SCHEDULE 14A
(Rule 14a-101)
INFORMATION REQUIRED IN PROXY STATEMENT
SCHEDULE 14A INFORMATION
Proxy Statement Pursuant to Section 14(a) of the Securities Exchange Act of 1934
Filed by the Registrant [X]
Filed by a Party Other than the Registrant [ ]
Check the appropriate box:
[ ] Preliminary Proxy Statement [ ] Confidential, for Use of the
Commission Only (as permitted by
[ ] Definitive Proxy Statement Rule 14a-6(e)(2))
[X] Definitive Additional Materials
[ ] Soliciting Material Pursuant to Rule 14a-11(c) or Rule 14a-12
PACIFICORP
(Name of Registrant as Specified in Its Charter)
Payment of Filing Fee (check the appropriate box):
[ ] No fee required.
[ ] Fee computed on table below per Exchange Act Rules 14a-6(i)(1) and 0-11.
(1) Title of each class of securities to which transaction applies:
(2) Aggregate number of securities to which transaction applies:
(3) Per unit price or other underlying value of transaction computed
pursuant to Exchange Act Rule 0-11 (Set forth the amount on which the
filing fee is calculated and state how it was determined):
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[X] Fee paid previously with preliminary materials.
[ ] Check box if any part of the fee is offset as provided by Exchange Act Rule
0-11(a)(2) and identify the filing for which the offsetting fee was paid
previously. Identify the previous filing by registration statement number,
or the Form or Schedule and the date of its filing.
(1) Amount previously paid:
(2) Form, Schedule or Registration Statement No.:
(3) Filing Party:
(4) Date Filed:
<PAGE>
in many ways, we're back to our roots. we think there is
great value in the strategy that has brought us back. here's
why.
the pacificorp 1998 annual report
<PAGE>
a winning combination
o a word about ScottishPower and the pending merger
<PAGE>
who is ScottishPower?
On December 7, 1998, PacifiCorp announced a definitive agreement to merge with
ScottishPower, a leading multi-utility located in the United Kingdom.
The combined company, to be called ScottishPower, will have approximately 7
million customers and 23,500 employees worldwide. The headquarters will be in
Glasgow, Scotland, with U.S. headquarters remaining in Portland, Oregon.
PacifiCorp will continue to operate as Pacific Power and Utah Power in its
retail service territories.
Under the terms of the agreement, each PacifiCorp shareholder will receive
tax-free 0.58 American Depositary Shares (ADSs) or 2.32 ordinary shares of
ScottishPower for each share of PacifiCorp.
Based on a share price of 650p, the ScottishPower reference share price used in
negotiations, the merger terms imply a price of $25 1/8 per PacifiCorp common
share, representing a significant premium over the trading value of PacifiCorp
stock at that time. Based on the closing price of ScottishPower on December 4,
1998, the last business day prior to the announcement, the merger terms imply a
value for the equity of PacifiCorp of $7.9 billion. The premium will depend on
the stock prices of ScottishPower and PacifiCorp at the time the merger is
final.
The merger is subject to approval by the shareholders of both companies, the
U.S. Federal Energy Regulatory Commission and the regulatory commissions in
certain of the states served by PacifiCorp. The merger already received
clearance under the Hart-Scott-Rodino Antitrust Improvements Act and from
Australian and U.K. regulatory authorities. As we went to press with this annual
report, proxy materials had been mailed to all shareholders, and all regulatory
filings had been made.
<PAGE>
The ScottishPower Group
[map depicting ScottishPower territories omitted]
<PAGE>
ScottishPower and PacifiCorp
ScottishPower's ordinary shares will continue to be listed in London and
ScottishPower's ADSs, each representing four ordinary shares, will continue to
be listed in New York. PacifiCorp shareholders can choose whether they receive
ScottishPower ADSs or ordinary shares.
We believe this proposed merger offers significant benefits to our customers and
delivers good value to our shareholders. Together, we will work to provide
enhanced services to customers, utilizing the best practices of each company in
the U.S., U.K. and Australia.
