of the
Company's electric utility operations be deemed to no longer meet the SFAS No.
71 criteria, the Company may be required to write off any above-market cost
assets, the recovery of which is uncertain, and any regulatory assets or
liabilities for those operations that no longer meet these requirements.
[Enlarge/Download Table]
Regulatory Assets at December 31
----------------------------------------------------------------------------------------------------
1996 1995
(Amounts in Thousands of Dollars)
----------------------------------------------------------------------------------------------------
Regulatory tax receivable (Note H) $394,131 $414,543
Unamortized debt costs (Note K)(a) 93,299 98,776
Deferred rate synchronization costs (see page 48) 41,446 51,149
Beaver Valley Unit 2 sale/leaseback premium (Note I)(b) 30,059 31,564
Deferred employee costs (c) 29,589 31,218
Deferred nuclear maintenance outage costs (Note A) 13,462 6,776
Deferred coal costs (see page 48) 12,191 12,753
DOE decontamination and decommissioning receivable (Note J) 9,779 10,687
Extraordinary property loss (d) - 8,300
Other 12,860 12,934
----------------------------------------------------------------------------------------------------
Total Regulatory Assets $636,816 $678,700
====================================================================================================
(a) 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.
(b) The premium paid to refinance the BV Unit 2 lease was deferred for
amortization over the life of the lease.
(c) Includes amounts for recovery of accrued compensated absences and accrued
claims for workers' compensation.
(d) During the third quarter of 1996, the Company completed recovery of its
investment in Perry Unit 2.
47
Deferred Rate Synchronization Costs
-------------------------------------------------------------------------------
In 1987, the PUC approved the Company's petition to defer initial
operating and other costs of BV Unit 2 and Perry Unit 1. The Company deferred
the costs incurred from November 1987, when the units went into commercial
operation, until March 1988, when a rate order was issued. In its rate order,
the PUC postponed ruling on whether these costs would be recoverable from the
Company's electric utility customers. The Company is not earning a return on the
deferred costs. (See "Mitigation Plan" discussion on page 46.)
Deferred Coal Costs
-------------------------------------------------------------------------------
The PUC has established two market price coal cost standards for
the Company. One applies only to coal delivered at the Bruce Mansfield Power
Station (Bruce Mansfield). The other, the system-wide coal cost standard,
applies to coal delivered to the remainder of the Company's system. Both
standards are updated monthly to reflect prevailing market prices of similar
coal. 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. The PUC allows deferred amounts to
be recovered from customers when the delivered costs of coal fall below such
PUC-determined prevailing market prices.
In 1990, the PUC approved a joint petition for settlement that
clarified certain aspects of the system-wide coal cost standard. The Company has
exercised options to extend the coal cost standard through March 2000. The
unrecovered cost of Bruce Mansfield coal was $9.6 million and $8.4 million, and
the unrecovered cost of the remainder of the system-wide coal was $2.6 million
and $4.4 million at December 31, 1996 and 1995. The Company believes that all
deferred coal costs will be recovered.
Warwick Mine Costs
-------------------------------------------------------------------------------
The 1990 joint petition for settlement also recognized costs at
the Company's Warwick Mine, which had been excluded from rate base since 1981,
and allowed for recovery of such costs, including the costs of ultimately
closing the mine. (See "Deferred Coal Costs" discussion above.) In 1990, the
Company entered into an agreement under which an unaffiliated company will
operate the mine until March 2000 and sell the coal produced. Production began
in late 1990. The contract operator at Warwick Mine notified the Company that
its financial circumstances and geologic conditions caused it to cease
operations late in 1996. Therefore, the Company is pursuing its remedies and is
currently negotiating to retain an operator for the mine as a smaller sized
operation. Additionally, the Company will continue to purchase coal on the open
market. In the past year, the Warwick Mine supplied slightly less than
one-fifth of the coal used in the production of electricity at the Company's
wholly owned and jointly owned plants. This change should not impact the
Company's ability to recover all of its investment in Warwick Mine, the $2.6
million of unrecovered system-wide cost of coal which excludes Bruce Mansfield,
or to accrue funds for future liabilities. It is anticipated that this effort
will be successfully completed by March 31, 2000 when the system-wide coal cost
cap expires.
