EXHIBIT 99.2
Managing
For The Competitive
Marketplace
New Competitive
Paradigm
Transformational
Restructuring
Increased
Competition
[LOGO OF DQE]
1994
----
Annual Report
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to
--
Shareholders
------------
Traditional
Business
DQE FINANCIAL AND OPERATING HIGHLIGHTS
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Change Change
From From
1994 1993 1993 1992 1992
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Peak Demand 2,535 MW 1.4% 2,499 MW 8.3% 2,308 MW
Duquesne Customer Sales
(millions) 12,122 KWH 2.3% 11,851 KWH 2.4% 11,569 KWH
Operating Revenues (billions) $1.236 3.0% $1.200 3.1% $1.164
Net Income (millions) $156.8 8.9% $144.0 1.8% $141.5
Year-End Shares Outstanding
(millions) 52.3 -1.3% 53.0 -- 53.0
Return on Average Common Equity 12.5% 4.2% 12.0% -3.2% 12.4%
Long-Term Debt (billions) $1.378 -2.8% $1.417 0.3% $1.413
Interest (millions) $104.0 -5.9% $110.5 -10.1% $122.9
Preferred and Preference Dividends
of Subsidiaries (millions) $6.0 -32.6% $8.9 -5.3% $9.4
Net Operating Cash Flow
(millions)(A) $372.9 -3.1% $384.9 -3.1% $397.4
Capital Expenditures and
Other Investments (millions) $187.8 -4.3% $196.3 45.6% $134.8
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MW: Megawatt. A measure of the generating capacity of utility plants, equal to
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1,000 kilowatts.
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KWH: Kilowatt-hour. A measure of the quantity of electricity consumed in one
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hour, equivalent to 1,000 watts consumed for one hour.
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(A): Excludes working capital and other--net changes.
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CONTENTS
On the Cover
The pace of change in the electric utility industry continues to accelerate.
After decades of operating as "traditional" utilities with exclusive
franchises, the industry is entering a period of far-reaching restructuring to
meet the challenges of competition. Emerging from that restructuring will be a
new competitive paradigm--a profoundly different way in which energy companies
like DQE will operate their businesses in the competitive marketplace.
Chairman's Message 2
Wesley W. von Schack discusses how DQE is strategically--and flexibly--
positioned to meet new challenges as the new competitive paradigm emerges.
Managing for the Competitive Marketplace 4
Anticipating and meeting the needs of the customer is fundamental to any
successful business. When your business environment is experiencing rapid
change, as is the energy industry, you must rise above the swirl to find better,
more efficient solutions for your customers. Our people are maintaining high
levels of customer satisfaction as we continue to focus internally on
performance improvement and cost control. The stories of five satisfied
customers demonstrate how we are successfully managing our company for the
competitive marketplace.
1994 Financial Information 9
The company continues to effectively manage its financial position through
continued growth of its diversified operations while maintaining competitive
costs of production in its utility operations. Effective cost controls are in
place while we continue to reduce interest and other charges and maintain a
strong cash flow.
Board of Directors 45
Officers 46
Shareholder Reference Guide Inside Back Cover
[BAR GRAPH APPEARS HERE]
DQE Earnings
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Per Share
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(Dollars per Share)
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Year Dollars
1990 $2.24
1991 $2.50
1992 $2.67
1993 $2.72
1994 $2.98
Earnings per share have increased eight straight years.
[BAR GRAPH APPEARS HERE]
DQE Annualized
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Dividends Per Share
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(Dollars per Share)
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Year Dollars
1990 $1.44
1991 $1.52
1992 $1.60
1993 $1.68
1994 $1.76
Dividend growth has been in the top quartile of the industry.
CORPORATE PROFILE
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DQE is an energy services holding company nationally and regionally recognized
for excellence, quality, integrity and value.
Mission Statement
Our primary focus is to efficiently and effectively satisfy the needs and
requirements of our customers through the commitment and personal involvement of
all employees. DQE will be a profitable diversified entity, dedicated to
supplying low cost, safe and reliable electric energy and pursuing prudent
diversification opportunities related to the core business that benefit our
customers, shareholders and communities.
Subsidiaries
Duquesne Light Company
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Duquesne Light Company, whose origin dates to 1880, is the principal subsidiary
of DQE. Duquesne Light is engaged in the production, transmission, distribution
and sale of electric energy. Its service territory is approximately 800 square
miles in southwestern Pennsylvania, with a population of 1.5 million. In
addition to serving more than 580,000 customers in Allegheny and Beaver
counties, the company sells electricity to other utilities.
Duquesne Enterprises
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Duquesne Enterprises owns Allegheny Development Corporation and Property
Ventures, Ltd., and has substantial equity interest in Chester Environmental,
Inc. These companies are involved in initiatives related to the core business,
including energy and utility services, environmental services, power quality,
and real estate.
Montauk
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Montauk makes both short- and long-term investments and raises capital for its
own purposes and for Duquesne Enterprises.
1994 Results
. Earnings per share were $2.98, an increase of 9.6% over 1993 and our eighth
consecutive yearly increase.
. Duquesne Enterprises and Montauk contributed 32 cents to earnings per share
in 1994, an increase of 146% over the previous year.
. Sales to Duquesne Light's customers were up 2.3% in 1994. The company had a
system peak demand of 2,535 megawatts, its highest ever.
COMMON STOCK TRENDS
Five-Year
Compound
Growth
1994 1993 1992 1991 1990 1989 Rate
Earnings Per Share $ 2.98 $ 2.72 $ 2.67 $ 2.50 $ 2.24 $ 2.03 8.0%
Dividends Paid Per
Share $ 1.68 $ 1.60 $ 1.52 $ 1.44 $ 1.36 $ 1.28 5.6%
Book Value at
Year-End $24.41 $23.21 $22.12 $21.00 $20.07 $19.27 4.8%
Market Price Per Share
High $34 1-2 $37 $32 3-8 $31 $25 1-4 $23 7-8 7.6%
Low $27 5-8 $31 3-8 $26 7-8 $23 5-8 $20 3-8 $17 3-8 9.7%
Year-End $29 5-8 $34 1-2 $32 1-4 $30 5-8 $24 7-8 $23 7-8 4.4%
1
To Our Shareholders
Competition in the electric utility business made a lot of news during the past
year. But the reality of competition was not news to DQE shareholders. The
changing environment for utilities has been a constant theme in my letters to
shareholders for nine years. That's how long we have been preparing ourselves
for competitive markets. Our first major step in meeting marketplace demands
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came with the highly successful Duquesne Plan in 1986. The front cover of our
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annual report that year said: "To become more efficient, more competitive, more
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market-driven, more customer-oriented and more profitable, we are determined to
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evolve and change."
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In 1989, we restructured our traditional business organization with
the formation of DQE as a holding company. As we indicated at the time, our
goal was to create a more flexible and adaptable structure, one that would
enable us to seek opportunities and be proactive in an increasingly
competitive environment. Since then we have continued to see remarkable
change in our business, and the flexibility of DQE has enabled us to add
substantial value.
This year, the solid progress of the various businesses of DQE is
yielding significant contributions to the overall value of the company. The
core business represented by Duquesne Light Company is stable, while new
business opportunities associated with Montauk and Duquesne Enterprises
continue to grow in importance. Last year their contribution grew to more
than 10 percent of the company's earnings, as earnings per share increased
for the eighth consecutive year.
The pace of change for the traditional electric utility industry is
accelerating. Various scenarios for market forces to replace regulation are
being discussed across the country and in our own state of Pennsylvania,
but the public policy that will be implemented to resolve these issues is
far from evident. As a matter of good public policy, we believe we need at
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least two things from federal and state regulators: 1) a clear vision of
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how all customers of the industry can best benefit from competition, and 2)
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a transition plan that is fair to customers and shareholders and does not
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suddenly change long-established ground rules.
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We support a regulatory vision that allows all of our retail customers
to benefit from the lower prices that inevitably will result from vigorous
wholesale competition. The first step toward this goal is access to the
transmission network at non-discriminatory price and service levels. This
cost-based service must be comparable to what transmission owners provide
for themselves in order to ensure economically efficient investment
decisions will be made for future generation options.
In addition, prudent investments that were made by regulated companies
under their clear legal obligation to provide service will have to be
recognized as legitimate system costs. These costs should be shared by all
electricity users, regardless of future sources of competitively priced
power. As retail customers gain more choice in their competitive purchasing
options, electric utility responsibilities will shift from an absolute
obligation to service any request for power to an obligation only to
deliver available power at competitively determined prices. Any investments
in new generation plants, whether by utility or non-utility developers,
would be supported by market determined prices regardless of the ultimate
costs of these new power sources.
The flexibility offered by DQE and the changes being made in Duquesne
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Light will help keep us positioned for such a future. Duquesne Light's
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strategy to succeed in a competitive marketplace is characterized by three
elements. First, the quality of our service continues to deliver
significant value to customers. This is evident in system performance,
2
[BOX WITH REVERSE TYPE APPEARS HERE]
"Despite the uncertainty created by change in the industry, all of our people
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have continued in their dedication to providing our customers with the highest
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level of satisfaction. These are strengths that we can continue to count on."
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where Duquesne Light's service reliability is the best in the state, and in
the feedback our people receive from customers, who give the company
extremely high customer satisfaction ratings. Second, we are continuing to
restructure Duquesne Light. Over the past five years, we have implemented
quality management initiatives, such as benchmarking and reengineering, to
improve the competitiveness of production and delivery costs. Our
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competitive cost of production has resulted in increased sales to the
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wholesale power market. Twenty-one percent of our total sales are to other
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utilities. We currently are petitioning the Federal Energy Regulatory
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Commission to open access to the regional transmission system, and believe
this will further help us to sell energy into wholesale markets. Third, we
also have developed innovative pricing flexibility to attract new
industrial customers and to maintain our competitiveness with large
industrial customers who add incremental load.
Montauk, a financial services company, has continued to grow with
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selective investments and projects that are related to our core business.
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Our strategy has been to develop an investment portfolio that provides
excellent returns, geographical diversity, and a mix of assets. We have
pursued selective investments and focused only on opportunities where we
have direct knowledge and experience. We remain committed to this
investment philosophy.
Duquesne Enterprises owns a majority interest in Chester Environ-
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mental, a leader in the water quality management industry. Last year
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Chester won new contracts to provide consulting and engineering services to
major municipal and industrial clients in the People's Republic of China,
Mexico and Taiwan. We expect that demand for these services will continue
to increase. In early 1995, we also saw our investment in International
Power Machines enhanced by its merger with Exide Electronics. We now are a
major shareholder of Exide Electronics, a dominant player in the power
management and protection industry.
Over the last ten years, we have systematically assembled a strong
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management team. Many of these individuals come from industries other than
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our own and bring fresh ideas to the challenge of competitive markets.
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Despite the uncertainty created by change in the industry, all of our
people have continued in their dedication to providing our customers with
the highest level of satisfaction. These are strengths that we can continue
to count on.
Thank you, our shareholders, for your confidence and support.
On behalf of the Board of Directors,
/s/ Wesley W. von Schack
Wesley W. von Schack
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Chairman and Chief Executive Officer
February 17, 1995
3
Managing For The Competitive Marketplace
Anticipating and meeting customer needs is fundamental to any successful
business. When your business environment is experiencing rapid change, as is the
energy industry, you must rise above the swirl to find better, more efficient
solutions for your customers. DQE serves diverse markets, both traditional and
emerging. In 1994, our principal subsidiary, Duquesne Light, maintained high
levels of customer satisfaction as its people continued to focus internally on
performance improvement and cost control. Our other subsidiaries proved their
worth in their markets. The following stories of five satisfied customers
demonstrate how we are successfully managing for the competitive marketplace.
[BOX WITH REVERSE TYPE AND PHOTO OF PETER R. GILEZAN APPEARS HERE]
"Chester Environmental's excellent work has led us to use them time and again
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to design and engineer our wastewater treatment plants. These plants employ the
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latest technology and have a superb compliance record. Some are `firsts' in our
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industry." Peter R. Gilezan, Director, Environmental and Energy Affairs,
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Chrysler Corporation.
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Peter Gilezan's challenge to Chester Environmental was a major one. Chrysler
de Mexico planned to build a new Dodge Ram assembly plant in the desert
southwest of Monterrey, at Saltillo. The size of the plant and the limited
availability of water meant that Chester was asked to design and build one of
the world's largest zero-discharge water and wastewater treatment facilities.
This task was made more formidable by a six-month schedule for completion.
Chrysler was confident Chester would be up to the challenge because it had
earned the company's preferred supplier rating five out of the six previous
years and a Quality Excellence Award given to less than 3% of Chrysler's
suppliers. That award is a key measure of demonstrated commitment to excellence
in a supplier's products and services.
Chester delivered again at the Saltillo plant--successfully fulfilling the
largest contract in its 80-year history--by designing and overseeing
construction of a totally integrated system. The Chester solution maximizes use
of wastewater, supplemented by makeup water from a private well. Drinking and
industrial process water is chemically and biologically treated, filtered by
advanced membrane systems, and then reused in production facilities. Sanitary
wastewater similarly is recycled for irrigating the grounds around the plant.
Chrysler is just one of a long list of Fortune 500 companies to which Chester
provides environmental engineering and scientific consulting services. Its
growing list of international clients features projects in Australia, Poland,
Taiwan and China.
We acquired a controlling interest in Chester Environmental in 1993. Chester's
activities are closely related to our core business. Our association with
Chester is a sound investment in a growing company, and it reinforces our own
long-term commitment to the environment.
Environmental management and control is a subject we know well. Our
environmental record and expertise are competitive advantages, especially as
other energy companies attempt to come to grips with compliance deadlines for
new environmental regulations.
Because of Duquesne Light's pioneering efforts in pollution control
technology, the average sulfur dioxide (SO\\2\\) emission rate for our
Pennsylvania coal-burning units already is lower than the Clean Air Act requires
to meet its 1995 and 2000 standards. With more than
4
[BOX WITH REVERSE TYPE AND PHOTO OF MATTHEW W. BOTSFORD, JR. APPEARS HERE]
"The key to any successful relationship begins with the word `we.' `We are in
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this together' summarizes the WorldClass belief that close and open cooperation,
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working toward utilizing today's extraordinary technical advances in pursuing
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win/win solutions, defines the parameters of a dynamic partnership. WorldClass
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shares such a partnership with Duquesne Light."--Matthew W. Botsford, Jr., Chief
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Executive Officer, WorldClass Processing, Inc.
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$600 million already invested in clean air, we have relatively small capital
requirements to meet additional SO\\2\\ and nitrogen oxide standards, while
other energy providers across the country are facing much more significant
expenditures.
Our commitment to the environment takes many forms.
. A comprehensive, systematic, environmental strategic plan that addresses
compliance, training, issues management, stewardship and communications.
. Environmental awareness training for all Duquesne Light people that connects
practically to their lives and to the more than 300 environmental regulations
that govern the company's day-to-day operations.
. A variety of stewardship programs, including collaborative efforts with the
Western Pennsylvania Conservancy, American Forests, the Audubon Society, the
Pennsylvania Environmental Council, the National Tree Trust, Allegheny County,
and the American Legion. These and other programs educate elementary students,
high school students, Boy Scouts and Girl Scouts about the importance of
environmental preservation; foster the collection of recyclable materials;
improve land use through environmental planning and wildlife habitat
development; and help small businesses comply with new environmental
regulations. Various of these activities have received special commendations
from Allegheny County and the Pennsylvania Legislature.
. The Three Rivers Environmental Awards, which pay tribute to individuals and
organizations in western Pennsylvania that demonstrate environmental excellence,
leadership and accomplishment. This recognition encourages others in the
community to emulate these achievements.
With all of our customers, we strive to build the type of partnership Matt
Botsford describes. Whether helping a major customer like WorldClass Processing
to expand its operations, introducing food service providers to a new, more
efficient electrotechnology, or helping local hospitals reduce their medical
waste disposal costs through another new electrotechnology, we are committed to
helping our customers improve their competitiveness through increased use of
electricity.
The WorldClass Processing story began in the early 1990s, when a group of
investors was seeking a location for a steel processing plant. Our economic
development team provided potential site locations and assisted in securing low-
cost state funding to finance infrastructure improvements. We also provided
competitively priced power through our special economic development rider,
designed to encourage business expansion and job creation. The plant has been a
successful processer of hot-rolled steel coils for major steel producers and
their customers.
A decade earlier, steel manufacturing and processing represented 30% of the
record 13.6 billion kilowatt-hours (KWH) of electricity we sold to retail
customers. With the shakeout of the local steel industry, that share declined to
just 15% of the 11 billion KWH sold in 1985, an unprecedented
5
[BOX WITH REVERSE TYPE AND PHOTO OF MILTON A. WASHINGTON APPEARS HERE]
"It's so easy to take electrical power for granted. But if you flip the switch
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to start production and nothing happens, then the loss of power means more than
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a machine not working. It means income is lost. One of Duquesne Light's
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strengths is its quality production of power, which helps to create world
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competitive businesses."
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-Milton A. Washington,
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Chairman,
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SSM Industries, Inc.
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drop of almost 60% in just four years. Pittsburgh in the 1990s features a more
diverse economy, based on small manufacturing, financial and medical services,
advanced technology enterprises and a world-class university system. However,
steel remains an important contributor to the local economy--13% of our 1994
sales of 12.1 billion KWH.
In 1994, WorldClass announced plans to build the first new steel mill in this
area since World War II. The $440 million mini-mill, scheduled for construction
in four phases over the next three years, will enable WorldClass to produce a
variety of specialized steels and offer a wider range of services to larger
mills.