With ScottishPower, we will be able to pursue more effectively our strategy of
concentrating on our core electricity business, improving performance for both
customers and shareholders.
ScottishPower, a leading multi-utility company in the United Kingdom, has a
proven track record of delivering value to shareholders through improving
operating efficiencies and integrating acquisitions. ScottishPower serves 5
million customers - about one in five British households.
The company's activities span the generation, transmission, distribution and
supply of electricity, gas supply, water and wastewater services and
telecommunications. ScottishPower is one of the largest companies in the U.K.
with a market capitalization of $13.5 billion.
Scottish Power has quickly grown from a regional electricity company to one of
the 25 largest investor-owned utilities in the world. With a strong financial
and operations position, ScottishPower is dedicated to delivering benefits to
customers and enhanced returns to shareholders. The transaction is expected to
close by the end of 1999.
<PAGE>
<TABLE>
<CAPTION>
1998 financial highlights
1998 to 1997
percentage
for the year || millions of dollars, except per share amounts 1998 1997 comparison
- ---------------------------------------------------------------------------------- ------------ ------------
<S> <C> <C> <C>
Operating Results
Revenues $ 5,580 $ 4,549 23%
Income from Operations 681 811 (16)
Income from Continuing Operations 111 233 (52)
Discontinued Operations (147) 447 (133)
Extraordinary Item - (16) 100
Net Income (Loss) (36) 664 (105)
Earnings (Loss) on Common Stock (55) 641 (109)
Data per Common Share
Earnings
Continuing Operations $ 0.30 $ 0.71 (58)
Discontinued Operations (0.49) 1.50 (133)
Extraordinary Item - (0.05) 100
Total (0.19) 2.16 (109)
Dividends Paid 1.08 1.08 -
Book Value 13.31 14.55 (9)
Stock Price Range 26 3/4 - 18 3/4 27 5/16 - 19 1/4 (23)/a
Financial Position at December 31
Assets 12,989 13,627
Capitalization 9,658 9,870
Capital Structure
Total Debt 53% 50%
Preferred Securities of Trusts 4 4
Preferred Stock 2 2
Common Equity 41 44
Other Statistics
Return on Average Common Equity/b (1.3)% 15.7%
Market to Book Value (Year End) 158% 188%
Cash Flows from Continuing Operations $ 685 $ 836
Common Shares (Average, Thousands) 297,229 296,094
Dividend Payout Ratio/b (610)% 50%
/a Based on year end price.
/b 1998 includes the effects of the provision for losses on discontinued
operations of $105 million, or $0.35 per share, special charges of $77
million, or $0.26 per share, and other adjustments of $132 million, or
$0.45 per share. 1997 includes the effect of gains on sales of assets of
$395 million, or $1.33 per share, special charges of $106 million, or $0.36
per share, other adjustments of $65 million, or $0.22 per share, and
extraordinary item of $16 million, or $0.05 per share. If these items were
excluded, the Return on Average Common Equity in 1998 and 1997 would have
been 6.2% and 10.6%, respectively. The Dividend Payout Ratio in 1998 and
1997 would have been 124% and 74%, respectively.
</TABLE>
[graphic bar chart depicting total investment return omitted]
<PAGE>
fellow shareholders,
- -----------------------------------------------------------
In a difficult year for PacifiCorp, I am pleased that we put into
action measures that were in the best interest of our shareholders.
In April, we announced the end of our attempt to acquire The Energy
Group (TEG). The decision was not easy, but the price of TEG had risen
to a level that we believed would not provide acceptable returns for
our shareholders.
Our regret in the outcome of the TEG transaction was compounded by our
poor earnings results. Overall, we reported a net loss for the year of
$55 million, or $0.19 per share, and our share price declined 19
percent.
[picture of Mr. McKennon omitted]
Keith R. McKennon
CHAIRMAN, PRESIDENT AND
CHIEF EXECUTIVE OFFICER
3.