Costs at the Warwick Mine and the Company's investment in the mine are
expected to be recovered through the cost of coal in the ECR. Recovery is
subject to the system-wide coal cost standard and the cap agreed to as part of
the Company's Mitigation Plan. The Company also has an opportunity to earn a
return on its investment in the mine through the cost of coal during the period
of the system-wide coal cost standard, including extensions. At December 31,
1996, the Company's net investment in the mine was $11.4 million. 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 $20.2 million toward these costs.
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 and
from rate base. In accordance with the Company's Mitigation Plan, 112 MWs
related to BI Units 2a and 2b were moved from property held for future use to
electric plant in service in 1996. The Company expects to recover its
investment in BI Units 3 and 4, which remain in property held for future use
through future electricity sales. The Company believes its investment in BI
will be necessary in order to meet future business needs. A portion of the
proceeds of the sale of
48
Ft. Martin is expected to be used to fund reliability enhancements to the BI
Unit 3 combustion turbine. The reliability enhancements are contingent upon the
projects meeting a least-cost test versus other potential sources of peaking
capacity. (See "Mitigation Plan" discussion on page 46.) The Company is
analyzing the effects of customer choice on its future generating requirements.
The Company is planning to seek recovery of its investment and associated costs
of Phillips through a CTC. In the event that market demand, transmission access
or rate recovery do not support the utilization of these plants, the Company
may have to write off part or all of these investments and associated costs. At
December 31, 1996, the Company's net of tax investment in Phillips and BI held
for future use was $53.6 million and $17.2 million.
G. Short-Term
Borrowing and
Revolving
Credit
Arrangements
At December 31, 1996, the Company had two extendible revolving credit
arrangements, including a $125 million facility expiring in June 1997 and a $150
million facility expiring in October 1997. 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, 1996, there were no short-term borrowings
outstanding. At December 31, 1995, short-term borrowings were $35 million. The
weighted average interest rate applied to such borrowings was 6.5 percent.
H. Income Taxes
The annual federal corporate income tax returns have been audited by
the Internal Revenue Service (IRS) for the tax years through 1992. The tax
years 1993 through 1996 remain subject to IRS review. The Company does not
believe that final settlement of the federal income tax returns for the years
1991 through 1996 will have a materially adverse effect on its financial
position, results of operations or cash flows.
[Enlarge/Download Table]
Deferred Tax Assets (Liabilities) at December 31
-----------------------------------------------------------------------------------------------
1996 1995
(Amounts in Thousands of Dollars)
-----------------------------------------------------------------------------------------------
Investment tax credits unamortized $ 44,067 $ 48,033
Gain on sale/leaseback of BV Unit 2 61,131 64,124
Tax benefit -- long-term investments 174,935 214,089
Other 19,952 41,509
-----------------------------------------------------------------------------------------------
Deferred tax assets 300,085 367,755
-----------------------------------------------------------------------------------------------
Property depreciation (785,950) (871,539)
Regulatory assets (150,346) (172,008)
Loss on reacquired debt unamortized (33,331) (35,340)
Other (89,547) (90,499)
-----------------------------------------------------------------------------------------------
Deferred tax liabilities (1,059,174) (1,169,386)
-----------------------------------------------------------------------------------------------
Net Deferred Tax Liabilities $ (759,089) $ (801,631)
===============================================================================================
[Enlarge/Download Table]
Income Taxes
-------------------------------------------------------------------------------------------------------
1996 1995 1994
(Amounts in Thousands of Dollars)
-------------------------------------------------------------------------------------------------------
Currently payable: Federal $ 103,525 $ 88,866 $ 70,908
State 44,582 29,915 33,407
Deferred -- net: Federal (36,286) (8,649) (13,198)
State (14,874) (5,640) (72,662)
Investment tax credits deferred -- net (9,559) (7,831) (5,982)
Tax rate adjustment -- regulatory tax receivable (a) -- -- 80,500
-------------------------------------------------------------------------------------------------------
Income Taxes $ 87,388 $ 96,661 $ 92,973
=======================================================================================================
(a) During 1994, the statutory Pennsylvania income tax rate was reduced from
12.25 percent to 9.99 percent. This resulted in a net decrease of $80.5
million in deferred tax liabilities and a corresponding reduction in the
regulatory receivable.
49
Total income taxes differ from the amount computed by applying the
statutory federal income tax rate to income before income taxes and before
preferred and preference dividends of subsidiaries.