The reliability of our power, and our commitment to deliver it at a
competitive price, were critical components in the WorldClass decision to
expand. We recognize that in today's economy, many of our customers face intense
competition worldwide. One of our major goals with these customers is to
structure their rates in a way that enables them to compete in global markets.
We're also helping businesses of all sizes by providing electric options to
increase their efficiency and competitiveness. For example, we introduced local
food service providers to the benefits of the flash bake oven. This new
technology uses a combination of intense visible light and infrared energy to
cook foods almost instantly from the outside in and the inside out. Restaurants,
convenience stores, supermarkets and movie theaters now can serve a wider range
of foods better, faster and more profitably.
New electrotechnologies also can reduce disposal costs for infectious medical
waste from hospitals and other facilities. Safely sterilizing this waste on-site
reduces the cost to bury the material in special landfills. For the past two
years, we have cosponsored educational symposiums that introduced hospital
administrators to this technology. In conjunction with a national utility
research group, we plan to open a demonstration site at a local hospital in mid-
1995.
As chairman of one of the top ten sheet metal producers in the United States,
Milt Washington values the reliable electric service we provide. It enables SSM
Industries to use innovative technology to fabricate a wide range of products
from diverse metals.
We take great pride in our record of reliability. In fact, independent surveys
show that we have the highest level of service reliability in Pennsylvania.
Our commitment to reliability was tested in 1994. In January, a record-setting
freeze put electric power in short supply throughout most of the northeastern
United States and many utilities imposed rolling blackouts. In June, a heat wave
pushed customer demand to a new all-time system high--2,535 megawatts. In both
cases, we delivered safe and reliable electric energy. Pennsylvania Public
Utility Commissioner John Hanger gave Duquesne Light's January performance high
praise, saying it was "at the top of all utilities in the state."
That performance is a result of the dedication and the skill of line workers,
customer service representatives, and the people in our System Operations and
Distribution Operations centers. The people in our
6
[BOX WITH REVERSE TYPE AND PHOTO OF BETTY PICKETT APPEARS HERE]
"I've lived in Pittsburgh for 17 years and I've never had to call Duquesne Light
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concerning my electricity. I think that's quite a record for reliability and
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efficient customer service."
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- Betty Pickett,
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Duquesne Light
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residential customer.
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power stations play a particularly important role in providing reliable power to
both local customers, like SSM Industries, and to utility companies in other
parts of the country.
Our available capacity is one of our key assets and an important competitive
advantage for the future. Our generating stations--the source of that power--
performed well in 1994. Beaver Valley Power Station achieved the highest
combined capacity factor--a key production measure--in the history of the
station. Cheswick Power Station achieved its highest capacity factor in 24 years
of operation.
Reliable energy is a major consideration for companies planning an expansion
or selecting a location for a new plant. With increased computerization, more
and more customers want added protection to ensure an uninterrupted flow of
power.
For that reason, we made a strategic investment several years ago in
International Power Machines, a world-wide supplier of power protection for
computer applications, telecommunications systems and industrial process
control. That investment will be enhanced by IPM's merger with Exide
Electronics. Exide is the largest company in the world dedicated exclusively to
developing, manufacturing and servicing a full line of power management and
power protection systems. Its customers include AT&T, IBM, the Federal Aviation
Administration and the Department of Defense.
As both a homeowner and a regional executive director of The National
Conference of Christians and Jews, Betty Pickett appreciates not having to worry
about her electric service. She can remember only three times when her home was
without electricity during 17 years. Each outage was brief and storm-related.
There are several good reasons why Betty never had to call us.
. Our customers have the most reliable electric service in Pennsylvania; 99.99
percent have full power at any given time.
. Our distribution system's remote switching devices isolate problems and
allow us to resolve most service interruptions within 15 minutes.
. Most service interruptions requiring an "in-the-field" response are resolved
within two hours.
Reliability is just one facet of our strong customer satisfaction record.
. Customers who do need to call us (we received more than one million calls in
1994) are connected with a service representative within 13 seconds, on average.
. Our billing accuracy is 99.95 percent. That's an average of one billing
error every seven customer lifetimes.
. The average time required to connect a new residential service is now 24
hours.
Independent surveys continue to prove that customers are very satisfied. They
give us particularly high ratings for reliability, courteous employees and
accurate billings.
We are taking significant steps behind the scenes to streamline our internal
processes to further improve service and cut costs. Increased use of
microprocessors, first introduced in 1985 for meter reading, is improving
productivity in a number of functions. Expansion of the multicrafting concept
for our field workers--consolidating job descriptions and training our people
to handle a wider number of assignments--is helping
7
[BOX WITH REVERSE TYPE AND PHOTO OF ROBERT LAWYER APPEARS HERE]
"The Smart Comfort Program has helped my wife and me so much, especially since
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we're on a fixed income. It's cut our bill by more than a third, and it's made
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us more conscious of how we use electricity."
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--Robert Lawyer,
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Duquesne Light
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residential customer.
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us build a more flexible and responsive workforce. A new way of scheduling
substation maintenance is reducing operating costs while maintaining
reliability.
Our companywide focus on customer satisfaction, quality service and cost
reduction is driving continuous improvement in operations, positioning us to
be even more competitive in a changing marketplace.
Robert Lawyer and his wife, Mary Lou, have had to make a number of adjustments
since illness forced him to retire early from his job as a machine shop
supervisor. Robert called to inquire about our award-winning Smart Comfort
program, which helps customers in need take better control of their electric
costs by developing more efficient energy-use habits.
Traditional residential conservation programs focus on the house's outer
shell. We've turned that approach inside out. Rather than looking only at
heating, windows and insulation, we explore electric use from the customer's
perspective. How does the household use lights and appliances?
The core of the program is an in-person analysis of the customer's monthly
bill. Working with the Lawyers, we were able to pinpoint several areas in their
trailer home where high usage could be reduced. Major improvements included
placing an insulation wrap on their electric water heater, lowering the hot-
water temperature to 120 degrees, replacing their old, inefficient refrigerator,
and replacing incandescent recessed lights in the kitchen with more efficient
compact fluorescent lamps.
Robert thinks so highly of Smart Comfort that he's told many of his friends
about it. He even competes with a friend who has achieved similar benefits from
the program. They compare bills each month to see who has been the most
efficient.
Smart Comfort has helped thousands of customers. The payback period for
program expenses is nearly half the industry's seven-year standard. Smart
Comfort has been recognized by the U.S. Department of Energy, the Pennsylvania
Governor's Energy Office and the Edison Electric Institute for its innovative
program design and delivery.
Additional programs and activities to benefit the communities we serve are
logical outgrowths of Smart Comfort and other services for customers with
special needs. With service ties to the Pittsburgh area dating back nearly 115
years, we are a committed community partner.
Education is a top priority because it will help ensure that the workforce of
the future has the skills and knowledge necessary for the 21st century. We have
particularly close ties with seven local school districts through our "Partners
in Education" program. In addition to providing cultural experiences for
children, the partnership program has been instrumental in increasing
involvement of students--particularly minorities and females--in math and
science.
We are proud of our voluntary service to the community and we strongly
encourage our people to get involved. Last year, our people collectively
contributed almost 100,000 hours of volunteer services, helping a wide variety
of community, health, environmental and human services organizations.
8
DQE 1994 Financial Information
Company Report on Financial Statements
The Company is responsible for the financial information and representations
contained in the financial statements and other sections of this annual report
to shareholders. The Company believes that the consolidated financial
statements have been prepared in conformity with generally accepted accounting
principles that are appropriate in the circumstances to reflect, in all
material respects, the substance of events and transactions that should be
included in the statements and that the other information in the annual report
to shareholders is consistent with those statements. In preparing the financial
statements, the Company makes informed judgments and estimates based on
currently available information about the effects of certain events and
transactions. The Company maintains a system of internal accounting control
designed to provide reasonable assurance that the Company's assets are
safeguarded and that transactions are executed and recorded in accordance with
established procedures. There are limits inherent in any system of internal
control and such limits are based on recognition that the cost of such a system
should not exceed the benefits derived. The system of internal accounting
control is supported by written policies and guidelines and is supplemented by
a staff of internal auditors. The Company believes that the internal accounting
control system provides reasonable assurance that its assets are safeguarded
and the financial information is reliable.
/s/ Wesley W. von Schack
Wesley W. von Schack
Chairman of the Board, President
and Chief Executive Officer
/s/ Gary L. Schwass
Gary L. Schwass
Executive Vice President,
Chief Financial Officer and Treasurer
Contents
Glossary of Terms
10
Management's Discussion
and Analysis
Results of Operations
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11
Capital Resources
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and Liquidity
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14
Generating Units
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15
Outlook
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16
Report of
Independent Accountants
20
Statement of Consolidated
Income
21
Consolidated Balance Sheet
22
Statement of Consolidated
Cash Flows
24
Notes to Consolidated
Financial Statements
25
Selected Financial Data
43
Selected Operating Data
44
9
Glossary of Terms
Following are explanations of certain financial and operating terms used in our
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report and unique in our core business.
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Allowance for Funds Used During Construction (AFC)
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AFC is an amount recorded on the books of a utility during the period of
construction of utility assets. The amount represents the estimated cost of
both debt and equity used to finance the construction.
Construction Work In Progress (CWIP)
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This amount represents utility assets in the process of construction but not
yet placed in service. The amount is shown on the consolidated balance sheet
as a component of property, plant and equipment.
Deferred Energy Costs
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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 electric utility customers.
Demand
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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.
Equivalent Availability Factor
--------------------------------------------------------------------------------
The percent of generating capacity available for service, whether operated
or not.
Federal Energy Regulatory Commission (FERC)
--------------------------------------------------------------------------------
FERC is an independent five-member commission within the U.S. Department of
Energy. Among its many responsibilities, FERC sets rates and charges for the
wholesale transportation and sale of natural gas and electricity, and the
licensing of hydroelectric power projects.
Kilowatt (KW)
--------------------------------------------------------------------------------
A kilowatt is a unit of power or capacity. A kilowatt hour (KWH) is a unit of
energy or kilowatts times the length of time the kilowatts are used. For
example, a 100-watt bulb has a demand of .1 KW and, if burned continuously,
will consume 1 KWH in ten hours. One thousand KWs is a megawatt (MW). One
thousand KWHs is a megawatt hour (MWH).
Nuclear Decommissioning Costs
--------------------------------------------------------------------------------
Decommissioning costs are expenses to be incurred in connection with the
entombment, decontamination, dismantlement, removal and disposal of the
structures, systems and components of a nuclear power plant that has
permanently ceased the production of electric energy.
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 Pennsylvania governmental body that regulates all utilities (electric, gas,
telephone, water, etc.), which is made up of five members nominated by the
governor and confirmed by the senate.
Regulatory Asset
--------------------------------------------------------------------------------
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 FERC will allow recovery of these costs
through the ratemaking process.
Retail Access
--------------------------------------------------------------------------------
The ability of end-use consumers to individually contract for electrical energy
from competing generation suppliers.
Scrubbed Capacity
--------------------------------------------------------------------------------
Fossil fuel fired generating capacity equipped with sulphur dioxide (SO//2//)
emission reducing equipment.
10
Management's Discussion and Analysis of
Financial Condition and Results of Operations
Corporate Structure
-------------------
DQE is an energy services holding company. Its subsidiaries are Duquesne Light
Company (Duquesne), Duquesne Enterprises (DE) and Montauk. DQE and its
subsidiaries are collectively referred to as the Company.
Duquesne, the principal subsidiary, is an electric utility engaged in the
production, transmission, distribution and sale of electric energy. DE is
involved in initiatives related to the core business; these include providing
all the energy services for the Pittsburgh International Airport, providing
environmental consulting and engineering services, providing power quality
management, and investing in real estate. Montauk makes both short- and
long-term investments and raises capital for DE and for its own purposes.
Results of Operations
---------------------
Operating Revenues
--------------------------------------------------------------------------------
The Company sells electricity to approximately 580,000 ultimate customers
within its service territory of approximately 800 square miles in
Southwestern Pennsylvania and, on a short-term basis, to other utilities.
Customer operating revenues result from the Company's sales of electricity to
---------------------------
ultimate customers and are based on rates authorized by the Pennsylvania Public
Utility Commission (PUC). These rates are cost-based and are designed to
recover the Company's energy and other operating expenses and investment in
utility assets and to provide a return on the investment. Short-term sales to
other utilities are regulated by the Federal Energy Regulatory Commission
(FERC) and are made at market rates.
Phase-in deferred revenues represent the deferral and subsequent recovery of
--------------------------
revenues resulting from a $232 million rate increase granted in early 1988. The
PUC required the Company to phase this increase in during a six-year period,
which ended in April 1994. During this phase-in period, the rate increase was
recognized in operating revenues.
------------------
The Company's non-KWH revenues comprise other operating revenues in the
------------------------
Statement of Consolidated Income of DQE.
Components of Change in Operating Revenues from the Prior Year
--------------------------------------------------------------------------------
1994 1993
(Amounts in Millions of Dollars)
--------------------------------------------------------------------------------
Revenues from Sales of Electricity:
Revenues from ultimate customers $ 0.7 $ 31.9
Revenues from other utilities 7.6 (21.8)
--------------------------------------------------------------------------------
Total Revenues from Sales of Electricity 8.3 10.1
--------------------------------------------------------------------------------
Other Operating Revenues 26.9 26.5
--------------------------------------------------------------------------------
Total Operating Revenues $35.2 $ 36.6
================================================================================
[Bar Graph appears here]
Electric Utility Customer Sales
1994 vs. 1993
(Millions of KWH)
Residential -11.2
Commercial +72.8
Industrial +209.8
Customer sales were higher due to the strengthening economy.
Revenues from sales of electricity to ultimate customers, including phase-in
--------
deferrals, fluctuate as a result of changes in sales volume and changes in fuel
---------
and other energy costs. Generally, the Company is permitted to recover (to the
extent that such amounts are not included in base rates) these fuel and other
energy costs from its customers through an energy cost rate adjustment clause
(ECR), subject to PUC review. This revenue adjustment includes a credit to the
Company's customers for profits from short-term sales to other utilities.
Revenues from sales of electricity to ultimate customers increased in 1994
compared to 1993 as a result of higher sales to commercial and industrial
customers. Commercial and industrial sales volume increased 1.3 percent and 6.9
percent, respectively, benefiting from the improving economy, as well as slight
growth in the numbers of customers. Industrial sales volume also increased as a
result of our marketing efforts and fewer customer production facility outages.
Compared to 1992, the significantly hotter summer in 1993 resulted in higher
residential and commercial sales volume. The credit to the Company's customers
for profits from short-term sales to other utilities was $16.6 million in 1994,
$12.1 million in 1993 and $19.1 million in 1992. These fluctuations primarily
resulted from changes in sales volume to other utilities.
11
The overall level of business activity in the Company's service territory and
weather conditions are expected to continue to be the primary factors affecting
sales of electricity to ultimate customers in the near term. The Company's
electric sales may also be affected in the long term by increased competition
in the electric utility industry. (See "Competition" discussion on page 16.)
Revenues from other utilities result from sales of electricity to other
-----------------------------
utilities. Fluctuations in electricity sales to other utilities are generally
related to the Company's customer energy requirements, the energy market and
transmission conditions and the availability of the Company's generating
stations. Because of reduced generating station availability, the Company had
fewer off-system sales in 1993 than in 1994 or 1992. Future levels of
off-system sales of electricity will be affected by the outcome of the
Company's FERC filings requesting firm transmission access. (See "Transmission
Access" discussion on page 17.)
Other operating revenues increased in 1994 and 1993 compared to the prior year
------------------------
primarily due to growth in environmental service revenues. The increase
reflects the acquisition of a 70 percent controlling interest in Chester
Environmental, Inc. (Chester) on August 17, 1993. Chester's revenues have been
reflected in other operating revenues since that date.
------------------------
Operating Expenses
--------------------------------------------------------------------------------
Fuel and purchased power expense fluctuations result from changes in the cost
------------------------
of fuel, the mix between coal and nuclear generation, the total KWHs sold and
generating station availability. Because of the ECR, changes in fuel and
purchased power cost normally do not impact earnings.
Components of Change in Fuel and Purchased Power Expense from the Prior Year
--------------------------------------------------------------------------------
1994 1993
(Amounts in Millions of Dollars)
--------------------------------------------------------------------------------
Average unit cost of fuel $(3.4) $ (1.8)
Generation mix (5.5) 9.1
Generation volume 7.4 (13.4)
Purchased power 7.7 4.6
--------------------------------------------------------------------------------
Total Energy Expense $ 6.2 $ (1.5)
================================================================================
[Bar Graph appears here]
Electric Utility Customer Revenues
(Millions of Dollars)
1990 1991 1992 1993 1994
Residential 381.9 413.3 385.7 405.1 401.2
Commercial 839.1 892.2 848.0 887.1 873.6
Industrial 1061.5 1106.4 1054.6 1086.5 1087.2
Revenue mix remains balanced.
[Bar Graph appears here]
Electric Utility Operating and Maintenance Expense
(Millions of Dollars)
Year Dollars
1990 365.6
1991 373.0
1992 358.5
1993 365.0
1994 358.4
Reflects ongoing cost-control efforts. (Excludes one-time lease termination
charge in 1993.)
The average unit cost of coal declined slightly in 1994, after remaining
relatively constant during 1993. Meanwhile, the average unit cost of nuclear
fuel has declined continually during the past three years.