<PAGE>
- -----------------------------------------------------------
Such results are unacceptable to me, to your board of directors, and to
PacifiCorp's management team. When your board of directors elected me
as CEO in September 1998, I was asked to provide a realistic assessment
of PacifiCorp and to recommend actions to improve shareholder value. To
make my recommendations as meaningful as possible, I met with
securities analysts, investors, customers and employees, and the
message was clear: the company required a new, fully focused and
achievable strategic direction.
That strategy is to return to our roots, to the business we know best.
In October, we announced that we would focus on our western U.S.
electricity business and sell or shut down all unrelated endeavors with
the exception of Powercor, our Australian electricity distribution
company.
We also embarked on an aggressive program to cut costs to address our
realization that PacifiCorp must be smaller, leaner and have lower
overhead. An early retirement program resulted in a net reduction of
more than 700 jobs, and we expect to make more reductions in staff and
support areas.
4.
<PAGE>
But even as we continue to in divesting nonstrategic assets we
accomplish two goals: provide additional cash resources while putting
all of our attention on our core business.
- -----------------------------------------------------------
reduce costs, we remain committed to improved customer service and
reinvestment in our electric operations.
We also remain committed to the current annual dividend of $1.08 per
share, and our goal is to deliver a five percent average annual growth
in earnings per share, starting in the year 2000.
When our strategic refocus was announced, I also promised to listen to
anyone who had a proposal for building shareholder value better and
faster. ScottishPower, a leading multi-utility located in the United
Kingdom, made such a proposal and, in December 1998 our two companies
announced a proposed merger. We believe this merger is in the best
interests of our customers and delivers good value to our shareholders.
The transaction also creates an opportunity for our shareholders to own
a stake in a larger, faster-growing and financially strong company,
which has excellent prospects for the future.
5.
<PAGE>
- -----------------------------------------------------------
With ScottishPower, we will be able to pursue more effectively our
strategy of concentrating on our core electricity business in the west.
The merger affirms the direction we have chosen and will provide a
strong platform for future growth. We believe that the transaction will
also enhance our ability to improve our performance and better serve
our customers. It is important to note that the merger is subject to
the approval of certain federal and state regulatory bodies, including
the Federal Energy Regulatory Commission and regulatory commissions in
Idaho, Oregon, Utah, Washington, Wyoming and California.
Within the framework of our chosen strategy, the people of PacifiCorp
have clear direction and purpose: listen to customers; be alert to
greater efficiencies; and view these changes as opportunity. Our people
possess the knowledge, skills and initiative necessary to successfully
execute our new strategy and the merger with ScottishPower. One person
we will miss is Don Wheeler, from Salt Lake City. He has been a member
of our board of directors for 10 years and has made a substantial
contribution to our company. Don retired from the board in February
1999, and I would like to thank him for his dedication to PacifiCorp
and its stakeholders.
6.
<PAGE>
the people of PacifiCorp have clear direction and purpose: listen
to customers; be alert to greater efficiencies; and consider
these changes as opportunity
- -----------------------------------------------------------
The future of your company is bright. PacifiCorp is located in one of
the fastest-growing parts of the country. Our fundamentals remain sound
with low-cost generation, an extensive transmission grid, knowledgeable
employees and more than 85 years of reliable service to customers. We
have the opportunity to grow both our regulated and unregulated
business in the west, and our success in the west will provide the
foundation for building shareholder value. As a fellow shareholder, I'd
like to thank you for your continued support.
Sincerely,
KEITH R. MCKENNON
Keith R. McKennon
CHAIRMAN, PRESIDENT AND
CHIEF EXECUTIVE OFFICER
7.
<PAGE>
[picture omitted]
8.
<PAGE>
We began by asking what best serves our
shareholders and our customers. With that as a
starting point, the decisions we've made are
pretty straightforward.
o core business o customer focus o cost reductions
9.
<PAGE>
PacifiCorp began in 1910 as the Pacific Power and Light Company. At the
time, we provided electricity to 7,000 rural customers in the states of
Oregon and Washington.
Today, we are a Fortune 500 company providing electricity and energy
services to 1.5 million customers in the western states of California,
Idaho, Oregon, Utah, Washington and Wyoming. We also serve 560,000
electricity customers in the Australian states of Victoria and New
South Wales through Powercor, our Australian electricity distribution
company.