[Enlarge/Download Table]
Income Tax Expense Reconciliation
------------------------------------------------------------------------------------------------
1996 1995 1994
(Amounts in Thousands of Dollars)
------------------------------------------------------------------------------------------------
Computed federal income tax at statutory rate $ 94,752 $ 95,591 $ 89,524
Increase (decrease) in taxes resulting from:
State income taxes, net of federal income tax benefits 19,310 15,779 (25,516)
Amortization of deferred investment tax credits (9,559) (7,831) (5,982)
Adjustment to regulatory receivable, net of federal tax -- -- 52,325
Revenue requirement adjustment to regulatory taxes -- -- (12,178)
Other (17,115) (6,878) (5,200)
------------------------------------------------------------------------------------------------
Total Income Tax Expense $ 87,388 $ 96,661 $ 92,973
================================================================================================
I. Leases
The Company leases nuclear fuel, a portion of a nuclear generating
plant, certain office buildings, computer equipment, and other property and
equipment.
[Enlarge/Download Table]
Capital Leases at December 31
-----------------------------------------------------------------------------------------------------------------------------------
1996 1995
(Amounts in Thousands of Dollars)
-----------------------------------------------------------------------------------------------------------------------------------
Nuclear fuel $ 79,103 $ 112,573
Electric plant 20,505 20,808
-----------------------------------------------------------------------------------------------------------------------------------
Total 99,608 133,381
Less: Accumulated amortization (47,670) (74,874)
-----------------------------------------------------------------------------------------------------------------------------------
Property Held Under Capital Leases -- Net (a) $ 51,938 $ 58,507
===================================================================================================================================
(a) Includes $2,618 in 1996 and $2,910 in 1995 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
total sales price of $537.9 million was the appraised value of the Company's
interest in the property. 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 of 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, 1996, the deferred balance was
approximately $30.1 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.
These lease-related expenses are charged to operating expenses on the statement
of consolidated income.
50
Summary of Rental Payments
[Download Table]
----------------------------------------------------------------------
1996 1995 1994
(Amounts in Thousands of Dollars)
----------------------------------------------------------------------
Operating leases $ 59,503 $ 57,617 $ 56,437
Amortization of capital leases 19,378 26,705 33,596
Interest on capital leases 3,703 4,332 4,996
----------------------------------------------------------------------
Total Rental Payments $ 82,584 $ 88,654 $ 95,029
======================================================================
[Enlarge/Download Table]
Future Minimum Lease Payments
------------------------------------------------------------------------------------------------------------------------------------
Operating Leases Capital Leases
Year Ended December 31, (Amounts in Thousands of Dollars)
------------------------------------------------------------------------------------------------------------------------------------
1997 $ 58,000 $ 24,186
1998 57,799 11,380
1999 57,757 6,516
2000 57,682 4,166
2001 56,925 2,481
2002 and thereafter 846,851 18,555
------------------------------------------------------------------------------------------------------------------------------------
Total Minimum Lease Payments $1,135,014 $ 67,284
------------------------------------------------------------------------------------------------------------------------------------
Less: Amount representing interest (17,964)
------------------------------------------------------------------------------------------------------------------------------------
Present value of minimum lease payments for capital
leases (a) $ 49,320
====================================================================================================================================
(a) Includes current obligations of $20.9 million at December 31, 1996.
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, 1996, under
subleases of certain corporate office space are approximately $4.5 million in
1997, $4.6 million in 1998 and $18.5 million thereafter.
J. Commitments
and
Contingencies
Construction
-------------------------------------------------------------------------------
The Company estimates that it will spend, excluding AFC and nuclear
fuel, approximately $110 million, $110 million and $95 million for electric
utility construction during 1997, 1998 and 1999. These estimates also exclude
any potential expenditures for reliability enhancements to the BI Unit 3
combustion turbine. (See "Mitigation Plan" discussion, Note F, on page 46.)
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 PUC ruled that recovery of the
decommissioning costs for Beaver Valley Unit 1 (BV Unit 1) could begin in 1977,
and that recovery for BV Unit 2 and Perry Unit 1 could begin in 1988. 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 finalized in 1992 for BV Unit 2, and
in 1994 for BV Unit 1 and Perry Unit 1, the Company's share of the total
estimated decommissioning costs, including removal and decontamination costs,
currently being used to determine the Company's cost of service, is $122
million for BV Unit 1, $35 million for BV Unit 2, and $67 million for Perry
Unit 1. A study will be performed in 1997 to update the Company's estimated
decommissioning costs of BV Unit 1 and BV Unit 2.