Generation mix impacts fuel expense as the Company's nuclear fuel cost per KWH
is less than its fossil fuel cost per KWH. During 1993, compared to 1994 and
1992, the Company had more scheduled nuclear station refueling outages,
resulting in less nuclear generation and more fuel expense.
Generation volume during 1994 increased 3.4 percent compared to 1993 due to
fewer generating station outages. During 1993, generation decreased 5.6 percent
from 1992.
Purchased power volume increased in 1994 compared to 1993 because of the timing
of generating station outages. Purchased power volume increased in 1993 compared
to 1992 primarily due to the performance of the Perry plant. (See "Perry Unit 1"
discussion on page 15.)
Other operating expenses decreased slightly in 1994 compared to 1993 despite a
---------------
$25.0 million increase in operating expenses at Chester, the result of a full
year's ownership in 1994. This increase was offset by the continuation of the
Company's cost reduction program and by the 1993 recording of a $15.2 million
long-term power sale write-off and a $12.8 million property subleasing charge.
These 1993 charges, along with the Chester acquisition, accounted for the
increase in 1993 compared to 1992.
Maintenance expense fluctuations primarily result from the timing of scheduled
-----------
generating station outages, the timing of scheduled transmission and
distribution line maintenance and the effect of storms on overhead lines and
transformers. Incremental maintenance expense
12
incurred for scheduled refueling outages at the Company's nuclear units is
deferred for amortization over the period (generally 18 months) between
scheduled outages. During 1994 and 1993, amortization of deferred nuclear
refueling outage expense increased, reflecting the higher costs of more recent
refueling outages. Offsetting this increase in 1994 was a decrease in
transmission and distribution line maintenance expense. Also increasing
maintenance expense in 1993 was the Company's change, as of January 1, 1993, in
-----------
its method of accounting for maintenance costs during major fossil generating
station outages. Prior to 1993, maintenance costs incurred for scheduled major
outages at fossil generating stations were charged to expense as the costs were
incurred. Under the new accounting policy, the Company accrues, over the period
between outages, anticipated expenses for scheduled major fossil station
outages. (Maintenance costs incurred for non-major scheduled outages and for
forced outages continue to be charged to expense as the costs are incurred.)
This method was adopted to match more accurately the maintenance costs with the
revenue produced during the periods between scheduled major fossil generating
station outages.
Depreciation and amortization expense includes, in addition to depreciation of
-----------------------------
plant and equipment, nuclear decommissioning accruals, amortization of
regulatory tax receivables and amortization of an extraordinary property loss.
Depreciation and amortization expense increased in 1994 and 1993 compared to the
-----------------------------
prior year due to increases in depreciable property, nuclear decommissioning
expense and leveraged lease amortization. The 1993 increase also results from
amortization of regulatory tax receivables which began January 1, 1993,
concurrent with the adoption of Statement of Financial Accounting Standards No.
-----------------------------------------------
109 (SFAS No. 109). During 1994, the Company completed an extensive review of
------------------
its depreciation rates and submitted an informational filing to the PUC. As a
result of this study, beginning in 1995 the Company's composite depreciation
rate increased from 3.0 percent to 3.5 percent. It is anticipated that annual
depreciation expense will increase by approximately $25 million in 1995 compared
to the 1994 level. The Company is not currently seeking a rate increase to cover
these additional costs.
Taxes other than income taxes were lower in 1993 compared to 1994 and 1992,
-----------------------------
primarily as a result of a favorable resolution of certain property tax
assessments. In 1993, the Company recorded, on the basis of these revised
assessments, the expected refunds for overpayments in prior years.
[Bar Graph appears here]
Ratio of Earnings to Fixed Charges
Year Dollars
1990 1.89
1991 2.09
1992 2.23
1993 2.28
1994 2.59
Credit quality continues to improve.
[Bar Graph appears here]
Interest Expense and Other Charges
(Millions of Dollars)
Year Dollars
1990 157.3
1991 141.7
1992 132.3
1993 119.4
1994 110.0
Financial restructuring has reduced interest expense by more than 30% over the
last 5 years.
Other Income
--------------------------------------------------------------------------------
Other income increased in 1994 compared to 1993 as a result of leasing
------------
activities in 1994 and a full year's income from investments made during 1993.
Other income decreased in 1993 compared to 1992 due to lower deferred revenue
------------
carrying costs, as the deferred revenue balance upon which carrying charges were
earned declined.
Interest and Other Charges
--------------------------------------------------------------------------------
Interest expense reductions in 1994 and 1993 were achieved through refinancing
----------------
first mortgage bonds and certain tax exempt pollution control notes and through
retiring debt. Interest expense is expected to decline further in 1995.
----------------
Preferred and preference dividends of subsidiaries continue to decrease as a
--------------------------------------------------
result of the retirement of several outstanding issues. During 1994, the Company
retired $39.9 million of preferred and preference stock.
Income Taxes
--------------------------------------------------------------------------------
Income tax expense was lower in 1993, compared to 1994 and 1992, because of a
----------
favorable settlement (related to Duquesne's 1988 federal income tax return and
the Company's 1989 consolidated federal income tax return) with the Internal
Revenue Service. The remaining fluctuations result from a 1 percent increase in
the corporate federal income tax rate in 1993 and changes in taxable income.
During 1994 the statutory Pennsylvania income tax rate was reduced from 12.25
percent to 9.99 percent; this reduction is to be phased in over four years. This
change resulted in a net decrease of $87.2 million in deferred tax liabilities
and a corresponding reduction in the regulatory receivable.
13
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.
With respect to the financial statement presentation of SFAS No. 109, the
------------
Company reflects the amortization of the regulatory tax receivable resulting
from reversals of deferred taxes as depreciation and amortization expense.
-----------------------------
Changes in the regulatory tax receivable as a result of a change in tax rates
are reflected in the statement of consolidated income on the tax rate
--------
adjustment--regulatory tax receivable line. Reversals of accumulated deferred
------------------------------------- --------------------
income taxes are included in income tax expense.
------------ ----------
[Bar Graph appears here]
Capital Resources and Liquidity
-------------------------------
Net Cash Flow from Operations
(Millions of Dollars)
Year Dollars
1990 278.6
1991 345.3
1992 397.4
1993 384.9
1994 372.9
Net cash flow excludes working capital and other--net changes
[Bar Graph appears here]
Net Income
(Millions of Dollars)
Year Dollars
1990 121.7
1991 133.6
1992 141.5
1993 144.0
1994 156.8
Net income increased 9% in 1994.
Capital Expenditures and Investing
-------------------------------------------------------------------------------
During 1994, the Company spent approximately $94.3 million for utility
construction. The Company spent approximately $100.6 million in 1993 and
$112.4 million in 1992 for utility construction. These amounts were expended to
improve and/or expand its production, transmission and distribution systems.
Utility construction programs of the Company focus on the need to serve new
customers, to provide for the replacement of utility property and to modify
facilities consistent with the most current environmental and safety
regulations. The Company estimates that it will spend approximately $80 million
for utility construction annually in 1995, 1996 and 1997. These amounts exclude
AFC, nuclear fuel, expenditures for possible early replacement of steam
generators at the Beaver Valley Power Station and expenditures for the
refurbishment of the cold-reserved units. (See Notes F and J to the
consolidated financial statements.) The Company currently has no plans for
construction of new base load generating plants. The Company expects that funds
generated from operations will continue to be sufficient to finance a large part
of its capital needs.
In addition to utility construction, the Company's long-term investments are
focused in four principal areas: real estate investments, energy-related
investments, leasing investments and environmental services investments. The
level of investing activities stayed relatively constant in 1994 after
increasing in 1993 compared to 1992. Lease investments in 1994 were $52.3
million, of which $18.8 million were energy-related. Real estate investments in
1994 were $48.9 million, including $22.1 million in affordable housing, and, on
a net basis, other investments decreased $7.7 million. In 1993, the Company
invested $59.1 million in real estate, including $35.4 million in affordable
housing, and $24.7 million in leasing and other investments. Also during 1993,
the Company acquired a controlling interest in Chester for $11.9 million. The
Company's 1992 investments were primarily in energy-related leases.
Financing
-------------------------------------------------------------------------------
The Company plans to meet its current obligations and debt maturities through
1999 with funds generated from operations and through new financings. At
December 31, 1994, the Company was in compliance with all of its debt covenants.
During 1993, the Company refinanced $734.2 million of long-term debt. In 1994,
the Company continued to reduce its cost of capital by refinancing and retiring
securities.
During 1994, all of the outstanding shares of $2.10 and $7.50 preference stock
were redeemed for approximately $37.7 million. The Company also retired $2.2
million of $7.20 preferred stock. In May 1994, the Company filed a shelf
registration statement for the issuance of up to $150 million of Duquesne
Capital L.P. Cumulative Monthly Income Preferred Securities. These preferred
securities have not been issued.
During 1994, the Company also issued $114.1 million of its pollution control
obligations to replace a like amount of higher cost pollution control
obligations. The new pollution control obligations bear variable interest rates
and mature October 1, 2029.
The Company maintains two extendible revolving credit agreements, including a
$100 million arrangement expiring August 1995, and a $150 million arrangement
expiring October, 1995. Both arrangements contain two-year repayment periods for
any amounts outstanding at the expiration of the revolving credit periods. At
December 31, 1994, the Company had borrowed $60 million under the agreements.
14
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, 1994. The accounts receivable sales agreement, which expires in
June 1995, is one of many sources of funds available to the Company. Upon
expiration of this facility, the Company expects to extend the agreement or to
replace the facility with a similar one.
[Bar graph appears here]
Average Cost of Generation
--------------------------
(Cents Per KWH)
Year Cents
1990 2.52
1991 2.48
1992 2.14
1993 2.27
1994 2.23
Marginal cost of production continues to improve.
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, 1994, the amount of nuclear fuel financed by the Company under
this arrangement totaled approximately $52 million. The Company plans to
continue leasing nuclear fuel to fulfill its requirements at least through
September 1996, the remaining term of the current leasing arrangement.
Dividends
-------------------------------------------------------------------------------
The Company has paid dividends on common stock continuously since 1953. The
quarterly dividends paid have increased by an average annual rate of 5.6 percent
over the past five years, even though the Company has maintained a more
conservative payout ratio than the electric utility industry in general. The
Company expects that funds generated from operations will continue to be
sufficient to meet sinking fund and long-term debt maturities and to pay
dividends. The Company's need and the availability of funds will be influenced
by the economic activity within the Company's utility service territory, by
competitive and environmental legislation and by regulatory matters experienced
by the electric utility industry generally.
Dividends may be paid on DQE common stock to the extent permitted by law and as
declared by the board of directors. However, in Duquesne's Restated Articles of
-----------------
incorporation, provisions relating to preferred and preference stock may
restrict the payment of Duquesne's common dividends. 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 shareholders' equity to total capitalization is less than specified
percentages. As all of Duquesne's common stock is owned by DQE, to the extent
that Duquesne cannot pay common dividends, DQE may not be able to pay dividends
to its common shareholders. No part of the retained earnings of DQE or any of
its subsidiaries was restricted at December 31, 1994.
Generating Units
----------------
Generating Performance
-------------------------------------------------------------------------------
The Company wholly owns and operates two generating units. In addition, the
Company has an ownership or leasehold interest in nine jointly owned units, two
of which the Company operates. Of the four units the Company operates, three
achieved record performance during 1994.
The Beaver Valley Power Station achieved the highest combined (Units 1 and 2)
capacity factor (87.7 percent) in the history of the station. The Cheswick Power
Station achieved the highest capacity factor (78.7 percent) in its 24-year
history. Capacity factor is a key production measure. It is the ratio of the
power actually generated by a facility to the facility's rated capacity during
that period of time. It is also a key indicator of how well the stations are
operated based on their design capabilities.
Perry Unit 1
-------------------------------------------------------------------------------
The Company has a 13.74 percent ownership interest in Perry Unit 1, a nuclear
generating unit located in Ohio and operated by The Cleveland Electric
Illuminating Company (CEI). During 1993, the unit had an equivalent
availability factor of 39 percent. This performance resulted from several
outages. As a result of the length of these outages, the PUC imposed a penalty
for incremental replacement power costs. The 1994 equivalent availability factor
was 44 percent. This performance resulted from an extended outage (190 days)
for refueling and
15
maintenance. From the end of the outage in August 1994 thorugh the balance of
1994, Perry operated at full capacity except for short durations of reduced
power for testing and minor on-line maintenance activities.
CEI has prevoiusly submitted to the Nuclear Regulatory Commission an action
plan, called the Perry Course of Action (PCA), designed by CEI to "correct
identified management, technical, and programmatic deficiencies" at the plant
over roughly a three-year period, and to "correct the downward trending
performance" of Perry. CEI management represents to us that the PCA is on
schedule and will be an effective program to insure that Perry is in conformance
with industry standards for boiling water reactors. Based on actual costs and
estimates obtained from CEI through January 1995, the total costs to bring the
plant into compliance, including the costs associated with implementing the PCA,
are more than the costs originally projected by CEI. The Company cannot predict
the ultimate cost, timing or effectiveness of the PCA, and is continuing to
closely monitor the situation.
Outlook
-------
Competition
-------------------------------------------------------------------------------
Regulatory developments in the electric utility industry are placing increasing
competitive pressures on electric utilities. The electric utility industry is
expected to continue to undergo significant changes for the remainder of the
decade. These changes most likely will include increasing competition in the
generation and sale of electricity, increasing energy flows resulting from open
transmission access and non-regulated generation and transmission projects
outside the traditional service areas. The Company, like the industry in
general, is continuing to assess the impact of these competitive forces on its
future operations.
Electric Utility Industry Developments: The National Energy Policy Act of 1992
-------------------------------------- --------------------------------------
(energy act) was designed, among other things, to foster competition. Among
other provisions, the energy act amends the Public Utility Holding Company Act
----------------------------------
of 1935 (1935 act) and the Federal Power Act. Amendments to the 1935 act create
------- -----------------
a new class of independent power producers known as Exempt Wholesale Generators
(EWGs), which are exempt from the corporate structure regulations of the 1935
act. EWGs, which may include independent power producers as well as affiliates
of electric utilities, do not require Securities and Exchange Commission
approval or regulation. In addition, brokers and marketers, without owning or
operating any generation or transmission facilities, are being permitted to
enter into the business of buying and selling electric capacity and energy.
Amendments to the Federal Power Act create the potential for utilities and other
-----------------
power producers to gain increased access to transmission systems of other
utilities in order to facilitate sales to other utilities. The amendments permit
the FERC to order utilities to transmit power over their lines for use by other
suppliers and to enlarge or construct additional transmission capacity to
provide these services. The Company is currently pursuing expanded transmission
access under these amendments. (See discussion in "Transmission Access" on page
17.)
The energy efficiency title of the energy act requires states to consider
adopting integrated resource planning, which allows utility investments in
conservation and other demand side management techniques to be at least as
profitable as supply investments. The energy act also establishes new efficiency
standards in industrial and commercial equipment and lighting and requires
states to establish commercial and residential building codes with energy
efficiency standards. Additionally, the energy act requires utilities to
consider energy efficiency programs in their integrated resource planning.
These new regulations also permit industrial and large commercial customers to
own and operate facilities to generate their own electric energy requirements
and, if such facilities are qualifying facilities, to require the displaced
electric utility to purchase the output of such facilities. Customers may also
have the option of substituting fuels, such as the use of natural gas, oil or
wood for heating and/or cooling purposes rather than electric energy or of
relocating their facilities to a lower cost environment.
16
The PUC is currently conducting an investigation into electric power
competition. The Company has been advocating increased transmission access in
the wholesale power market as the necessary first step toward enabling our
customers to benefit from competition.
The Company's Response: Emerging competition, federal deregulation of wholesale
----------------------
energy sales, and prospective retail access initiatives require the Company to
reexamine its approach to doing business. Growth in energy sales, competitive
rate pressures, and the Company's commitment to provide reliable, quality
service to its customers influence short- and long-term corporate goals. The
Company's current business plan recognizes the need to encourage economic
growth and stability in the service territory and surrounding region. The
Company's efforts continue to focus on achievement of business growth through
the application of marketing and economic development programs to achieve
energy-efficient growth in its sales of utility services.
The Company has a diverse customer mix with less than 22 percent of total sales
of electricity derived from industrial customers as compared to an electric
utility industry average of approximately 34 percent. The Company's rates for
energy intensive industrial and commercial customers are competitively priced
and its rate structure allows some flexibility in setting rates to attract new
business. In addition, Company-sponsored programs help customers manage their
electricity consumption and control their costs.
Although management believes the Company's system is well positioned, as a
clean, low cost producer, to compete both within and outside of its service
territory, efforts continue to further reduce costs and increase effectiveness
and productivity. We will aggressively address these factors to position the
Company to overcome the challenges they may create and take advantage of the
opportunities increased competition will bring.
Transmission Access: In March 1994, the Company submitted, pursuant to the
-------------------
Federal Power Act, a "good faith" request for transmission service with the
-----------------
Allegheny Power System (APS) and Pennsylvania-New Jersey-Maryland
Interconnection Association (PJM Companies). The request is based on 20-year
firm service with flexible delivery points for 300 megawatts of transfer
capability over the transmission network that extends from Western Pennsylvania
to the East Coast. Because of a lack of progress on pricing and other issues, on
August 5 and September 16, 1994, the Company filed with the FERC applications
for transmission service from the PJM Companies and APS, respectively. The
applications are authorized under Section 211 of the Federal Power Act, which
-----------------
requires electric utilities to provide firm wholesale transmission service.