We own or have ownership interests in five coal mines, which enables us
to mine most of the coal we need for power generation. In 1998 we mined
22 million tons of coal, and though much of it is low-sulfur coal from
the Powder River basin in Wyoming, scrubbers are installed on most of
our plants to further reduce sulfur dioxide emissions. We have also
been recognized by the U.S. Bureau of Surface Mine Reclamation for our
award-winning coal mine reclamation efforts, and in a study released in
April 1999 by The Mine Safety and Health Administration, our Bridger
Coal Mine ranked first among U.S. surface coal mines for safety.
Having mine operations next to our power plants helps us to operate
some of the lowest-cost generating plants in the U.S., and contributes
to our position as one of the lowest-cost electricity suppliers in the
country. Our average net retail price is 4.7 cents per kilowatt-hour,
compared to the national average of more than 7 cents.
-----------------------------------------------------------------------
Our average net retail price is 4.7 cents per kilowatt-hour, compared
to the national average of more than 7 cents.
-----------------------------------------------------------------------
We own three major hydroelectric systems, and own or have interests in
17 thermal electric generating plants, giving us a total of 8,445
megawatts of low-cost generation.
Access to the nation's most extensive transmission network also
provides us with low-cost power supply options, in addition to
opportunities to sell power. The 15,000 miles of transmission lines
10.
<PAGE>
give us nearly 150 points of interconnection and enable us to buy and
sell power with more than 60 other utilities.
All of these factors - low-cost generation, geographically diverse
energy resources and an extensive transmission system - benefit our
retail customers, and have also helped us develop a highly competitive
wholesale energy business: in the western U.S., we are the largest
wholesale power marketer among investor-owned utilities.
-----------------------------------------------------------------------
In the western U.S., we are the largest wholesale power marketer among
investor-owned utilities.
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In October, we embarked on a significant change in our strategic
direction, designed to optimize these strengths and to improve our
financial performance. That strategy is to focus on our domestic
western electricity business and sell or shut down all unrelated
businesses except for Powercor, our Australian electricity distribution
business.
Our commitment to shareholders is to deliver a five percent average
annual growth in earnings per share, starting in the year 2000. We also
intend to maintain the annual dividend at $1.08 per share. Our strong
balance sheet and sustainable cash position allow us to return value to
our shareholders via the dividend while we work on improving our
earnings.
In addition to providing good value to our shareholders, we are equally
dedicated to finding new and innovative ways to enhance customer
service and system reliability. We have already taken significant steps
since October 1998 to improve billing and collections, power outage
management, community relationships and business center performance. We
are committed to providing the best among utility basics: low-cost,
reliable power and exceptional customer service.
Of all the strategic options we considered, this approach is clearly
focused on what we do best, and with real dedication, it will bring the
most value to both our shareholders and customers.
11.
<PAGE>
[picture omitted]
12.
<PAGE>
We are committed to providing the best
among utility basics: low-cost, reliable power
and exceptional customer service.
o initiatives o divestitures o improvements
13.
<PAGE>
Our priority is to improve the operating and financial performance of
our core business, and by doing so, enhance value for our shareholders.
We intend to do this through cost reductions and by seeking rate
increases where necessary. In January 1999 we deferred our request for
rate increases for six months in order to place the highest priority on
completing our merger with ScottishPower. However, we are determined to
earn our authorized rate of return in each of the states where we do
business, and will assess the need to seek rate relief later in the
year.
To reduce costs and improve cash flow from operations, we implemented
two aggressive cost reduction programs. An early retirement program
announced in January 1998 resulted in a net reduction of more than 700
jobs, and annual pre-tax cost savings of approximately $50 million. In
the fourth quarter of 1998 we implemented a second cost reduction
program aimed at achieving an additional pre-cost savings of $30
million from our continuing business.
-----------------------------------------------------------------------
To reduce costs and improve cash flow from operations, we executed two
aggressive cost reduction programs.