51
On July 18, 1996, the PUC issued a Proposed Policy Statement Regarding
Nuclear Decommissioning Cost Estimation and Cost Recovery for the purpose of
obtaining comments from the public. The proposed policy includes guidelines for
a site-specific study to estimate the cost of decommissioning. Guidelines
require that studies be performed at least every five years, address
radiological and non-radiological costs, and include a contingency factor of
not more than 10 percent. Under the proposed policy, annual decommissioning
funding levels are based on an annuity calculation recognizing inflation in the
cost estimates and earnings on fund assets. 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, the Company has increased its nuclear
decommissioning funding by $5 million under the PUC-approved plan for the sale
of the Company's ownership interest in Ft. Martin. (See "Mitigation Plan"
discussion, Note F, on page 46.) These additional annual contributions bring
the total annual funding to approximately $9 million. Also, on October 17,
1996, the PUC adopted an Accounting Order filed by the Company to recognize the
increased funding as part of the Company's cost of service. The Company expects
to receive 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 may be invested in a portfolio of corporate common
stock and debt securities, municipal bonds, certificates of deposit and United
States government securities. Trust fund earnings increase the fund balance and
the recorded liability. The market value of the aggregate trust fund balances at
December 31, 1996 totaled approximately $33.7 million.
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 funds prove
insufficient to pay claims, the United States Congress could impose other
revenue-raising measures on the nuclear industry.
The Company's share of insurance coverage for property damage,
decommissioning and decontamination liability is $1.2 billion. The Company
would be responsible for its share of any damages in excess of insurance
coverage. In addition, if the property damage reserves of Nuclear Electric
Insurance Limited (NEIL), an industry mutual insurance company that provides a
portion of this coverage, are inadequate to cover claims arising from an
incident at any United States nuclear site covered by that insurer, the Company
could be assessed retrospective premiums totaling a maximum of $7.3 million.
In addition, the Company participates in a NEIL program that provides
insurance for the increased cost of generation and/or purchased power resulting
from an accidental outage of a nuclear unit. Subject to the policy limit, the
coverage provides for 100 percent of the estimated incremental costs per week
during the 52-week period starting 21 weeks after an accident and 80 percent of
such estimate per week for the following 104 weeks, 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 $3.5 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 required removal of approximately 15 percent of its steam generator tubes
from service through a process called "plugging." However, BV Unit 1 continues
to have the capability to operate at 100 percent reactor power and has the
ability to return tubes to service by repairing them through a process called
"sleeving." To date, no tubes at either BV Unit 1 or BV Unit 2 have been
sleeved. 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.
52
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
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.
BV Unit 1 completed its 11th refueling outage on May 11, 1996. The
outage lasted 49 days and was the shortest refueling outage in the history of
the unit. During the outage, various inspections of the unit's steam generators
were made, including examinations using a new "Plus Point" probe. As a result
of these inspections, the Company returned to service tubes that had previously
been plugged. Following the refueling outage, 85 percent of the steam generator
tubes were in service, approximately 1 percent more than at the beginning of
the outage.
BV Unit 2 completed its sixth refueling outage on December 16, 1996.
The outage lasted 107 days due to unanticipated repairs to two residual heat
removal pumps and reactor head vent valves. Various inspections of the unit's
steam generators, including inspections using the Plus Point probe, were
completed. Upon completion of the outage, approximately 98 percent of the unit's
steam generator tubes remained in service.
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, which occur at, approximately,
18-month intervals for each unit. The Company will continue to monitor and
evaluate the condition of the BVPS steam generators.
Spent Nuclear Fuel Disposal. The Nuclear Waste Policy Act of 1982
established a 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. On July 23, 1996, the U.S. Court of Appeals for the District of
Columbia Circuit, in response to a suit brought by 25 electric utilities and 18
states and state agencies, unanimously ruled that the DOE has a legal obligation
to begin taking spent nuclear fuel by January 31, 1998. The DOE has not yet
established an interim or permanent storage facility, and has indicated that it
will be unable to begin acceptance of spent nuclear fuel for disposal by January
31, 1998. Further, Congress is considering amendments to the Nuclear Waste
Policy Act of 1982 that could give the DOE authority to proceed with the
development of a federal interim storage facility. In the event the DOE does not
begin accepting spent nuclear fuel, 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 2016 (end of operating license), 2013 and 2011, respectively.