Generating Units Held for Future Use: In 1986, the PUC approved the Company's
------------------------------------
request to remove the Phillips and most of the Brunot Island (BI) power stations
from service and place them in cold reserve. The Company expects to recover its
net investment in these plants through future electricity sales. Phillips and BI
represent licensed, certified, clean sources of electricity that will be
necessary to meet expanding opportunities in the power markets. The Company
believes that anticipated growth in peak demand for electricity within its
service territory will require additional peaking generation. The Company looks
to BI to meet this need. The Phillips power plant is an important component in
the Company's strategy to identify and serve opportunities for providing bulk
power service. With recent legislation promoting wider transmission access to
bulk power markets and with the opportunity to package a sale of power from
Phillips with the support of the Company's system, the Phillips plant could be
made a highly reliable, cost-competitive alternative for most purchasers. In
summary, the Company believes its investment in these cold-reserved plants will
be necessary in order to meet future business needs. If business opportunities
do not develop as expected, the Company will consider the sale of these assets.
In the event that market demand, transmission access or rate recovery do not
support the utilization or sale of the plants, the Company may have to write off
part or all of their costs. At December 31, 1994, the Company's net investment
in Phillips and BI was $93.0 million and $42.0 million, respectively.
17
Environmental Matters
--------------------------------------------------------------------------------
The Comprehensive Environmental Response, Compensation and Liability Act of 1980
--------------------------------------------------------------------------------
(Superfund) and the Superfund Amendments and Reauthorization Act of 1986
----------------------------------------------------
established a variety of informational and environmental action programs. The
United States Environmental Protection Agency (EPA) has informed the Company of
its involvement or potential involvement in three hazardous waste sites. If the
Company is ultimately determined to be a responsible party with respect to these
sites, it could be liable for all or a portion of the cleanup costs. However, in
each case, other solvent, potentially responsible parties that may bear all or
part of any liability are also involved. In addition, the Company believes that
available defenses, along with other factors (including overall limited
involvement and low estimated remediation costs for one site) will limit any
potential liability that the Company may have for cleanup costs. The Company
believes that it is adequately reserved for all known liabilities and costs and,
accordingly, that these matters will not have a materially adverse effect on its
financial position or results of operations.
In 1990, Congress approved amendments to the Clean Air Act. Among other
-------------
innovations, this legislation established the Emission Allowance Trading System.
These allowances are issued by the EPA to fossil-fired stations with generating
capability of more than 25 megawatts that were in existence as of the passage of
the 1990 amendments. Allowances are part of a market-based approach to sulfur
dioxide (SO//2//) reduction. Emission allowances can also be obtained through
purchases on the open market or directly from other sources. Excess allowances
may be banked for future use or sold on the open market to other parties for
their use in offsetting emissions.
The legislation requires significant additional reductions of SO//2// and oxides
of nitrogen (NO//X//) by the year 2000. The Company continues to work with the
operators of its jointly owned stations to implement cost-effective compliance
strategies to meet these requirements. NO//X// reductions under Title IV of the
Clean Air Act amendments were required at the Cheswick station and the work to
-------------
achieve the reductions was completed in 1993. The ozone attainment provisions
of Title I of the Clean Air Act amendments also required NO//X// reductions by
----------------------------
1995 at the Company's Elrama plant and at the jointly owned Mansfield plant. The
Company will achieve such reductions with low NO//X// burner technology. The
Company has 662 megawatts of nuclear capacity, 1,187 megawatts of scrubbed
capacity, including 300 megawatts at the currently cold-reserved Phillips plant,
and 757 megawatts of capacity that meets the 1995 standards of the Clean Air Act
-------------
amendments through the use of low sulfur coal. Through the year
2000, the Company is planning a combination of compliance methods that include
fuel switching; increased use of, and improvements in, scrubbed capacity; flue
gas conditioning; low NO//X// burner technology; and the purchase of emission
allowances. The Company currently estimates that additional capital costs to
comply with Clean Air Act requirements through the year 2000 will be
-------------
approximately $20 million. This estimate is subject to the finalization of
federal and state regulations.
The Company is closely monitoring other potential air quality programs and air
emission control requirements that could be imposed in the future, including
additional NO//X// control requirements that could be imposed on fossil fuel
plants by the Ozone Transport Commission. As these 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.
In 1992, the Pennsylvania Department of Environmental Resources (DER) issued
Residual Waste Management Regulations governing the generation and management of
non-hazardous waste. The Company is currently conducting tests and developing
compliance strategies. Capital compliance costs for these DER regulations are
estimated, on the basis of information currently available, at $5 million in
1995. The expected additional capital cost of compliance for these DER
regulations through 2000 is estimated, based on current information, to be
approximately $25 million; this estimate is subject to the results of continuing
ground water assessments and DER final approval of compliance plans.
18
Under the Nuclear Waste Policy Act of 1982, which establishes a policy for
--------------------------------
handling and disposing of spent nuclear fuel and requires the establishment of a
final repository to accept spent fuel, contracts for jointly owned nuclear
plants have been entered into with the United States Department of Energy (DOE)
for permanent disposal of spent nuclear fuel and high-level radioactive waste.
The DOE has indicated that the repository will not be available for acceptance
of spent fuel before 2010. Existing on-site spent fuel storage capacities at
Beaver Valley Unit 1, Beaver Valley Unit 2 and Perry are expected to be
sufficient until 2017, 2011, and 2009, respectively. During 1994, the Company
increased the storage capacity at Beaver Valley Unit 1 by equipping the spent
fuel pool with high density fuel storage racks.
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, 1994, to 8.0
percent. The assumed change in future compensation levels was 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 Note N to the consolidated financial
statements. The resulting decrease in related expenses for subsequent years is
not expected to be material.
Investment in International Power Machines Corporation (IPM)
--------------------------------------------------------------------------------
The Company had a $2.8 million investment, reflected in the Consolidated Balance
Sheet of DQE as Other Long-Term Investments at December 31, 1994, in IPM
---------------------------
convertible preferred stock. On February 8, 1995, IPM was acquired by Exide
Electronics Group, Inc. (Exide). The Company is now a major shareholder of
Exide, the world's largest independent developer, manufacturer and servicer of
power protection and power management systems. This acquisition resulted in a
first quarter 1995 pre-tax gain for the Company of approximately $7.2 million,
or eight cents per share.
Other
--------------------------------------------------------------------------------
The Company is subject to the accounting and reporting requirements of the
Securities and Exchange Commission. In addition, the Company's utility
operations are subject to the regulation of the PUC and the FERC. As a result,
the consolidated financial statements contain 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 ratemaking process. In accordance with SFAS No. 71,
------------
the Company's financial statements reflect regulatory assets and costs based on
current cost-based ratemaking regulations. The regulatory assets represent
probable future revenue to the Company because provisions for these costs are
currently included, or are expected to be included, in charges to utility
customers through the ratemaking process.
The Company's electric utility operations currently satisfy the criteria of
SFAS No. 71. However, a company's utility operations or a portion of such
-----------
operations can cease to meet these criteria for various reasons including a
change in regulation. Should the Company cease to meet the SFAS No. 71 criteria,
-----------
it would be required to write-off any regulatory assets and liabilities for
those operations that no longer meet these requirements.
19
Report of Independent Certified Public Accountants
--------------------------------------------------
To the Directors and Shareholders of DQE:
----------------------------------------
We have audited the accompanying consolidated balance sheets of DQE and its
subsidiaries as of December 31, 1994 and 1993, and the related consolidated
statements of income, retained earnings, and cash flows for each of the three
years in the period ended December 31, 1994. These financial statements are the
responsibility of the Company's management. Our responsibility is to express an
opinion on these financial statements based on our audits.
We conducted our audits in accordance with generally accepted auditing
standards. Those standards require that we plan and perform the audit to obtain
reasonable assurance about whether the financial statements are free of material
misstatement. An audit includes examining, on a test basis, evidence supporting
the amounts and disclosures in the financial statements. An audit also includes
assessing the accounting principles used and significant estimates made by
management, as well as evaluating the overall financial statement presentation.
We believe that our audits provide a reasonable basis for our opinion.
In our opinion, such consolidated financial statements present fairly, in all
material respects, the financial position of DQE and its subsidiaries as of
December 31, 1994 and 1993, and the results of their operations and their cash
flows for each of the three years in the period ended December 31, 1994 in
conformity with generally accepted accounting principles.
As discussed in Note A to the consolidated financial statements, effective
January 1, 1993, the Company changed its method of accounting for income taxes
to conform with Statement of Financial Accounting Standards No. 109, and the
Company changed its method of accounting for maintenance costs during scheduled
major fossil station outages.
/s/ Deloitte & Touche LLP
Deloitte & Touche LLP
Pittsburgh, Pennsylvania
January 31, 1995
--------------------------------------------------------------------------------
Report of the Audit Committee of the Board of Directors of DQE
--------------------------------------------------------------
The Audit Committee, composed entirely of non-employee directors, meets
regularly with the independent public accountants and the internal auditors to
discuss results of their audit work, their evaluation of the adequacy of the
internal accounting controls and the quality of financial reporting.
In fulfilling its responsibilities in 1994, the Audit Committee recommended to
the Board of Directors, subject to shareholder approval, the selection of the
Company's independent public accountants. The Audit Committee reviewed the
overall scope and details of the independent public accountants' and internal
auditors' respective audit plans and reviewed and approved the independent
public accountants' general audit fees and non-audit services.
Audit Committee meetings are designed to facilitate open communications with
internal auditors and independent public accountants. To ensure auditor
independence, both the independent public accountants and the internal auditors
have full and free access to the Audit Committee.
The Audit Committee of the Board of Directors of DQE
20
Statement of Consolidated Income
--------------------------------------------------------------------------------------------------
(Thousands of Dollars, Except Per Share Amounts)
-----------------------------------------------
Year Ended December 31,
-----------------------------------------------
1994 1993 1992
----------------------------------------------------------------------------------------------------
Operating Revenues
------------------
Sales of Electricity:
Customers $1,115,987 $1,186,779 $1,152,835
Phase-in deferrals (28,810) (100,315) (98,201)
Utilities 58,295 50,669 72,440
----------------------------------------------------------------------------------------------------
Total Sales of Electricity 1,145,472 1,137,133 1,127,074
Other 90,157 63,322 36,748
----------------------------------------------------------------------------------------------------
Total Operating Revenues 1,235,629 1,200,455 1,163,822
----------------------------------------------------------------------------------------------------
Operating Expenses
------------------
Fuel and purchased power 243,905 237,731 239,230
Other operating 342,220 346,685 289,775
Maintenance 79,488 80,292 79,146
Depreciation and amortization 160,531 152,282 128,730
Taxes other than income taxes 89,474 73,126 85,733
----------------------------------------------------------------------------------------------------
Total Operating Expenses 915,618 890,116 822,614
----------------------------------------------------------------------------------------------------
Operating Income
Operating Income 320,011 310,339 341,208
----------------------------------------------------------------------------------------------------
Other Income 43,486 28,102 41,533
----------------------------------------------------------------------------------------------------
Interest and Other Charges
--------------------------
Interest expense 104,008 110,470 122,872
Preferred and preference dividends of subsidiaries 5,994 8,936 9,411
----------------------------------------------------------------------------------------------------
Total Interest and Other Charges 110,002 119,406 132,283
----------------------------------------------------------------------------------------------------
Income Before Income Taxes 253,495 219,035 250,458
----------------------------------------------------------------------------------------------------
Income Taxes
------------
Tax rate adjustment--regulatory tax receivable 87,200 -- --
Income taxes 9,479 77,628 108,940
----------------------------------------------------------------------------------------------------
Total Income Taxes 96,679 77,628 108,940
----------------------------------------------------------------------------------------------------
Income Before Cumulative Effect on Prior Years
of Changes in Accounting Principles 156,816 141,407 141,518
Adoption of SFAS No. 109--income taxes -- 8,000 --
Accounting for maintenance costs--net -- (5,425) --
----------------------------------------------------------------------------------------------------
Net Income
----------
Net Income $ 156,816 $ 143,982 $ 141,518
====================================================================================================
Average Number of Common Shares
Outstanding (000) 52,697 52,979 52,913
====================================================================================================
Earnings Per Share
------------------
Earnings Per Share of Common Stock:
Income Before Cumulative Effect on Prior Years
of Changes in Accounting Principles $2.98 $2.67 $2.67
Adoption of SFAS No. 109--income taxes -- .15 --
Accounting for maintenance costs--net -- (.10) --
----------------------------------------------------------------------------------------------------
Earnings Per Share of Common Stock $2.98 $2.72 $2.67
====================================================================================================
Dividends Declared
------------------
Dividends Declared Per Share of Common Stock $1.70 $1.62 $1.54
====================================================================================================
See notes to consolidated financial statements.
21
Consolidated Balance Sheet
------------------------------------------------------------------------------
Assets (Thousands of Dollars)
----------------------------
As of December 31,
----------------------------
1994 1993
------------------------------------------------------------------------------
Current Assets:
Cash and temporary cash investments $ 50,058 $ 32,234
------------------------------------------------------------------------------
Receivables:
Electric customer accounts receivable 96,157 107,342
Other utility receivables 26,008 28,807
Other receivables 53,766 56,576
Less: Allowance for uncollectible accounts (15,822) (13,688)
------------------------------------------------------------------------------
Receivables less allowance for uncollectible
accounts 160,109 179,037
Less: Receivables sold _ (9,000)
------------------------------------------------------------------------------
Total Receivables 160,109 170,037
Materials and supplies (at average cost):
Coal 30,484 26,793
Operating and construction 58,262 64,885
------------------------------------------------------------------------------
Total Materials and Supplies 88,746 91,678
------------------------------------------------------------------------------
Other current assets 36,156 10,455
------------------------------------------------------------------------------
Total Current Assets 335,069 304,404
------------------------------------------------------------------------------
Long-Term Investments:
Partnership investments 77,163 39,418
Leveraged lease investments 50,322 48,102
Leasehold investments 33,542 _
Other 35,191) 38,111)
------------------------------------------------------------------------------
Total Long-Term Investments 196,218 125,631
------------------------------------------------------------------------------
Property, Plant and Equipment:
Electric plant in service 4,196,690 4,102,979
Construction work in progress 52,199 60,103
Property held under capital leases 162,732 177,800
Property held for future use 216,738 216,863
Other 81,165 63,405
------------------------------------------------------------------------------
Total 4,709,524 4,621,150
------------------------------------------------------------------------------
Less accumulated depreciation and amortization (1,569,983) (1,452,910)
------------------------------------------------------------------------------
Property, Plant and Equipment_Net 3,139,541 3,168,240
------------------------------------------------------------------------------
Other Non-Current Assets:
Regulatory assets 710,763 909,405
Other 45,414 42,698
------------------------------------------------------------------------------
Total Other Non-Current Assets 756,177 952,103
------------------------------------------------------------------------------
Total Assets $4,427,005 $4,550,378
==============================================================================
See notes to consolidated financial statements.
22
------------------------------------------------------------------------------
(Thousands of Dollars)
Liabilities and ---------------------------
Capitalization As of December 31,
------------------------------------------------------------------------------
1994 1993
------------------------------------------------------------------------------
Current Liabilities:
Notes payable $ 60,115 $ 36,267
Current maturities and sinking fund requirements 85,986 45,741
Accounts payable 83,854 88,309
Accrued liabilities 64,894 70,967
Dividends declared 26,484 26,699
Other current liabilities 5,722 14,029
------------------------------------------------------------------------------
Total Current Liabilities 327,055 282,012
------------------------------------------------------------------------------
Non-Current Liabilities:
Deferred income taxes-net 969,948 1,169,148
Deferred investment tax credits 123,591 129,574
Capital lease obligations 41,106 55,733
Other 215,639 133,202
------------------------------------------------------------------------------
Total Non-Current Liabilities 1,350,284 1,487,657
------------------------------------------------------------------------------
------------------------------------------------------------------------------
Commitments and Contingencies (Notes B through N)
------------------------------------------------------------------------------
Capitalization:
Long-Term Debt 1,377,611 1,416,998
------------------------------------------------------------------------------
Preferred and Preference Stock of Subsidiaries:
Non-redeemable preferred stock 90,340 92,523
Non-redeemable preference stock 29,857 59,339
Deferred employee stock ownership plan
(ESOP) benefit (24,852) (27,126)
Redeemable preference stock _) 8,392)
------------------------------------------------------------------------------
Total Preferred and Preference Stock of Subsidiaries 95,345 133,128
------------------------------------------------------------------------------
Common Shareholders' Equity:
Common stock - no par value (authorized - 125,000,000
shares: issued - 73,119,436 shares) 1,001,973 1,001,259
Retained earnings 622,072 554,604
Treasury stock (at cost) (20,813,698 and
20,107,209 shares) (347,335) (325,280)
------------------------------------------------------------------------------
Total Common Shareholders' Equity 1,276,710 1,230,583
------------------------------------------------------------------------------
Total Capitalization 1,276,710 1,230,583
------------------------------------------------------------------------------
Total Liabilities and Capitalization $4,427,005 $4,550,378
------------------------------------------------------------------------------
23
Statement of Consolidated Cash Flows
------------------------------------------------------------------------------
(Thousands of Dollars)
--------------------------------
Year Ended December 31,
Cash Flows From --------------------------------
Operating Activities 1994 1993 1992
----------------------------------------------------------------------------------
Net income $ 156,816 $143,982 $141,518
Principal non-cash charges (credits) to net income:
Depreciation and amortization 160,531 152,282 128,730
Capital lease and nuclear fuel amortization 36,320 32,019 49,001
Deferred income taxes and investment tax
credits - net (8,136) (41,930) (2,319)
Allowance for equity funds used during construction (1,295) (869) (2,598)
Deferred revenues and carrying charges recovered 28,621 99,375 83,056
Changes in working capital other than cash (31,891) (111,677) 48,670
Other - net 28,661 26,167 2,487
----------------------------------------------------------------------------------
Net Cash Provided From Operating Activities 369,627 299,349 448,545
----------------------------------------------------------------------------------
Cash Flows Used By
Investing Activities
Investments:
Capital expenditures (121,085) (124,376) (113,215)
Long-term investments (66,698) (5,178) (21,632)
Other - net (12,321) (5,178) (12,632)
Net Cash Used By Investing Activities (223,411) (201,510) (147,430)
------------------------------------------------------------------------------
Cash Flows Used In
Financing Activities
Sale of bonds 114,110 740,500 312,925
Increase in notes payable 32,530 36,267 _
Dividends on common stock (89,348) (86,089) (81,491)
Reductions of long-term obligations:
Preferred and preference stock (39,958) (187) (24,158)
Long-term debt (114,835) (735,048) (394,951)
Other obligations (33,522) (27,751) (43,686)
Beaver Valley Unit 2 sale/leaseback premium _ _ (36,371)
Premium on reacquired debt (5,033) (31,702) (18,127)
Other - net 7,664 623 (2,719)
----------------------------------------------------------------------------------
Net Cash Used In Financing Activities (151,699) (103,387) (288,578)
----------------------------------------------------------------------------------
Net increase (decrease) in cash and temporary cash
investments 17,824 (5,548) 12,537
Cash and temporary cash investments at beginning
of year 32,234 37,782 25,245
----------------------------------------------------------------------------------
Cash and temporary cash investments at end of year $ 50,058 $ 32,234 $ 37,782
==================================================================================
Supplemental Cash Flow Information
Cash Paid During
the Year
Interest (net of amount capitalized) $105,900 $124,174 $125,305
----------------------------------------------------------------------------------
Income taxes $111,614 $133,303 $112,859
----------------------------------------------------------------------------------
Non-Cash Investing
and Financing
Activities
Capital lease obligations recorded $ 16,909 $ 11,811 $ 17,089
==================================================================================
See notes to consolidated financial statements.