-----------------------------------------------------------------------
We moved quickly to implement our new strategy, successfully closing or
selling the majority of the underperforming assets that detracted from
our core business. In the past six months we have: closed the eastern
U.S. electricity-trading arm of PacifiCorp Power Marketing; shut down
our business development activities in Turkey; agreed in March to the
sale of EnergyWorks, our joint venture with Bechtel Enterprises; and in
April sold TPC Corporation, our natural gas storage and marketing
business for $150 million.
The divestiture of other non-core businesses is also progressing,
including our energy development activities in the Philippines, our
investment in the Hazelwood Power Station in Australia and our
investment in enoable, our joint venture with KN Energy.
14.
<PAGE>
In July 1998 we announced our intention to sell our electric service
areas in California and Montana. The following November we finalized
the sale of our Montana distribution system to Flathead Electric
Cooperative for $92 million, and in April 1999 we announced the signing
of a non-binding letter agreement with Nor-Cal Electric Authority for
the sale of our California service area. The sale of these properties
will allow us to focus on states where we have a larger customer base
and more significant investment in assets.
Focusing on the needs of our 1.5 million customers is also an integral
part of our strategy. We reorganized our service functions in 1998 to
be more responsive to our customers and to the communities we serve.
-----------------------------------------------------------------------
In 1998 we reorganized our service functions to be more responsive to
our customers and to the communities we serve.
-----------------------------------------------------------------------
Our customers first point of contact with PacifiCorp is usually through
our business centers in Salt Lake City, Utah and Portland, Oregon. To
make that contact as pleasant and productive as possible, we are
improving service levels at our business centers through employee
training programs, the creation of more efficient work shifts and
process improvement efforts.
To ensure that we continue to provide our customers with reliable
service, we intend to have our generation, transmission and
distribution systems ready for the year 2000 by July 1999. We began our
year 2000 preparations in 1996. Since then, we have dedicated
significant time and resources to making sure our systems are
performing optimally in the year 2000.
These actions mark the beginning of a host of initiatives that will
improve our performance, and we are on track to deliver exceptional
customer service and better operations efficiency.
15.
<PAGE>
[picture omitted]
16.
<PAGE>
It would be easy to undervalue PacifiCorp.
Yet, while there is much work to do, we believe that with your
continued support, the future for your company is bright.
o credibility o accountability o results
17.
<PAGE>
In 1998 we made solid progress toward implementing a strategic refocus
on our domestic western electricity business. We moved quickly to
execute our new strategy by selling non-core businesses, implementing a
cost reduction program and making changes designed to improve customer
service and reliability.
These efforts are yielding results. Our recurring earnings for the
fourth quarter 1998, the first reporting period following the
implementation of our strategy, were in line with expectations, as were
first quarter 1999 earnings.
Our renewed emphasis on our western electricity business also extends
to our environmental efforts and to the communities where we live and
work. We achieved two major milestones in these areas in the past year.
In April 1999 we began energy production at the Wyoming Wind Energy
Project, one of the largest wind plants in the West outside of
California. The facility is located on 2,156 acres between Laramie and
Rawlins, Wyoming. The 69 wind energy turbines generate up to 41.4
megawatts of electricity, enough renewable power to serve 15-20,000
customers.
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Our new Wyoming wind plant is capable of generating 41.4 megawatts of
electricity, enough renewable power to serve 15-20,000 customers.
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We own 80 percent of the $62 million project, and Eugene Water and
Electric Board (EWEB) of Eugene, Oregon, owns the balance. Bonneville
Power Administration has already committed to buy 15 megawatts of the
plant's output.
The project benefits a variety of stakeholders: tax revenues from the
project will support local schools and community development efforts;
consumers have access to an affordable, renewable energy
18.
<PAGE>
source; and the environment remains largely unaffected by the facility.
Only one percent of the land will be removed from local use; local
ranchers can use the remaining acreage for grazing livestock.
As a result of this project, we were the recipients of Renewable Energy
Northwest's Clean Energy Award, and received notice for our efforts in
the Senate Congressional Record.
A high point was also reached in our efforts to serve our communities.