On January 31, 1997, the Company joined 35 other electric utilities
and 46 states, state agencies and regulatory commissions in filing a suit in
the U.S. Court of Appeals for the District of Columbia against the DOE. The
suit requests 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. Significant additional
expenditures for the storage of spent nuclear fuel at BV Unit 2 and Perry Unit
1 could be required if the DOE does not fulfill its obligation to accept spent
nuclear fuel.
Uranium Enrichment Decontamination and Decommissioning. 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
53
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,
1996, the Company's liability for contributions was approximately $9.3 million
(subject to an inflation adjustment). Contributions, when made, are currently
recovered from electric utility customers through the ECR.
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. In 1996, the Financial
Accounting Standard Board issued an exposure draft, Accounting for Certain
Liabilities Related to Closure or Removal of Long-Lived Assets. The primary
effect of this exposure draft would be to change the way the Company accounts
for nuclear and fossil decommissioning costs. The exposure draft calls for
recording the present value of estimated future cash flows to decommission the
Company's nuclear and fossil power plants as an increase to asset balances and
as a liability. This amount is currently estimated to be $299.5 million. The
Company will seek to recover these costs through a CTC.
Guarantees
-------------------------------------------------------------------------------
The Company and the other owners of Bruce Mansfield have guaranteed
certain debt and lease obligations related to a coal supply contract for Bruce
Mansfield. At December 31, 1996 the Company's share of these guarantees was
$20.3 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. (See "Deferred Coal Costs" discussion, Note F, on
page 48.) The minimum future payments to be made by the Company solely in
relation to these obligations are $5.9 million in 1997, $5.6 million in 1998,
$5.3 million in 1999, and $4.2 million in 2000. The Company's total payments
for coal purchased under the contract were $26.9 million in 1996, $28.9 million
in 1995, and $23.3 million in 1994.
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 $2.5 million were
incurred by the Company in 1996 to comply with these DEP regulations. Based on
information currently available, an additional $2.8 million will be spent in
1997. The additional capital cost of compliance through the year 2000 is
estimated, based on current information, to be $15 million. This estimate is
subject to the results of groundwater assessments and DEP final approval of
compliance plans.
Employees
-------------------------------------------------------------------------------
In November 1996, the Company reached an agreement on a three-year
contract extension through September 30, 2001 with the International
Brotherhood of Electrical Workers (IBEW), which represents approximately 2,000
of the Company's employees.
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.
54
K. Long-Term
Debt
The pollution control notes arise from the sale of bonds by public
authorities for the purposes of financing construction of pollution control
facilities at the Company's plants or refunding previously issued bonds. The
Company is obligated to pay the principal and interest on these bonds. For
certain of the pollution control notes, there is an annual commitment fee for
an irrevocable letter of credit. Under certain circumstances, the letter of
credit is available for the payment of interest on, or redemption of, all or a
portion of the notes.
[Enlarge/Download Table]
Long-Term Debt At December 31
---------------------------------------------------------------------------------------------------------------
Principal Outstanding
Interest (Amounts in Thousands of Dollars)
Rate Maturity 1996 1995
---------------------------------------------------------------------------------------------------------------
First mortgage bonds 4.75%-8.75% 1997-2025 $ 853,000 (a) $ 903,000 (b)
Pollution control notes (c) 2009-2030 417,985 417,985
Sinking fund debentures 5% 2010 4,891 5,703
Term loans 6.47%-7.47% 2000-2001 150,000 65,000
Miscellaneous 17,785 13,462
Less: Unamortized debt discount
and premium -- net (3,915) (4,157)
---------------------------------------------------------------------------------------------------------------
Total Long-Term Debt $1,439,746 $1,400,993
===============================================================================================================
(a) Excludes $50.0 million related to current maturities on November 15, 1997.
(b) Excludes $50.0 million related to a current maturity on May 15, 1996.
(c) The pollution control notes have adjustable interest rates. The interest
rates at year-end averaged 3.7 percent in 1996 and 3.9 percent in 1995.
At December 31, 1996, sinking fund requirements and maturities of
long-term debt outstanding for the next five years were $51.1 million in 1997,
$76.3 million in 1998, $81.9 million in 1999, $166.7 million in 2000, and $86.8
million in 2001.