24
Statement of Consolidated Retained Earnings
------------------------------------------------------------------------------
(Thousands of Dollars)
-----------------------------
1994 1993 1992
------------------------------------------------------------------------------
Balance at beginning of year $554,604 $496,711 $436,684
Net income 156,816 143,982 141,518
Dividends declared (89,348) (86,089) (81,491)
------------------------------------------------------------------------------
Balance at end of year $622,072 $554,604 $496,711
==============================================================================
See notes to consolidated financial statements.
Notes to Consolidated Financial Statements
A. Summary of Significant
Accounting
Policies
Consolidation
------------------------------------------------------------------------------
The consolidated financial statements of DQE include the accounts of its
subsidiaries: Duquesne Light Company (Duquesne), Duquesne Enterprises (DE) and
Montauk. DQE and its subsidiaries are collectively referred to as the Company.
All material intercompany balances and transactions have been eliminated in the
preparation of the Consolidated Financial Statements of DQE.
On August 17, 1993, DE acquired a 70 percent controlling interest in Chester
Environmental, Inc. (Chester) for approximately $12 million. The acquisition was
accounted for under the purchase method of accounting and Chester's results of
operations have been included in the Company's consolidated financial statements
since that date.
Basis of Accounting
------------------------------------------------------------------------------
The Company is subject to the accounting and reporting requirements of the
Securities and Exchange Commission (SEC). In addition, the Company's utility
operations are subject to the regulation of the Pennsylvania Public Utility
Commission (PUC) and the Federal Energy Regulatory Commission (FERC). As a
result, the consolidated financial statements contain 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 ratemaking process. Such effects concern mainly the
time at which various items enter into the determination of net income in
accordance with the principle of matching costs and revenues. (See Note F.)
Revenues
------------------------------------------------------------------------------
Meters are read monthly and 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 following section on ``Energy
Cost Rate Adjustment Clause.'') Deferred revenues are associated with the
Company's 1987 rate case. (See Note F.)
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 energy cost
recovery 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 Note F.)
25
Over or under-recoveries from customers are recorded in the Consolidated
Balance Sheet of DQE as payable to, or receivable from, customers. At December
31, 1994, $5.9 million was receivable from customers and shown as other current
assets. At December 31, 1993, $10.1 million was payable to customers and shown
as other current liabilities.
Maintenance
------------------------------------------------------------------------------
Incremental maintenance expense incurred for refueling outages at the Company's
nuclear units is deferred for amortization over the period (generally eighteen
months) between scheduled outages. The Company changed, as of January 1, 1993,
its method of accounting for maintenance costs during scheduled major fossil
generating station outages. Prior to that time, maintenance costs incurred for
scheduled major outages at fossil generating stations were charged to expense as
these costs were incurred. Under the new accounting policy, 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 continue to be charged to expense as
such costs are incurred.) This method was adopted to match more accurately the
maintenance costs and the revenue produced during the periods between scheduled
major fossil generating station outages.
The cumulative effect (approximately $5.4 million, net of income taxes of
approximately $3.9 million) of the change on prior years was included in net
income in 1993. The effect of the change in 1993 was to reduce income, before
the cumulative effect of changes in accounting principles, by approximately $2.4
million or $.05 per share and to reduce net income, after the cumulative effect
of changes in accounting principles, by approximately $7.8 million or $.15 per
share. The effect of the scheduled major fossil station outage accrual in 1994
was to reduce net income by approximately $0.7 million, or $.01 per share.
Depreciation and Amortization
------------------------------------------------------------------------------
Depreciation of property, plant and equipment, including plant-related
intangibles, is recorded on a straight-line basis over the estimated 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. Such nuclear decommissioning funds are deposited in
external, segregated trust accounts. The funds are invested in a portfolio
consisting of municipal bonds, certificates of deposit, and U.S. 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,
1994 totaled $19.2 million. On the Company's consolidated balance sheet, the
decommissioning trusts have been reflected in long-term investments, and the
related liability has been recorded as other liabilities.
Income Taxes
------------------------------------------------------------------------------
On January 1, 1993, the Company adopted Statement of Financial Accounting
Standards No. 109, Accounting for Income Taxes (SFAS No. 109). Implementation of
SFAS No. 109 involved a change in accounting principle. The cumulative $8
million effect on prior years was reported in 1993 as an increase in net income.
SFAS No. 109 requires that the liability method be used 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. SFAS
No. 109 also requires that a deferred tax liability or asset be adjusted in the
period of enactment for the effect of changes in tax laws or rates. During 1994
the statutory Pennsylvania income tax rate was reduced from 12.25 percent to
9.99 percent; this reduction is to be phased in over four years. This resulted
in a net decrease of $87.2 million for deferred tax liabilities.
For its utility operations, the Company recognizes a regulatory asset for the
deferred tax liabilities that are expected to be recovered from customers
through rates. (See Notes F and H).
26
With respect to the financial statement presentation of SFAS No. 109, the
Company reflects the amortization of the regulatory tax receivable resulting
from reversals of deferred taxes as depreciation and amortization expense.
Changes in the regulatory tax receivable as a result of a change in tax rates
are reflected in the statement of consolidated income on the tax rate
adjustment_regulatory tax receivable line. 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 utility property generally were deferred. Such credits are
subsequently reflected, over the lives of the related assets, as reductions to
tax expense.
Property, Plant and Equipment
------------------------------------------------------------------------------
The asset values of the Company's 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. The amount of AFC that is capitalized will vary according
to changes in the cost of capital and in the level of construction work in
progress (CWIP). On a current basis, the Company does not realize cash from the
allowance for funds used during construction. The Company does realize cash,
during the service life of the plant, through increased revenues reflecting a
higher rate base (upon which a return is earned) and increased depreciation.
The AFC rates applied to CWIP were 9.0 percent in 1994, 9.6 percent in 1993,
and 10.3 percent in 1992.
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 utility properties
that are retired (plus removal costs and less any salvage value) are charged to
the accumulated provision for depreciation.
Substantially all of the Company's utility properties are subject to first
mortgage liens, and to junior liens.
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 1993 and 1992 financial statements have been reclassified to conform with
accounting presentations adopted during 1994.
B. Receivables
An arrangement between the Company and an unaffiliated corporation entitles the
Company to periodically sell up to $50 million of its accounts receivable. The
Company sold receivables from time to time throughout 1994 but had no
receivables sold at December 31, 1994. At December 31, 1993, the Company had
sold $7.1 million of electric customer accounts receivable and $1.9 million of
other utility receivables. The sales agreement includes a limited recourse
obligation under which the Company could be required to repurchase certain of
the receivables. The arrangement expires on June 27, 1995.
C. Changes in
Working Capital
Other Than Cash
Changes in Working Capital Other Than Cash
------------------------------------------------------------------------------
1994 1993(a) 1992
(Amounts in Thousands of Dollars)
------------------------------------------------------------------------------
Receivables $(09,928) $(103,188) $(64,088)
Materials and supplies 2,932 13,635 (4,151)
Other current assets (25,701) 4,631 7,140
Accounts payable (4,455) (7,961) (8,818)
Other current liabilities (14,595) (18,794) (9,589)
------------------------------------------------------------------------------
Total $(31,891) $(111,677) $48,670
==============================================================================
(a) Net of the effects from the purchase of Chester
27
D. Long-Term
Investments
The Company's partnership investments are primarily in affordable housing
limited partnerships. The Company's investments in affordable housing were $57.5
million at December 31, 1994 and $35.4 million at December 31, 1993. The Company
also has a partnership investment at December 31, 1994 of $15.7 million in a
waste-to-energy facility.
The Company is the lessor in five leveraged lease arrangements involving
manufacturing equipment, mining equipment, rail equipment and natural gas
processing equipment. These leases expire in various years beginning 2001
through 2012. The residual value of the equipment, which belongs to the Company
after the leases expire, is estimated to approximate 14 percent of the original
cost. The Company's aggregate equity investment represents 22 percent of the
aggregate original cost of the property and is secured by guarantees of each
lessee's parent or affiliate. The remaining 78 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
$139 million and $144 million at December 31, 1994 and 1993, respectively.
Net Leveraged Lease Investments at December 31
------------------------------------------------------------------------------
1994 1993
(Amounts in Thousands of Dollars)
------------------------------------------------------------------------------
Rentals receivable (net of principal and
interest on the non-recourse debt) $50,010 $52,016
Estimated residual value of leased assets 26,470 26,470
Less: Unearned income (26,158) (30,384)
------------------------------------------------------------------------------
Leveraged lease investments 50,322 48,102
Less: Deferred taxes arising from
leveraged leases (34,174) (22,845)
------------------------------------------------------------------------------
Net Leveraged Lease Investments $16,148 $25,257
==============================================================================
The Company's leasehold investments are in computers, vehicles and equipment.
The Company's other investments are primarily in assets of a nuclear
decommissioning trust and marketable securities. 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 amounts of unrealized
holding gains at December 31, 1994 are not material.
E. Property, Plant
and Equipment
In addition to its wholly owned generating units, Duquesne, 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.
The Company has a 13.74 percent ownership interest in Perry Unit 1, a nuclear
generating unit operated by Centerior Energy. During 1993, the unit had an
equivalent availability factor of 39 percent. This performance resulted from
several outages related to mechanical failures. As a result of the length of
these outages, the PUC imposed a penalty for incremental replacement power
costs. The 1994 availability was 39 percent. This performance resulted from
several outages As a result of the length of these outages, the PUC imposed a
penalty for incremental replacement power costs. The 1994 equivalent
availability factor was 44 percent. This performance resulted from an extended
outage in August 1994 through the balance of 1994, Perry operated at full
capacity except for short durations of reduced power for testing and minor
on-line maintenance activities.
CEI has previously submitted to the Nuclear REgulatory Commission an action
plan, called the Perry Course of Action (PCA), designed by CEI to ``correct
identified management, technical, and programmatic deficiencies'' at the plant
over roughly a three-year period, and to ``correct the downward trending
performance'' of Perry. CEI management represents to us that
28
the PCA is on schedule and will be an effective program to insure that Perry is
in conformance with industry standards for boiling bring the plant back
to a performance level that meets industry standards for boiling water reactors.
The Company cannot predict the ultimate cost, timing or effectiveness of the
PCA, and is continuing to closely monitor the situation.
Generating Units at December 31, 1994
------------------------------------------------------------------------------------------------------------
Net
Percentage Utility Fuel
Unit Interest Megawatts Plant Source
(Millions of Dollars)
------------------------------------------------------------------------------------------------------------
Cheswick 100.0 570 $ 120.8 Coal
Elrama (a) 100.0 487 97.3 Coal
Ft. Martin 1 50.0 276 38.2 Coal
Eastlake 5 31.2 186 44.6 Coal
Sammis 7 31.2 187 54.4 Coal
Bruce Mansfield 1 (a) 29.3 228 69.1 Coal
Bruce Mansfield 2 (a) 8.0 62 18.0 Coal
Bruce Mansfield 3 (a) 13.74 110 48.9 Coal
Beaver Valley 1 (b) 47.5 385 253.5 Nuclear
Beaver Valley 2 (c)(d) 13.74 113 14.8 Nuclear
Beaver Valley Common Facilities 165.6
Perry 1 (e) 13.74 164 591.7 Nuclear
Brunot Island 100.0 66 7.5 Fuel Oil
------------------------------------------------------------------------------------------------------------
Total 2,834 1,524.4
Cold-reserved units:
Brunot Island 100.0 240 44.9 Fuel Oil
Phillips (a) 100.0 300 78.6 Coal
------------------------------------------------------------------------------------------------------------
Total Generating Units 3,374 $1,647.9
============================================================================================================
(a) The unit is equipped with flue gas desulfurization equipment.
(b) The 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. Rate Matters
1987 Rate Case
------------------------------------------------------------------------------
In March 1988, the PUC adopted a rate order that increased the
Company's utility revenues by $232 million annually. This rate increase was
phased-in from April 1988 through April 1994. Deficiencies in current revenues
which resulted from the phase-in plan were included in the consolidated income
statement as deferred revenues. Deferred revenues were recorded on the balance
sheet as a regulatory asset. As customers were billed for deficiencies related
to prior periods, this regulatory asset was reduced. As designed, the phase-in
plan provided for carrying charges (at the after-tax AFC rate) on revenues
deferred for future recovery. The Company recovered previously deferred revenues
and carrying charges of approximately $315 million during the phase-in period
which concluded in April of 1994.
At this time, the Company has no pending base rate case and has no immediate
plans to file a base rate case.
Regulatory Assets
------------------------------------------------------------------------------
As a result of the 1987 Rate Case, and the continued 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 utility customers through the ratemaking process.
Management will continue to evaluate significant changes in the regulatory and
competitive environment to assess the Company's overall consistency with the
criteria of SFAS No. 71.
29
Regulatory Assets at December 31
----------------------------------------------------------------------------------------
1994 1993
(Amounts in Thousands of Dollars)
----------------------------------------------------------------------------------------
Regulatory tax receivable (Note H) $428,043 $569,555
Unamortized debt costs (Note K)(a) 103,454 104,076
Deferred rate synchronization costs (see below) 51,149 51,149
Beaver Valley Unit 2 sale/leaseback premium (Note I)(b) 33,414 34,903
Deferred employee costs (c) 31,012 32,408
Extraordinary property loss (see below) 22,394 35,781
Deferred nuclear maintenance outage costs (Note A) 11,406 15,256
DOE decontamination and decommissioning receivable (Note J) 10,932 12,251
Deferred coal costs (see below) 10,677 16,156
Phase-in plan deferrals (see above) __ 28,621
Other 8,282 9,249
----------------------------------------------------------------------------------------
Total Regulatory Assets $710,763 $909,405
========================================================================================
(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 Beaver Valley 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.
Deferred Rate Synchronization Costs
------------------------------------------------------------------------------
In the 1987 Rate Case, the PUC approved the Company's petition to defer
initial operating and other costs of Perry Unit 1 and Beaver Valley Unit 2. The
Company deferred the costs incurred from November 17, 1987, when the units went
into commercial operation, until March 25, 1988, when a rate order was issued.
In its order, the PUC deferred ruling on whether these costs would be
recoverable from ratepayers. The Company is not earning a return on the
deferred costs.
The Company believes that these deferred costs are recoverable. In 1990, the
PUC permitted another Pennsylvania utility recovery of such costs over a
10-year period.
Extraordinary Property Loss
------------------------------------------------------------------------------
The Company abandoned its interest in the partially-constructed Perry Unit 2
in 1986 and subsequently disposed of its interest in 1992. In the 1987 Rate
Case, the PUC approved recovery, over a 10-year period, of the Company's
original $155 million investment in Perry Unit 2. The Company is not earning a
return on the as yet unrecovered portion (approximately $23.9 million at
December 31, 1994) of its investment in the unit.
Deferred Coal Costs
------------------------------------------------------------------------------
The PUC has established two market price coal cost standards for the
Company's interests in mines that supply coal to its generating stations. One
applies only to coal delivered at the Mansfield plant. 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 for 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, as determined by the PUC, for similar coal.
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 and gave the Company
options to extend the standard through March 2000. In December 1991, the
Company exercised the first of two options that extended the standard through
March 1996. The unrecovered cost of coal used at Mansfield amounted to $7.3
million and $7.4 million and the unrecovered cost of coal used throughout the
system amounted to $3.4 million and $8.8 million at December 31, 1994 and 1993,
respectively.
The Company believes that all deferred coal costs will be recovered.