Total interest costs incurred were $103.9 million in 1996, $107.7
million in 1995, and $110.7 million in 1994. Interest costs attributable to
long-term debt and other interest were $99.4 million, $102.4 million and $105.1
million in 1996, 1995 and 1994, respectively. Interest costs incurred also
include $4.5 million, $5.3 million and $5.6 million attributable to capital
leases in 1996, 1995 and 1994, respectively. Of these amounts, $0.8 million in
1996, $1.0 million in 1995, and $0.6 million in 1994 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 ($391.8 million at December 31, 1996) would become
direct obligations of the Company.
At December 31, 1996 and 1995, the Company was in compliance with all
of its debt covenants.
At December 31, 1996, 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 $1,492.5
million. The principal amount included in the Company's consolidated balance
sheet is $1,495.6 million.
55
L. Preferred and
Preference
Stock of Subsidiaries
[Enlarge/Download Table]
Preferred and Preference Stock of Subsidiaries at December 31
-----------------------------------------------------------------------------------------------------
(Shares and Amounts in Thousands)
-----------------------------------------------------
1996 1995
Call Price ----------------------------------------
Per Share Shares Amount Shares Amount
Preferred Stock Series:
3.75% (a) (b) (c) $51.00 148 $ 7,407 148 $ 7,407
4.00% (a) (b) (c) 51.50 550 27,486 550 27,486
4.10% (a) (b) (c) 51.75 120 6,012 120 6,012
4.15% (a) (b) (c) 51.73 132 6,643 132 6,643
4.20% (a) (b) (c) 51.71 100 5,021 100 5,021
$2.10 (a) (b) (c) 51.84 159 8,039 159 8,039
9.00% (d) -- -- 3,000 -- 3,000
8.375% (e) -- 6,000 150,000 -- --
----------------------------------------------------------------------------------------------------
Total Preferred Stock 7,209 213,608 1,209 63,608
----------------------------------------------------------------------------------------------------
Preference Stock Series: (f)
Plan Series A (c) (g) 37.18 817 28,997 834 29,615
----------------------------------------------------------------------------------------------------
Total Preference Stock 817 28,997 834 29,615
----------------------------------------------------------------------------------------------------
Deferred ESOP benefit (19,533) (22,257)
----------------------------------------------------------------------------------------------------
Total Preferred and Preference Stock $223,072 $ 70,966
====================================================================================================
(a) Preferred stock: 4,000,000 authorized shares; $50 par value; cumulative
(b) $50 per share involuntary liquidation value
(c) Non-redeemable
(d) 500 authorized shares; 10 issued $300,000 par value; involuntary
liquidation value $300,000 per share; mandatory redemption beginning
August 2000
(e) Cumulative Monthly Income Preferred Securities, Series A: 6,000,000
authorized shares; $25 involuntary liquidation value
(f) Preference stock: 8,000,000 authorized shares; $1 par value cumulative
(g) $35.50 per share involuntary liquidation value
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, 1996, Duquesne
had made all dividend payments. Preferred and preference dividends of
subsidiaries included in interest and other charges were $12.1 million, $5.9
million and $6.0 million in 1996, 1995 and 1994. Total preferred and preference
stock had involuntary liquidation values of $242,467 and $93,086, which exceeded
par by $28,180 and $28,781 at December 31, 1996 and 1995.
In December 1991, the Company established an Employee Stock Ownership
Plan (ESOP) to provide matching contributions for a 401(k) Retirement Savings
Plan for Management Employees. (See "Employee Benefits," Note N, on page 57.)
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, 1996, $19.5 million of preference stock issued in
connection with the establishment of the ESOP had been offset, for financial
statement purposes, by the recognition of a deferred ESOP benefit. Dividends on
the preference stock and cash contributions from the Company are used to repay
the ESOP note. The Company made cash contributions of approximately $1.4
million for 1996, $1.6 million for 1995, and $2.2 million for 1994. These cash
contributions were the difference between the ESOP debt service and the amount
of dividends on ESOP shares ($2.3 million in 1996 and 1995, and $2.4 million in
1994). 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
56
compensation expense related to the 401(k) plans of $2.3 million in 1996, $2.3
million in 1995, and $1.8 million in 1994. Outstanding preferred and preference
stock is generally callable, on notice of not less than 30 days, at stated
prices plus accrued dividends.