30
Warwick Mine Costs
------------------------------------------------------------------------------
The 1990 joint petition for settlement (See preceding section on deferred coal
costs.) also recognized costs at the Company's Warwick Mine, which had been on
standby since 1988, and allowed for recovery of such costs, including the costs
of ultimately closing the mine. In 1990, Duquesne 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 mine reached a full
production rate in early 1991. The Warwick Mine coal reserves include both high
and low sulfur coal; the Company's contract is for medium to high sulfur (1.3
percent-2.5 percent) coal. More than 60 percent of the coal mined at Warwick
currently is used by the Company. The Company receives a royalty on sales of
Warwick coal in 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.
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. 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,
1994, the Company's net investment in the mine was $18.9 million. The estimated
liability, including final site reclamation, mine water treatment and certain
labor liabilities, for mine closing is $33 million and the Company has recorded
a liability in the consolidated balance sheet of approximately $12.8 million
toward these costs.
Property Held for Future Use
------------------------------------------------------------------------------
In 1986, the PUC approved the Company's request to remove the Phillips and most
of the Brunot Island (BI) power stations from service and place them in cold
reserve. The Company expects to recover its net investment in these plants
through future electricity sales. Phillips and BI represent licensed, certified,
clean sources of electricity that will be necessary to meet expanding
opportunities in the bulk power markets. The Company believes that anticipated
growth in peak load demand for electricity within its service territory will
require additional peaking generation. The Company looks to BI to meet this
need. The Phillips power plant is an important component in the Company's
strategy to identify and serve opportunities for providing bulk power service.
With recent legislation permitting wider transmission access to bulk power
markets and with the opportunity to package a sale of power from Phillips with
the support of the Company's system, the Phillips plant can be made a highly
reliable, cost-competitive alternative for most purchasers. In summary, the
Company believes its investment in these cold-reserved plants will be necessary
in order to meet future business needs. If business opportunities do not develop
as expected, the Company will consider the sale of these assets. In the event
that market demand, transmission access or rate recovery do not support the
utilization or sale of the plants, the Company may have to write off part or all
of their costs. At December 31, 1994, the Company's net investment in
Phillips and BI was $93.0 million and $42.0 million, respectively.
G. Short Term
Borrowing and
Revolving Credit
Arrangements
At December 31, 1994, the Company had two extendible revolving credit agreements
including a $100 million arrangement expiring August 1995, and a $150 million
arrangement expiring October 1995. Interest rates vary, in accordance with the
option selected at the time of each borrowing. Various borrowing options are
available under the credit agreements including prime, federal funds, Eurodollar
or certificate of deposit rates. Commitment fees are based on the unborrowed
amount of the commitments. Both arrangements contain two year repayment periods
for any amounts outstanding at the expiration of the revolving credit periods.
There were no short-term borrowings during 1992. During 1994 and 1993, the
maximum short-term bank and commercial paper borrowings outstanding were $60
million and $36 million; the average daily short-term borrowings outstanding
were $36.8 million and $9.9 million; and the weighted average daily interest
rates applied to such borrowings were 5.17 percent and 3.91 percent,
respectively. At December 31, 1994 and 1993, short-term borrowings were
$60 million and $36 million.
31
H. Income Taxes
----------------------------------------------------------------------------
The annual federal corporate income tax returns have been audited by the
Internal Revenue Service (IRS) for the tax years through 1989. Returns filed
for the tax years 1990 to date remain subject to IRS review. The Company does
not believe that final settlement of the federal income tax returns for these
years will have a materially adverse effect on its financial position or
results of operations. The effects of the 1993 adoption of SFAS No. 109 are
discussed in Note A. Implementation of the standard involved a change in
accounting principle. The cumulative effect of $8 million on prior years was
reported in 1993 as an increase in net income. The SFAS No. 109 impact on 1993
income before cumulative effect of changes in accounting principles is
immaterial.
Deferred Tax Liabilities
------------------------------------------------------------------------------------------
1994 1993
(Amounts in Thousands of Dollars)
------------------------------------------------------------------------------------------
At December 31, deferred tax assets (liabilities) were:
Investment tax credits unamortized $ 43,257 $ 45,351
Gain on sale/leaseback of Beaver Valley Unit 2 64,124 67,119
Tax benefit _ leasehold investment 61,667 --
Other 63,058 57,690
-------------------------------------------------------------------------------------------
Deferred tax assets 243,106 170,160
-------------------------------------------------------------------------------------------
Property depreciation (773,291) (855,560)
Regulatory asset (149,815) (199,344)
Loss on reacquired debt unamortized (38,066) (40,933)
Other (240,882) (243,471)
-------------------------------------------------------------------------------------------
Deferred tax liabilities (1,213,054) (1,339,308)
-------------------------------------------------------------------------------------------
Net Deferred Tax Liabilities $ (969,948) $(1,169,148)
===========================================================================================
Income Taxes
-------------------------------------------------------------------------------------------
1994 1993 1992
(Amounts in Thousands of Dollars)
-------------------------------------------------------------------------------------------
Currently payable: Federal $ 79,908 $ 82,803 $ 80,400
State 33,407 36,755 30,858
Deferred _ net: Federal (28,914) (27,017) 7,023
State (73,227) (8,907) (3,373)
Investment tax credits deferred _ net (5,982) (6,006) (5,968)
-------------------------------------------------------------------------------------------
Income Taxes $ 9,479 $ 77,628 $108,940
===========================================================================================
Total income taxes differ from the amount computed by applying the statutory
federal income tax rate to income before income taxes, preferred and preference
dividends of subsidiaries and before the cumulative effect of changes in
accounting principles.
Income Tax Expense Reconciliation
-------------------------------------------------------------------------------------------
1994 1993 1992
(Amounts in Thousands of Dollars)
-------------------------------------------------------------------------------------------
Computed federal income tax at statutory rate $ 90,821 $ 79,790 $88,355
Increase (decrease) in taxes resulting from:
Tax audit settlement -- (15,000) --
State income taxes, net of federal income tax benefit (25,883) 18,101 18,140
Amortization of deferred investment tax credits (5,982) (6,006) (5,969)
Adjustment to regulatory receivable, net of federal tax 56,680 -- --
Revenue requirement adjustment to regulatory taxes (12,178) -- --
Other (309) 743 8,414
-------------------------------------------------------------------------------------------
Total Income Tax Expense $ 96,679 $ 77,628 $108,940
===========================================================================================
32
Sources of Deferred Tax Expense
-------------------------------------------------------------------------------------------
1992
(Amounts in Thousands of Dollars)
-------------------------------------------------------------------------------------------
Sources of income taxes deferred and the related tax effects were:
Excess of tax depreciation $ 25,188
Deferred revenues recovered for book purposes (30,702)
Allowance for uncollectible accounts 9,760
Fuel costs (10,820)
Loss on early retirement of debt 20,999
Other _ net (10,775)
-------------------------------------------------------------------------------------------
Total Deferred Income Tax Expense $ 3,650
===========================================================================================
I. Leases
The Company leases nuclear fuel, a portion of a nuclear generating plant,
certain office buildings, computer equipment and other property and equipment.
Capital Leases at December 31
-------------------------------------------------------------------------------------------
1993 1992
(Amounts in Thousands of Dollars)
-------------------------------------------------------------------------------------------
Nuclear fuel $139,763 $136,755
Electric plant 22,969 41,045
-------------------------------------------------------------------------------------------
Total 162,732 177,800
Less accumulated amortization (91,376) (84,717)
-------------------------------------------------------------------------------------------
Property Held Under Capital Leases _ Net (a) $ 71,356 $093,083
===========================================================================================
(a) Includes $3,201 in 1994 and $3,492 in 1993 of capital leases with
associated obligations retired.
In 1987, the Company sold its 13.74 percent interest in Beaver Valley 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 leased back its interest in the unit for a term of 29.5
years. The lease provides for semiannual 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 Beaver Valley
Unit 2. In accordance with the Beaver Valley Unit 2 lease agreement, the Company
paid the premiums of approximately $36.4 million as a supplemental deferred rent
payment to the lessors. This amount was deferred and is being amortized over the
remaining lease term. At December 31, 1994, the deferred balance was
approximately $33.4 million.
Leased nuclear fuel is amortized as the fuel is burned. The amortization of
all other leased property is based on rental payments made. Payments for
capital and operating leases are charged to operating expenses on the statement
of consolidated income.
Summary of Rental Payments
-------------------------------------------------------------------------------------------
1994 1993 1992
(Amounts in Thousands of Dollars)
-------------------------------------------------------------------------------------------
Operating leases $56,437 $57,398 $ 64,986
Amortization of capital leases 33,596 28,758 43,119
Interest on capital leases 4,996 5,382 7,880
-------------------------------------------------------------------------------------------
Total Rental Payments $95,029 $91,538 $115,985
===========================================================================================
33
Future minimum lease payments for capital leases are related principally to the
estimated use of nuclear fuel financed through leasing arrangements and building
leases. Minimum payments for operating leases are related principally to Beaver
Valley Unit 2 and certain of the corporate offices.
Future Minimum Lease Payments
-------------------------------------------------------------------------------------------
Operating Leases Capital Leases
Year Ended December 31, (Amounts in Thousands of Dollars)
-------------------------------------------------------------------------------------------
1995 $ 57,391 $ 30,781
1996 57,202 15,305
1997 57,031 12,622
1998 56,921 6,078
1999 56,528 3,733
2000 and thereafter 950,385 23,736
-------------------------------------------------------------------------------------------
Total Minimum Lease Payments $1,235,458 92,255
-------------------------------------------------------------------------------------------
Less amount representing interest (25,065)
-------------------------------------------------------------------------------------------
Present value of minimum lease payments for capital leases $ 67,190 (a)
===========================================================================================
(a) Includes current obligations of $26.1 million at December 31, 1994.
Future payments due to the Company, as of December 31, 1994, under subleases
of certain corporate office space are approximately $1.2 million in 1995, $3.8
million in 1996 and $30 million thereafter.
J. Commitments and
Contingencies
Construction
------------------------------------------------------------------------------
The Company estimates that it will spend approximately $80 million annually on
construction during 1995, 1996 and 1997. These amounts exclude AFC, nuclear
fuel, expenditures for possible early replacement of steam generators at the
Beaver Valley Station (See ``Nuclear Litigation'' on page 35.) and expenditures
for the refurbishment of the cold-reserved units. (See ``Property Held For
Future Use'' on page 31.)
Nuclear-Related Matters
------------------------------------------------------------------------------
The Company operates two nuclear units and has an ownership interest in a third.
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 could begin in 1977, and that recovery for
Beaver Valley Unit 2 and Perry Unit 1 could begin in 1988. The Company expects
to decommission Beaver Valley Unit 2 and Perry Unit 1 following the end of
their operating lives, a date that currently coincides with the expiration of
each plant's operating license. Upon expiration of the Beaver Valley Unit 1
operating license, the unit will be placed in safe storage until the expiration
of the Beaver Valley Unit 2 operating license, at which time the units may be
decommissioned together.
Based upon site specific studies finalized in 1992 for Beaver Valley Unit 2,
and in 1994 for Beaver Valley 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, are $122 million for Beaver Valley Unit 1, $35 million for Beaver
Valley Unit 2, and $67 million for Perry Unit 1.
In conjunction with an August 18, 1994 PUC Accounting Order, the Company has
increased the annual contribution to its decommissioning trusts by
approximately $2 million to bring the total annual funding to approximately $4
million per year. The Company plans to continue making periodic reevaluations
of estimated decommissioning costs, to provide additional
funding from time to time, and to seek regulatory approval for recognition
of these increased funding levels.
34
Nuclear Insurance. All of the companies with an interest in the Beaver Valley
Power Station maintain the maximum available nuclear insurance for the $5.9
billion total investment in Beaver Valley Units 1 and 2. The insurance program
provides $2.8 billion for property damage, decommissioning, and decontamination
liabilities. Similar property insurance is held by the joint owners of the Perry
Plant for their $5.5 billion total investment in Perry Unit 1. 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, 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 $6.5 million.
The Price-Anderson Amendments to the Atomic Energy Act limit public liability
from a single incident at a nuclear plant to $8.9 billion. The Company has
purchased $200 million of insurance, the maximum amount available, which
provides the first level of financial protection.
Additional protection of $8.3 billion would be provided by an assessment of up
to $75.5 million per incident on each nuclear unit in the United States. The
Company's maximum total assessment, $56.6 million, which is based upon its
ownership interests in nuclear generating stations, would be limited to a
maximum of $7.5 million per incident per year. A further surcharge of
5 percent could be levied if the total amount of public claims exceeded the
funds provided under the assessment program. Additionally, a state premium tax
(typically 3 percent) would be charged on the assessment and surcharge. Finally,
the United States Congress could impose other revenue-raising measures on the
nuclear industry if funds prove insufficient to pay claims.
The Company carries extra expense insurance; coverage includes the incremental
cost of any replacement power purchased (in addition to costs that would have
been incurred had the units been operating) and other incidental expense after
the occurrence of certain types of accidents at its nuclear units. The amounts
of the coverage are 100 percent of the estimated extra expense 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. The amount and duration of actual
extra expense could substantially exceed insurance coverage.
Nuclear Litigation. In 1991, Pennsylvania Power Company, Ohio Edison Company,
Cleveland Electric Illuminating Company, Toledo Edison Company and the Company
were joined in the litigation against Westinghouse Electric Corporation
(Westinghouse) in the United States District Court for the Western District of
Pennsylvania. In the suit, the owners allege that six steam generators supplied
by Westinghouse for Beaver Valley Units 1 and 2 contain serious design defects
in particular defects causing tube corrosion and cracking.
Steam generator maintenance costs have increased as a result of these defects
and are likely to continue increasing. The condition of the steam generators is
being monitored closely. Replacement of the Beaver Valley Unit 1 steam generator
defective components may occur as early as 1997. While the Company has not yet
completed a detailed, site-specific study, replacement cost per unit is
estimated to be approximately $125 million. Other utilities with similar units
have replaced steam generators at comparable costs. To date, twelve additional
lawsuits have been brought by other utility companies around the country against
Westinghouse for similar problems with Westinghouse steam generators. A jury
trial began September 12, 1994 in Federal District Court in Western
Pennsylvania.
On October 24, 1994, the Court dismissed four of the five claims against
Westinghouse, leaving only the fraud claim. On December 6, 1994, the jury
rendered a verdict in favor of Westinghouse on the fraud count. On January 5,
1995, the owners of the Beaver Valley plant appealed the decision to the United
States Court of Appeals for the Third Circuit. The Company cannot predict the
outcome of this litigation; however, the Company does not believe that
resolution will have a materially adverse effect on its financial position or
results of operations. The Company's percentage interests (ownership and
leasehold) in Beaver Valley Unit 1 and in Beaver Valley Unit 2 are 47.5 percent
and 13.74 percent, respectively. The remainder of Beaver Valley Unit 1 is owned
by Ohio Edison Company and Pennsylvania Power Company.
35
The remaining interest in Beaver Valley Unit 2 is held by Ohio Edison Company,
Cleveland Electric Illuminating Company and Toledo Edison Company. The Company
operates both units on behalf of these owners.
Spent Nuclear Fuel Disposal. Under the Nuclear Waste Policy Act of 1982, which
establishes a policy for handling and disposing of spent nuclear fuel and
requires the establishment of a final repository to accept spent fuel, contracts
for jointly owned nuclear plants have been entered into with the Department of
Energy (DOE) for permanent disposal of spent nuclear fuel and high-level
radioactive waste. The DOE has indicated that the repository will not be
available for acceptance of spent fuel before 2010. Existing on-site spent fuel
storage capacities at Beaver Valley 1, Beaver Valley 2 and Perry are expected to
be sufficient until 2014, 2010, and 2009, respectively. During 1994, the Company
increased the storage capacity at Beaver Valley 1 by equipping the spent fuel
pool with high density fuel storage racks.
Uranium Enrichment Decontamination and Decommissioning Fund. Nuclear reactor
licensees in the United States are assessed annually for the decontamination and
decommissioning of DOE 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 (energy act) and are to be paid by such
utilities over a 15-year period. At December 31, 1994, the Company's liability
for contributions is approximately $9.9 million. Contributions when made are
recovered through the ECR.
Guarantees
------------------------------------------------------------------------------
The Company and the other co-owners have guaranteed certain debt and lease
obligations related to a coal supply contract for the Bruce Mansfield plant. At
December 31, 1994, the Company's share of these guarantees was $30.3 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 Note F.) The minimum future payments to be made by Duquesne solely in
relation to these obligations are $6.6 million in 1995, $6.2 million in 1996,
$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 $23.3 million in 1994, $26.5 million in 1993 and $25.2 million in
1992.
Residual Waste Management Regulations
------------------------------------------------------------------------------
In 1992, the Pennsylvania Department of Environmental Resources (DER) issued
Residual Waste Management Regulations governing the generation and management of
non-hazardous waste. The Company is currently conducting tests and developing
compliance strategies. Capital compliance costs are estimated, on the basis of
information currently available, at $5 million in 1995. The expected additional
capital cost of compliance through 2000 is estimated based on current
information to be approximately $25 million; this estimate is subject to the
results of continuing ground water assessments and DER final approval of
compliance plans.
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 or results of
operations.
K. Long-Term Debt
During 1992, the Company began issuing secured debt under a new first collateral
trust indenture. This indenture will ultimately replace Duquesne's 1947 first
mortgage bond indenture. First collateral trust bonds totaling $695 million with
an average interest rate of 6.58 percent were issued in 1993.
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 the bonds. For
certain of the
pollution control notes, there is an annual commitment fee for an irrevocable
letter of credit.
36
Under certain circumstances, the letter of credit is available for the
payment of interest on, or redemption of, a portion of the notes. In late 1994,
pollution control notes totaling $114.1million with an average interest rate of
10.34 percent were refinanced at lower adjustable interest rates.
Long-Term Debt at December 31
------------------------------------------------------------------------------------------------------------
Principal Outstanding
Interest (Amounts In Thousands of Dollars)
Rate Maturity 1994 1993
------------------------------------------------------------------------------------------------------------
First collateral trust bonds (a) 4.75%-8.75% 1996-2025 $0,950,400 $0,950,400
First mortgage bonds (b) 8.25% 1995 -- 49,000
Pollution control notes (c) (d) 2003-2030 417,051 416,266
Sinking fund debentures (e) 5% 2010 5,817 6,042
Miscellaneous 8,833 509
Less unamortized debt discount
and premium -- net (4,490) (5,219)
------------------------------------------------------------------------------------------------------------
Total Long-Term Debt $1,377,611 $1,416,998
============================================================================================================
(a) Excludes $9.6 million related to sinking fund requirements on the
underlying first mortgage bonds.
(b) Excludes $49.0 million related to a current maturity on June 1, 1995.
(c) Excludes $0.9 million related to sinking fund requirements on the
underlying first mortgage bonds.
(d) The pollution control notes have adjustable interest rates. The interest
rates at year-end averaged 4.3% in 1994 and 2.6% in 1993.
(e) As of January 1995, the sinking fund requirement for 1995 had been met
and the requirements for 1996 had been partially satisfied.
At December 31, 1994, sinking fund requirements and maturities of long-term debt
outstanding for the next five years were: $10.5 million and $49.1 million in
1995; $11.0 million and $50.1 million in 1996; $10.7 million and $50.0 million
in 1997; $9.9 million and $75.0 million in 1998; and $9.9 million and $75.0
million in 1999.
Sinking fund requirements relate primarily to the first mortgage bonds and
may be satisfied by cash or the certification of property additions equal to
166O percent of the bonds required to be redeemed. During 1994, annual sinking
fund requirements of $.5 million were satisfied by cash and $10.9 million by
certification of property additions.
Total interest costs incurred were $110.7 million in 1994, $118.1 million in
1993 and $133.9 million in 1992. Of these amounts, $2.0 million in 1994, $2.0
million in 1993 and $4.7 million in 1992 were capitalized as AFC. Debt discount
or premium and related issuance expenses are amortized over the lives of the
applicable issues.
In 1992, the Company was involved in the issuance of $419.0 million of
collateralized lease bonds, which were originally issued by an unaffiliated
corporation for the purpose of partially financing the lease of Beaver Valley
Unit 2. The Company is also associated with a letter of credit securing the
lessors' equity interest in the unit and certain tax benefits. During 1994, the
Company's Beaver Valley 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 the bonds would become
direct obligations of the Company. At December 31, 1994 and 1993, the Company
was in compliance with all of its debt covenants.
At December 31, 1994, 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 $1,353.3
million. The principal amount included in the Company's balance sheet is
$1,441.6 million.
37
L. Preferred and
Preference Stock of
Subsidiaries
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. At December
31, 1994, Duquesne had made all preferred stock dividend payments. 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, 1994, the Company had made all
dividend payments.
Outstanding preferred and preference stock is generally callable, on notice
of not less than thirty days, at stated prices plus accrued dividends. On
January 14, 1994, Duquesne called for redemption all of its outstanding shares
of $2.10 and $7.50 preference stock. None of the remaining preferred or
preference stock issues has mandatory purchase requirements.
Preferred and Preference Stock of Subsidiaries at December 31
----------------------------------------------------------------------------------------------------------
(Shares and Amounts in Thousands)
----------------------------------------------------------
Call Price 1994 1993 1992
Per Share ---------------- ---------------- ----------------
Shares Amount Shares Amount Shares Amount
----------------------------------------------------------------------------------------------------------
Preferred Stock Series: (a)
3.75% (b) (c) $ 51.00 148 $ 7,407 148 $ 7,407 148 $ 7,407
4.00% (b) (c) 51.50 550 27,486 550 27,486 550 27,486
4.10% (b) (c) 51.75 120 6,012 120 6,012 120 6,012
4.15% (b) (c) 51.73 132 6,643 132 6,643 132 6,643
4.20% (b) (c) 51.71 100 5,021 100 5,021 10 5,021
$2.10 (b) (c) 51.84 159 8,039 159 8,039 159 8,039
$7.20 (c) (d) 101.00 298 29,732 319 31,915 319 31,915
----------------------------------------------------------------------------------------------------------
Total Preferred Stock 1,507 90,340 1,528 92,523 1,528 92,523
----------------------------------------------------------------------------------------------------------
Preference Stock Series: (f)
$2.10 (c) (g) -- -- -- 1,175 29,383 1,175 29,383
----------------------------------------------------------------------------------------------------------
$7.50 (d) (e) -- -- -- 84 8,392 86 8,579
Plan Series A (c) (h) 37.46 841 29,857 844 29,956 845 29,995
----------------------------------------------------------------------------------------------------------
Total Preference Stock 841 29,857 2,103 67,731 2,106 67,957
----------------------------------------------------------------------------------------------------------
Deferred ESOP benefit (24,852) (27,126) (28,471)
----------------------------------------------------------------------------------------------------------
Total Preferred and
Preference Stock $ 95,345 $133,128 $132,009
==========================================================================================================
(a) Preferred stock: 4,000,000 authorized shares; $50 par value;
cumulative
(b) $50 per share involuntary liquidation value $1 par value; cumulative
(c) Non-redeemable
(d) $100 per share involuntary liquidation value involuntary liquidation value
(e) Redeemable
(f) Preference stock: 8,000,000 authorized shares;
(g) $25 per share involuntary liquidation value
(h) $35.50 per share
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 Note N.) 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 share of
DQE common stock. At December 31, 1994, $24.9 million of preference stock issued
in connection with the establishment of the ESOP had been offset, for financial
statement
38
purposes, by the recognition of a deferred ESOP benefit. Dividends on the
preference stock and cash contributions from the Company will be used to repay
the ESOP note. The Company made cash contributions of approximately $2.3
million for 1994, $2.1 million for 1993, and $4.9 million for 1992. These cash
contributions were the difference between the ESOP debt service and the amount
of dividends on ESOP shares (approximately $2.4 million in 1994,
$2.3 million in 1993 and $2.5 million in 1992). As shares of preference
stock are allocated to the accounts of participants in the ESOP, the Company
recognizes compensation expense, and the amount of the deferred compensation
benefit is amortized. The Company recognized compensation expense related to
the 401(k) plan of $1.8 million in 1994, $1.7 million in 1993, and $1.5 million
in 1992.
M. Common Stock
The Company or its predecessor, Duquesne, has continuously paid dividends on
common stock since 1953. The quarterly dividend declared in the fourth quarter
of 1994 was increased to $.44 per share. This annualized dividend of $1.76 per
share was increased from $1.68 per share in 1993. The annualized dividend per
share was $1.60 in 1992 and $1.52 in 1991.
An amendment to the Restated Articles of DQE changing the Company's Common Stock
from stock with a par value of $1.00 per share to stock having no par value, was
approved by stockholders at the Annual Meeting of Stockholders of DQE on April
20, 1994.
Dividends may be paid on DQE common stock to the extent permitted by law and
as declared by the board of directors. However, in Duquesne's Restated Articles
of incorporation, provisions relating to preferred and preference stock may
restrict the payment of Duquesne's common dividends. 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 shareholders' equity to total capitalization is less than specified
percentages. As all of Duquesne's common stock is owned by DQE, to the extent
that Duquesne cannot pay common dividends, DQE may not be able to pay dividends
to its common shareholders. No part of the retained earnings of DQE or any of
its subsidiaries was restricted at December 31, 1994.
Changes in the Number of Shares of Common Stock Outstanding
----------------------------------------------------------------------------------------------------------
1994 1993 1992
(Amounts in Thousands of Shares)
----------------------------------------------------------------------------------------------------------
Outstanding as of January 1 53,012 52,950 52,905
Reissuance from treasury stock 77 62 45
Repurchase of common stock (783) -- --
----------------------------------------------------------------------------------------------------------
Outstanding as of December 31 52,306 53,012 52,950
==========================================================================================================
N. Employee Benefits
Retirement Plans
---------------------------------------------------------------------------
The Company maintains retirement plans to provide pensions for all full-time
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 (ERISA) but not to exceed the maximum tax
deductible amount for the year. Pension costs charged to expense or construction
were $8.9 million for 1994, $9.8 million for 1993 and $11.4 million for 1992.
39
Funded Status of the Retirement Plans and Amounts Recognized on the
Consolidated Balance Sheet of DQE at December 31
---------------------------------------------------------------------------------------------------------
1994 1993
(Amounts in Thousands of Dollars)
---------------------------------------------------------------------------------------------------------
Actuarial present value of benefits rendered to date:
Vested benefits $314,933 $321,249
Non-vested benefits 17,282 16,826
---------------------------------------------------------------------------------------------------------
Accumulated benefit obligations based on
compensation to date 332,215 338,075
Additional benefits based on estimated future salary levels 59,318 74,718
---------------------------------------------------------------------------------------------------------
Projected benefit obligation 391,533 412,793
Fair market value of plan assets 412,724 434,384
---------------------------------------------------------------------------------------------------------
Projected benefit obligation under plan assets $ 21,191 $ 21,591
---------------------------------------------------------------------------------------------------------
Unrecognized net gain $ 95,691 $ 80,411
Unrecognized prior service cost (30,365) (21,449)
Unrecognized net transition liability (17,477) (19,289)
Net pension liability per balance sheet (26,658) (18,082)
---------------------------------------------------------------------------------------------------------
Total $ 21,191 $ 21,591
=========================================================================================================
Assumed rate of return on plan assets 8.00% 8.00%
---------------------------------------------------------------------------------------------------------
Discount rate used to determine projected benefit
obligation 8.00% 7.00%
---------------------------------------------------------------------------------------------------------
Assumed change in compensation levels 5.50% 5.25%
---------------------------------------------------------------------------------------------------------
Pension assets consist primarily of common stocks, United States obligations and corporate
debt securities.
Components of Net Pension Cost
---------------------------------------------------------------------------------------------------------
1994 1994 1993
(Amounts in Thousands of Dollars)
---------------------------------------------------------------------------------------------------------
Service cost (Benefits earned during the year) $ 12,482 $ 11,657 $ 11,397
Interest on projected benefit obligation 28,221 27,423 26,390
Return on plan assets 1,967 (41,725) (26,736)
Net amortization and deferrals (33,783) 12,454 325
---------------------------------------------------------------------------------------------------------
Net Pension Cost $ 8,887 $ 9,809 $ 11,376
=========================================================================================================
Retirement Savings Plan and Other Benefit Options
-------------------------------------------------------------------------------
The Company sponsors separate 401(k) retirement plans for its union-represented,
International Brotherhood of Electrical Workers (IBEW), employees and its
management 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 his or her eligible salary. The Company match consists of a $.25
base match per eligible contribution dollar and an additional $.25 incentive
match per eligible contribution dollar, if Board-approved targets are achieved.
The 1994 incentive target 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 Note L.)
40
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 his or her eligible salary. The Company
match consists of a $.25 base match per eligible contribution dollar and an
additional $.25 incentive match per eligible contribution dollar, if certain
Non-Occupational Illness and Injury targets are met.
DQE shareholders have approved a long-term incentive plan through which the
Company may grant management employees options to purchase, during the years
1987 through 2003, up to a total of five million shares of DQE common stock at
prices equal to the fair market value of such stock on the dates the options
were granted. At December 31, 1994, approximately 2.3 million of these shares
were available for future grants.
As of December 31, 1994, 1993 and 1992, respectively, active grants totaled
1,412,000; 1,175,000; and 848,000 shares. Exercise prices of these options
ranged from $12.3125 to $34.625 at December 31, 1994 and December 31, 1993 and
from $12.3125 to $28.75 at December 31, 1992. Expiration dates of these grants
ranged from 1997 to 2004 at December 31, 1994; from 1997 to 2003 at December 31,
1993; and from 1997 to 2002 at December 31, 1992. As of December 31, 1994, 1993
and 1992, respectively, stock appreciation rights (SARs) had been granted in
connection with 793,000; 795,000; and 623,000 of the options outstanding. During
1994, 836,000 SARs were exercised; 226,000 options were exercised at prices
ranging from $12.3125 to $28.375; and 187,000 options lapsed. During 1993,
748,000 SARs were exercised; 151,000 options were exercised at prices ranging
from $12.3125 to $28.375; and 152,000 options lapsed. During 1992, 108,000 SARs
were exercised; 50,000 options were exercised at prices ranging from $12.3125 to
$26.375; and 59,000 options lapsed. Of the active grants at December 31, 1994,
1993 and 1992, respectively, 612,000; 578,000; and 232,000 were not exercisable.
Other Postretirement Benefits
--------------------------------------------------------------------------------
In addition to pension benefits, the Company provides certain health care
benefits and life insurance for some retired employees. 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. As of
January 1, 1993, the Company adopted Statement of Financial Accounting Standards
No. 106, Employers' Accounting for Postretirement Benefits Other Than Pensions,
which requires the actuarially determined costs of the aforementioned
postretirement benefits to be accrued over the period from the date of hire
until the date the employee becomes fully eligible for benefits. The Company has
adopted the new standard prospectively and has elected to amortize the
transition liability over 20 years.
Components of Postretirement Cost
---------------------------------------------------------------------------------------------------------
1994 1993
(Amounts in Thousands of Dollars)
---------------------------------------------------------------------------------------------------------
Service cost (Benefits earned during the period) $1,631 $1,779
Interest cost on accumulated benefit obligation 2,294 2,497
Amortization of the transition obligation over twenty years 1,700 1,700
---------------------------------------------------------------------------------------------------------
Total Postretirement Cost $5,625 $5,976
=========================================================================================================
The accumulated postretirement benefit obligation comprises the present value of
the estimated future benefits payable to current retirees and a pro rata portion
of estimated benefits payable to active employees after retirement.
41
Funded Status of Postretirement Plan and Amounts Recognized on the
Consolidated Balance Sheet of DQE at December 31
---------------------------------------------------------------------------------------------------------
1994 1993
(Amounts in Thousands of Dollars)
---------------------------------------------------------------------------------------------------------
Actuarial present value of benefits:
Retirees $ 6,292 $ 4,830
Fully eligible active plan participants 3,074 3,482
Other active plan participants 20,543 24,170
---------------------------------------------------------------------------------------------------------
Accumulated postretirement benefit obligation 29,909 32,482
Fair market value of plan assets -- --
---------------------------------------------------------------------------------------------------------
Accumulated benefit obligation in excess of plan assets $(29,909) $(32,482)
=========================================================================================================
Unrecognized net loss $ 9,481 $ (122)
Unrecognized prior service cost -- 4,383
Unrecognized net transition liability (30,598) (32,296)
Postretirement liability per balance sheet (8,792) (4,447)
---------------------------------------------------------------------------------------------------------
Total $(29,909) $(32,482)
=========================================================================================================
Discount rate used to determine projected benefit obligation 8.00% 7.00%
---------------------------------------------------------------------------------------------------------
Health care cost trend rates:
For year beginning January 1 8.60% 10.50%
Ultimate rate 6.50% 5.50%
Year ultimate rate is reached 1999 1999
---------------------------------------------------------------------------------------------------------
Effect of a one percent increase in health care cost trend rates:
On accumulated projected benefit obligation $ 3,137 $ 4,000
On aggregate of annual service and interest costs $ 465 $ 600
---------------------------------------------------------------------------------------------------------
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 Company's service territory.]
---------------------------------------------------------------------------------------------------------
1994 First Quarter Second Quarter Third Quarter Fourth Quarter
---------------------------------------------------------------------------------------------------------
Operating Revenues $309,993 $296,574 $338,288 $290,774
Operating Income 81,969 72,042 101,159 64,841
Net Income 37,296 33,029 48,592 37,899
Earnings Per Share .70 .63 .92 .73
Stock Price:
High 34 1/2 32 7/8 31 30 1/4
Low 30 3/4 28 5/8 27 5/8 27 3/4
---------------------------------------------------------------------------------------------------------
1993 (a)(b)
---------------------------------------------------------------------------------------------------------
Operating Revenues $285,082 $281,798 $334,848 $298,727
Operating Income 76,376 76,792 86,504 70,667
Income Before Cumulative Effect on Prior
Years of Changes in Accounting Principles 31,839 33,017 48,294 28,257
Net Income 34,414 33,017 48,294 28,257
Earnings Per Share .65 .62 .91 .54
Stock Price:
High 36 3/8 36 37 36 7/8
Low 31 3/8 32 3/4 34 5/8 32
=========================================================================================================
(a) Fourth quarter 1993 results included the effects of a $15.2 million charge
for the write-off of the Company's investment in an abandoned transmission
line project and a $14.6 million reduction of taxes other than income as a
result of a favorable resolution of tax assessments.
(b) Restated to conform with presentations adopted during 1994.