M. Common Stock
[Download Table]
Changes in the Number of Shares of DQE Common Stock Outstanding
-----------------------------------------------------------------------
1996 1995 1994
(Amounts in Thousands of Shares)
-----------------------------------------------------------------------
Outstanding as of January 1 77,556 78,459 79,518
Reissuance from treasury stock 157 83 116
Repurchase of common stock (440) (986) (1,175)
-----------------------------------------------------------------------
Outstanding as of December 31 77,273 77,556 78,459
=======================================================================
The Company has continuously paid dividends on common stock since 1953
and in each of the last 10 years has increased its dividend paid per share. The
Company's annualized dividends per share were $1.36, $1.28 and $1.17 at December
31, 1996, 1995 and 1994. During 1996, the Company paid a quarterly dividend of
$0.32 per share on each of January 1, April 1, July 1 and October 1. The
quarterly dividend declared in the fourth quarter of 1996 was increased from
$0.32 to $0.34 per share payable January 1, 1997.
Dividends may be paid on the Company's common stock to the extent
permitted by law and as declared by its 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. 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 common stockholder'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 to its common
shareholders. No part of the retained earnings of the Company was restricted at
December 31, 1996.
N. 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 $11.9 million for 1996, $6.1 million
for 1995, and $8.9 million for 1994.
57
Funded Status of the Retirement Plans and Amounts Recognized on the Consolidated
Balance Sheet at December 31
[Enlarge/Download Table]
-----------------------------------------------------------------------------------------------------------------------
1996 1995
(Amounts in Thousands of Dollars)
------------------------------------------------------------------------------------------------------------------------
Actuarial present value of benefits rendered to date:
Vested benefits $413,109 $378,344
Non-vested benefits 22,551 19,110
------------------------------------------------------------------------------------------------------------------------
Accumulated benefits obligation based on compensation to date 435,660 397,454
Additional benefits based on estimated future salary levels 61,438 53,757
------------------------------------------------------------------------------------------------------------------------
Projected benefits obligation 497,098 451,211
Fair market value of plan assets 525,871 490,870
------------------------------------------------------------------------------------------------------------------------
Projected benefits obligation under plan assets $ 28,773 $ 39,659
========================================================================================================================
Unrecognized net gain $128,382 $124,794
Unrecognized prior service cost (43,790) (37,535)
Unrecognized net transition liability (13,853) (15,665)
Net pension liability per consolidated balance sheet (41,966) (31,935)
------------------------------------------------------------------------------------------------------------------------
Total $ 28,773 $ 39,659
========================================================================================================================
Assumed rate of return on plan assets 8.25% 8.00%
------------------------------------------------------------------------------------------------------------------------
Discount rate used to determine projected benefits obligation 7.50% 7.00%
------------------------------------------------------------------------------------------------------------------------
Assumed change in compensation levels 5.25% 5.00%
------------------------------------------------------------------------------------------------------------------------
Pension assets consist primarily of common stocks, United States
obligations and corporate debt securities.
Components of Net Pension Cost
[Enlarge/Download Table]
---------------------------------------------------------------------------------------------------------------
1996 1995 1994
(Amounts in Thousands of Dollars)
---------------------------------------------------------------------------------------------------------------
Service cost (benefits earned during the year) $ 12,209 $ 9,953 $ 12,482
Interest on projected benefits obligation 32,597 30,063 28,221
Return on plan assets (58,173) (99,246) 1,967
Net amortization and deferrals 25,312 65,316 (33,783)
---------------------------------------------------------------------------------------------------------------
Net Pension Cost $ 11,945 $ 6,086 $ 8,887
===============================================================================================================
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's 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 1996 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 of
Subsidiaries," Note L, on page 56.)
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's 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 1996, these incentive
targets were not met by the Company's union-represented employees.
58
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, 1996, approximately 3.1
million of these shares were available for future grants.
As of December 31, 1996, 1995 and 1994, active grants totaled
1,698,000; 2,159,000; and 2,118,000 shares. Exercise prices of these options
ranged from $8.2084 to $30.875 at December 31, 1996, and from $8.2084 to $27.625
at December 31, 1995, and from $8.2084 to $23.0833 at December 31, 1994.