42
Selected Financial Data
---------------------------------------------------------------------------------------------------------
Amounts in Thousands of Dollars 1994 1993 1992 1991 1990 1989
---------------------------------------------------------------------------------------------------------
Selected Income Statement Items
Operating Revenues:
Customers $1,115,987 $1,186,779 $1,152,835 $1,184,779 $1,050,702 $ 954,570
Phase-in deferrals (28,810) (100,315) (98,201) (78,344) 10,784) 96,287)
Utilities 58,295 50,669 72,440 58,903 48,543 49,949
Other 90,157 63,322 36,748 37,715 30,504 24,682
---------------------------------------------------------------------------------------------------------
Total Operating Revenues 1,235,629 1,200,455 1,163,822 1,203,053 1,140,533 1,125,488
---------------------------------------------------------------------------------------------------------
Operating Expenses:
Fuel and purchased power 243,905 237,731 239,230 254,019 228,993 221,928
Other operating & maintenance 421,708 426,977 368,921 393,100 390,231 373,658
Depreciation and amortization 160,531 152,282 128,730 119,264 122,250 119,376
Taxes other than income taxes 89,474 73,126 85,733 95,176 81,255 92,919
---------------------------------------------------------------------------------------------------------
Total Operating Expenses 915,618 890,116 822,614 861,559 822,729 807,881
---------------------------------------------------------------------------------------------------------
Operating Income 320,011 310,339 341,208 341,494 317,804 317,607
Other Income 43,486 28,102 41,533 35,566 45,976 35,823
Interest and Other Charges 110,002 119,406 132,283 141,654 157,313 165,009
Income Taxes 96,679 77,628 108,940 101,841 84,795 75,419
Changes in Accounting Principles -- 2,575 -- -- -- --
---------------------------------------------------------------------------------------------------------
Net Income $1,156,816 $ 143,982 $ 141,518 $ 133,565 $ 121,672 $ 113,002
=========================================================================================================
Earnings Per Share $2.98 $2.72 $2.67 $2.50 $2.24 $2.03
=========================================================================================================
Selected Balance Sheet Items
Property, plant & equipment--net $3,139,541 $3,168,240 $3,036,509 $3,052,834 $3,048,388 $3,057,079
Total assets $4,427,005 $4,550,378 $3,778,335 $3,851,318 $3,833,842 $3,832,638
Capitalization:
Common shareholders' equity $1,276,710 $1,230,583 $1,171,460 $1,111,121 $1,079,141 $1,066,190
Preferred and preference stock 95,345 133,128 132,009 137,343 189,093 219,991
Long-term debt 1,377,611 1,416,998 1,413,001 1,420,726 1,501,295 1,540,329
---------------------------------------------------------------------------------------------------------
Total Capitalization $2,749,666 $2,780,709 $2,716,470 $2,669,190 $2,769,529 $2,826,510
=========================================================================================================
Capitalization Ratios
Common shareholders' equity 46.4% 44.2% 43.1% 41.6% 39.0% 37.7%
Preferred and preference stock 3.5% 4.8% 4.9% 5.2% 6.8% 7.8%
Long-term debt 50.1% 51.0% 52.0% 53.2% 54.2% 54.5%
---------------------------------------------------------------------------------------------------------
Total Capitalization 100.0% 100.0% 100.0% 100.0% 100.0% 100.0%
=========================================================================================================
Ratio of Earnings to Fixed Charges
(pre-tax) 2.59% 2.28% 2.23% 2.09% 1.89% 1.78%
Selected Common Stock Information
Shares Outstanding (In thousands):
Year-end 52,306 53,012 52,950 52,905 53,759 55,340
Average 52,697 52,979 52,913 53,391 54,432 55,790
Dividends declared (In thousands) $89,348 $86,089 $81,491 $78,040 $74,972 $72,397
Dividends paid per share $1.68 $1.60 $1.52 $1.44 $1.36 $1.28
Dividend payout ratio 56.4% 58.8% 56.9% 57.6% 60.7% 63.1%
Price earnings ratio at year-end 9.9% 12.7% 12.1% 12.3% 11.1% 11.8%
Dividend yield at year-end 5.7% 4.6% 5.0% 5.0% 5.8% 5.7%
Return on average common equity 12.5% 12.0% 12.4% 12.2% 11.3% 10.6%
=========================================================================================================
43
Selected Operating Data
---------------------------------------------------------------------------------------------------------
1994 1993 1992 1991 1990 1989
---------------------------------------------------------------------------------------------------------
---------------------------------------------------------------------------------------------------------
Sales of Electricity:
Average annual residential
kilowatt-hour use 6,170 6,201 5,901 6,331 5,953 6,060
---------------------------------------------------------------------------------------------------------
Electric energy sales billed
(millions of KWH):
Residential 3,219 3,231 3,069 3,285 3,078 3,119
Commercial 5,563 5,490 5,358 5,450 5,236 5,145
Industrial 3,256 3,046 3,059 3,042 3,296 3,221
Miscellaneous 84 84 83 84 84 84
---------------------------------------------------------------------------------------------------------
Total Sales to Customers 12,122 11,851 11,569 11,861 11,694 11,569
---------------------------------------------------------------------------------------------------------
Sales to other utilities 3,212 2,821 4,060 2,979 1,830 2,100
---------------------------------------------------------------------------------------------------------
Total Sales 15,334 14,672 15,629 14,840 13,524 13,669
=========================================================================================================
Percentage Change in Energy Sales:
Residential (0.4) 5.3 (6.6) 6.7 (1.3) (1.2)
Commercial 1.3 2.5 (1.7) 4.1 1.8 1.8
Industrial 6.9 (0.4) 0.6 (7.7) 2.3 (2.5)
Miscellaneous -- 1.2 (1.2) -- -- (7.7)
---------------------------------------------------------------------------------------------------------
Total Sales to Customers 2.3 2.4 (2.5) 1.4 1.1 (0.3)
=========================================================================================================
Sales to other utilities 13.9 (30.5) 36.3 62.8 (12.9) (22.7)
---------------------------------------------------------------------------------------------------------
Total Sales 4.5 (6.1) 5.3 9.7 (1.1) (4.5)
=========================================================================================================
Energy Supply and Production Data:
Energy supply (millions of KWH):
Net generation--system plants
(net of Company use and losses) 14,678 14,056 15,074 14,220 13,266 13,455
Purchased and net inadvertent power 656 616 555 620 258 214
---------------------------------------------------------------------------------------------------------
Total Energy Supply 15,334 14,672 15,629 14,840 13,524 13,669
=========================================================================================================
Generating capability (MW) 2,834 2,834 2,834 2,835 2,835 2,835
Peak demand (MW) 2,535 2,499 2,308 2,402 2,379 2,381
Cost of fuel per million BTU 137.23(cent)143.65(cent)140.15(cent) 153.70(cent)149.62(cent)143.87(cent)
BTU per kilowatt-hour generated 10,478 10,437 10,370 10,414 10,444 10,411
Average cost of generation
per kilowatt-hour 2.23(cent) 2.33(cent) 2.19(cent) 2.44(cent) 2.51(cent) 2.35(cent)
---------------------------------------------------------------------------------------------------------
Number of Customers--End of Year:
Residential 522,588 522,353 521,152 520,016 518,322 516,801
Commercial 53,617 52,910 52,839 52,617 52,330 51,950
Industrial 2,027 1,995 1,987 2,004 2,026 2,023
Other 1,881 1,866 1,833 1,891 1,847 1,818
---------------------------------------------------------------------------------------------------------
Total Customers 580,113 579,124 577,811 576,528 574,525 572,592
=========================================================================================================
44
Board of Directors (All terms 3 years)
Daniel Berg
65. Term expires 1997 (1, 6). Institute Professor, Rensselaer Polytechnic
Institute. Directorships include Hy-Tech Machine, Inc. (specialty parts),
Joachim Machinery Co., Inc. (distributor of machine tools), and Chester
Environmental, Inc. (environmental engineering).
Doreen E. Boyce
60. Term expires 1995 (2, 5). President of the Buhl Foundation (support of
educational and community programs). Directorships include Microbac
Laboratories, Inc. and Dollar Bank, Federal Savings Bank. Trustee of Franklin
& Marshall College.
Robert P. Bozzone
61. Term expires 1997 (1, 2). Vice Chairman of Allegheny Ludlum Corporation
(specialty metals production). Directorships include Allegheny Ludlum
Corporation; Chairman, Pittsburgh branch of the Federal Reserve Bank of
Cleveland. Trustee of Rensselaer Polytechnic Institute.
Sigo Falk
60. Term expires 1996 (2, 3, 4). Management of personal investments. Chairman of
Maurice Falk Medical Fund and Vice Chairman of Chatham College Board of
Trustees. Directorships include the Historical Society of Western Pennsylvania
and the Allegheny Land Trust.
William H. Knoell
70. Term expires 1997 (3, 4, 6). Retired Chairman and Chief Executive Officer of
Cyclops Industries, Inc. (basic and specialty steels and fabricated steel
products; industrial and commercial construction). Directorships include Cabot
Oil and Gas Corporation. Life trustee of Carnegie Mellon University.
G. Christian Lantzsch
70. Term expires 1995 (2, 3). Retired Vice Chairman and Treasurer, Mellon Bank
Corporation (bank holding company); retired Vice Chairman and Chief Financial
Officer, Mellon Bank, N.A. (commercial banking and trust services).
Directorships include Koger Equity, Inc. (real estate investment trust).
Robert Mehrabian
53. Term expires 1995 (1, 5). President, Carnegie Mellon University; Dean,
College of Engineering, University of California at Santa Barbara, 1983-90.
Directorships include PPG Industries, Inc. (producer of glass, chemicals,
coatings and resins), Mellon Bank Corporation and Mellon Bank, N.A.
Thomas J. Murrin
65. Term expires 1997 (3, 6). Dean, A.J. Palumbo School of Business
Administration, Duquesne University; former Deputy Secretary of U.S. Dept. of
Commerce; former President, Westinghouse Electric Corporation Energy and
Advanced Technology Group. Directorships include Motorola, Inc. (manufacturer of
electronic equipment and components). Member of the Executive Committee of the
U.S. Council on Competitiveness and Chairman of the District Export Council.
Robert B. Pease
69. Term expires 1996 (1, 5). Senior Vice President, National Development
Corporation (real estate); Executive Director, Allegheny Conference on Community
Development, 1968-91. Directorships include the Port Authority of Allegheny
County and the Regional Industrial Development Corporation of Southwestern
Pennsylvania.
Eric W. Springer
65. Term expires 1996 (1, 4). Partner of Horty, Springer and Mattern, P.C.
(attorneys-at-law). Directorships include Presbyterian University Hospital.
Immediate past president of the Allegheny County Bar Association.
Wesley W. von Schack
50. Term expires 1996 (3, 4, 5, 6). Chairman, President and Chief Executive
Officer of DQE; Chairman and Chief Executive Officer of Duquesne Light.
Directorships include Mellon Bank Corporation, RMI Titanium Co. (producer of
titanium metal products), the Pittsburgh branch of the Federal Reserve Bank of
Cleveland, the Regional Industrial Development Corporation of Southwestern
Pennsylvania, the Pennsylvania Business Roundtable, and the Pittsburgh Cultural
Trust.
DQE/Duquesne Light Committees:
1. Audit
2. Compensation
3. Finance
4. Nominating
Duquesne Light Committees:
5. Employment and Community Relations
6. Nuclear Review
45
DQE Officers
Wesley W. von Schack, 50. Chairman of the Board, President and Chief Executive
Officer. Joined the company in 1984. Previously held senior executive positions
in finance and administration with other utility and communications
companies. Directorships included in listing on page 45.
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Gary L. Schwass, 49. Executive Vice President, Chief Financial Officer and
Treasurer. Previously served in a variety of senior executive positions in
finance and management with Consumers Power Company. Joined the company in 1985.
Directorships include Chairman, Western Pennsylvania Development Credit
Corporation (promotes small business through lending activities), and Vice
President and Treasurer, Holy Family Foundation (supports families in crisis).
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David D. Marshall, 42. Executive Vice President. Previously held senior
executive positions in finance at Central Vermont Public Service. Joined the
company in 1985. Directorships include the Technology Development and Education
Corporation (economic development) and the World Affairs Council (broadens local
awareness of global issues).
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James D. Mitchell, 43. Vice President. Previously held senior financial
positions with Duquesne Light and U.S. West, Inc. Joined the Company in 1988.
Directorships include Three Rivers Youth (helps troubled teenagers).
-------------------------------------------------------------------------------
Diane S. Eismont, 50
Secretary
Raymond H. Panza, 44
Controller
Morgan K. O'Brien, 34
Assistant Controller
Victor A. Roque, 48
General Counsel
Jack Saxer, Jr., 51
Assistant Treasurer
Joan S. Senchyshyn, 56
Assistant Secretary
Duquesne Light Company
Wesley W.
von Schack, 50
Chairman of the Board
and Chief Executive Officer
David D. Marshall, 42
President and
Chief Operating Officer
Gary L. Schwass, 49
Senior Vice President
and Chief Financial Officer
James E. Cross, 48
Senior Vice President, Nuclear
Dianna L. Green, 48
Senior Vice President,
Administration
Roger D. Beck, 58
Vice President, Marketing
and Customer Services
Gary R.
Brandenberger, 57
Vice President,
Power Supply
William J. DeLeo, 44
Vice President, Corporate
Performance and
Information Services
Donald J. Clayton, 40
Treasurer
Diane S. Eismont, 50
Secretary
Raymond H. Panza, 44
Controller
Victor A. Roque, 48
General Counsel
Jack Saxer, Jr., 51
Assistant Vice President,
Administration
Sally K. Wade, 41
Assistant Vice President,
Human Resources
William F. Fields, 44
Assistant Treasurer
Morgan K. O'Brien, 34
Assistant Controller
Joan S. Senchyshyn, 56
Assistant Secretary
Duquesne Enterprises
James D. Mitchell, 43
President
Kerry N. Diehl, 39
Vice President
Thomas A. Hurkmans, 29
Vice President
Anthony J. Villiotti, 48
Vice President,
Treasurer and Controller
H. Donald Morine, 57
President, Allegheny
Development Corporation
and Property Ventures, Ltd.
Montauk
Gary L. Schwass, 49
President
Donald J. Clayton, 40
Vice President
Lydia E. York, 35
Vice President
William F. Fields, 44
Treasurer
James E. Wilson, 29
Controller
46
Shareholder
Reference Guide
Common Stock
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Trading Symbol: DQE
Stock Exchanges Listed and Traded: New York, Philadelphia, Chicago
Number of Common Shareholders of Record at Year End: 79,024.
Annual Meeting
-------------------------------------------------------------------------------
Shareholders are cordially invited to attend our Annual Meeting of Shareholders
at 11 a.m. (local time), April 19, 1995, at the Manchester Craftsmen's Guild
Auditorium, 1815 Metropolitan St., Pittsburgh, PA 15233.
Direct Deposit of Dividends
-------------------------------------------------------------------------------
Your DQE quarterly dividend payments can be deposited automatically into a
personal checking or savings account. Call us toll-free for more information.
ELECTRI-STOCK Dividend Reinvestment and Stock Purchase Plan
-------------------------------------------------------------------------------
More than 40 percent of our shareholders acquire additional shares of DQE common
stock through reinvestment of their dividends and contributions of voluntary
cash. Call us toll-free to learn more about the following ELECTRI-STOCK
services:
. Purchase and sale of plan shares at nominal commissions.
. Deposit of certificates to your reinvestment account for sale or safekeeping.
. Participation in an automatic cash contributions program that allows you to
make regular voluntary cash contributions by having funds automatically
withdrawn from your bank account.
. Reregistration of your shares.
. Creation of new accounts at no charge.
. Replacement of a lost or stolen reinvestment plan sale check.
Direct Purchase of DQE Stock
-------------------------------------------------------------------------------
DQE offers non-shareholders the ability to purchase stock directly from the
company. Call us for more information.
Dividend Tax Status
-------------------------------------------------------------------------------
The company estimates that all of the common stock dividends paid in 1994 are
taxable as dividend income. This estimate is subject to audit by the Internal
Revenue Service.
Shareholder Services/Assistance
-------------------------------------------------------------------------------
By telephone, representatives are available from 7:30 a.m. to 4:30 p.m., Eastern
time.
1-800-247-0400 (toll-free)
393-6167 in Pittsburgh
FAX: 1-412-393-6087
These representatives can handle inquiries relating to . . .
Stock Transfers
Dividend Reinvestment
Dividend Payments
Change of Address Notification
Missing Stock Certificates
Direct Deposit of Dividends
Written inquiries should be directed to:
DQE
Shareholder Relations
Box 68
Pittsburgh, PA 15230-0068
Stock transfers should be sent to the Bank of Boston, addressed as follows:
Bank of Boston
Transfer Processing
150 Royall Street 45-01-05
Canton, MA 02021
Telephone: 1-617-575-3120
Form 10-K
-------------------------------------------------------------------------------
If you hold or are a beneficial owner of our stock as of February 16, 1995, the
record date for the 1995 Annual Meeting, we will send you, free upon request, a
copy of DQE's Annual Report on Form 10-K, as filed with the Securities and
Exchange Commission for 1994. Requests must be made in writing to:
Secretary
DQE
Box 68
Pittsburgh, PA 15230-0068
Financial Community Inquiries
-------------------------------------------------------------------------------
Analysts, investment managers, and brokers should direct their inquiries to 412-
393-4133. Written inquiries should be sent to:
Investor Relations Department
DQE
Box 68
Pittsburgh, PA 15230-0068
FAX: 1-412-393-6448
Reg. U.S. Pat. & Tm. Off.
DQE and its affiliated companies are
Equal Opportunity Employers.
47
[LOGO OF DQE]
[RECYCLED LOGO] The 1994 DQE Annual Report was printed entirely on recycled
paper and is 100 percent recyclable.
48