Expiration dates of these grants ranged from 1997 to 2006 at December 31, 1996;
from 1997 to 2005 at December 31, 1995; and from 1997 to 2004 at December 31,
1994. As of December 31, 1996, 1995 and 1994, stock appreciation rights (SARs)
had been granted in connection with 984,000; 1,202,000; and 1,190,000 of the
options outstanding. 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. During 1994, 1,254,000 SARs were exercised; 339,000 options were
exercised at prices ranging from $8.2084 to $18.9167; and 80,000 options were
cancelled. Of the active grants at December 31, 1996, 1995 and 1994, 668,000;
929,000; and 918,000 were not exercisable.
Other Post-Retirement Benefits
-------------------------------------------------------------------------------
In addition to pension benefits, the Company provides certain health
care benefits and life insurance for some retired employees. Substantially all
of the Company's full-time employees may, upon attaining the age of 55 and
meeting certain service requirements, become eligible for the same benefits
available to retired employees. Participating retirees make contributions, which
are 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 post-retirement 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.
[Enlarge/Download Table]
Components of Post-Retirement Cost
----------------------------------------------------------------------------------------------
1996 1995
(Amounts in Thousands of Dollars)
----------------------------------------------------------------------------------------------
Service cost (benefits earned during the period) $1,182 $1,315
Interest cost on accumulated benefit obligation 2,046 2,340
Amortization of the transition obligation over 20 years 1,700 1,700
Other (812) (582)
----------------------------------------------------------------------------------------------
Total Post-Retirement Cost $4,116 $4,773
==============================================================================================
The accumulated post-retirement 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.
59
Funded Status of Post-Retirement Plan at December 31
[Enlarge/Download Table]
-----------------------------------------------------------------------------------------------------------------
1996 1995
(Amounts in Thousands of Dollars)
-----------------------------------------------------------------------------------------------------------------
Actuarial present value of benefits:
Retirees $ 8,840 $ 7,359
Fully eligible active plan participants 3,829 3,187
Other active plan participants 26,352 21,935
-----------------------------------------------------------------------------------------------------------------
Accumulated post-retirement benefit obligation 39,021 32,481
Fair market value of plan assets -- --
-----------------------------------------------------------------------------------------------------------------
Accumulated benefit obligation in excess of plan assets $(39,021) $(32,481)
=================================================================================================================
Unrecognized net actuarial gains $ 2,874 $ 8,427
Unrecognized net transition liability (27,198) (28,898)
Post-retirement liability per consolidated balance sheet (14,697) (12,010)
-----------------------------------------------------------------------------------------------------------------
Total $(39,021) $(32,481)
=================================================================================================================
Discount rate used to determine projected benefit obligation 7.50% 7.00%
-----------------------------------------------------------------------------------------------------------------
Health care cost trend rates:
For year beginning January 1 6.96% 8.80%
Ultimate rate in the year 2000 6.00% 5.50%
-----------------------------------------------------------------------------------------------------------------
Effect of a one percent increase in health care cost trend
rates:
On accumulated projected benefit obligation $ 2,920 $ 3,228
On aggregate of annual service and interest costs $ 391 $ 435
-----------------------------------------------------------------------------------------------------------------
O. 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.]
[Enlarge/Download Table]
----------------------------------------------------------------------------------------------------------------------------------
1996 First Quarter Second Quarter Third Quarter Fourth Quarter
----------------------------------------------------------------------------------------------------------------------------------
Operating Revenues (a) $300,518 $293,357 $335,430 $295,890
Operating Income (a) 71,316 67,385 104,891 58,414
Net Income 42,305 38,972 57,412 40,449
Earnings Per Share 0.55 0.50 0.74 0.53
High 31-1/2 28-7/8 28-3/4 30-3/8
Low 27-1/2 25-3/4 27 27
==================================================================================================================================
1995 First Quarter Second Quarter Third Quarter Fourth Quarter
----------------------------------------------------------------------------------------------------------------------------------
Operating Revenues (a) $298,277 $283,372 $347,264 $291,249
Operating Income (a) 80,607 66,870 105,528 69,460
Net Income 40,901 35,685 55,269 38,708
Earnings Per Share 0.52 0.46 0.72 0.50
Stock Price:
High 22-3/8 25 26-5/8 30-3/4
Low 19-5/8 21-5/8 23-1/2 26-1/2
==================================================================================================================================
(a) Restated to conform with presentations adopted during 1996.
60
Dates Referenced Herein and Documents Incorporated by Reference
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