In 1998 we celebrated a decade of community commitment and support
through the PacifiCorp Foundation. The Foundation was created in 1988
as a separate, nonprofit entity with a permanent endowment. It is the
major philanthropic arm of PacifiCorp, Pacific Power and Utah Power,
and helps to promote the health and vitality of our communities.
In 10 years we have built the third largest utility foundation
endowment in the U.S. and have contributed $25 million through more
than 4,000 grants to a variety of organizations. Each year awards are
made in four categories: civic and community organizations; education
and research; culture and arts; and health and human services - with an
emphasis on children, the environment and safety.
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In 10 years we have built the third largest utility foundation in the
U.S., and contributed $25 million to our communities.
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We are accountable to many stakeholders, and we have a proud history of
commitment and service to customers, shareholders, communities and the
environment. We have made solid progress toward implementing a strategy
designed to strengthen our core business and our service. While there
is still much work to be done, the results we have achieved so far
indicate that we are taking the right actions to improve the
performance of our company and build credibility with all our
stakeholders.
19.
<PAGE>
1998 financial review
<PAGE>
-----------------------------------------------------------------
pg 22: management's discussion and analysis. pg 44: report of
management. pg 45: independent auditors' report. pg 46: financial
statements. pg 51: notes to consolidated financial statements.
-----------------------------------------------------------------
20.
<PAGE>
MANAGEMENT'S DISCUSSION AND ANALYSIS
OVERVIEW OF 1998
During 1998, PacifiCorp and its subsidiaries (the "Company") took several major
steps to redefine its objectives, reduce costs and develop plans for the future.
In March, the Company abandoned its attempt to acquire The Energy Group PLC
("TEG") after another United States utility made a higher offer for TEG and the
Company elected not to increase its offer. Subsequently, the Company reviewed
its strategy and decided to refocus on its electricity businesses in the western
United States and Australia and to exit its other domestic and international
businesses. The businesses to be exited include the eastern United States
electricity trading business of PacifiCorp Power Marketing, Inc. ("PPM"), the
natural gas marketing and storage business of TPC Corporation ("TPC") and most
of the Company's energy development businesses.
On December 6, 1998, PacifiCorp signed an Agreement and Plan of Merger with
Scottish Power plc ("ScottishPower") and NA General Partnership. ScottishPower
subsequently announced its intention to establish a new holding company for the
ScottishPower group pursuant to a court approved reorganization in the U.K.
Accordingly, on February 23, 1999, the parties executed an amended and restated
merger agreement (the "Agreement") under which PacifiCorp will become an
indirect, wholly owned subsidiary of the new holding company, which will be
renamed Scottish Power plc ("New ScottishPower"), and ScottishPower will become
a sister company to PacifiCorp. The combined company will have seven million
customers and 23,500 employees worldwide and will be headquartered in Glasgow,
Scotland. PacifiCorp will continue to operate under its current name, and its
headquarters will remain in Portland, Oregon.
In the merger, each share of PacifiCorp's common stock will be converted into
the right to receive 0.58 New ScottishPower American Depositary Shares ("ADS")
(each New ScottishPower ADS represents four ordinary shares), which will be
listed on the New York Stock Exchange, or, upon the proper election of the
holders of PacifiCorp's common stock, 2.32 ordinary shares of New ScottishPower,
which will be listed on the London Stock Exchange. Based on the issued and
outstanding shares of ScottishPower and PacifiCorp on February 1, 1999, the
holders of PacifiCorp's common stock will receive approximately 36% of the total
issued share capital of New ScottishPower upon consummation of the merger. Based
on the market prices of the ScottishPower ordinary shares and PacifiCorp's
common stock on February 26, 1999, holders of PacifiCorp's common stock would
receive a premium of approximately 17% over the closing sale price of
PacifiCorp's common stock of $18.00.
If the proposed reorganization is not completed, the parties will proceed
under the original agreement, and PacifiCorp will become an indirect, wholly
owned subsidiary of ScottishPower. The merger is not conditional on the
reorganization becoming effective nor is the reorganization conditional upon the
merger becoming effective.
Both companies' boards of directors have approved the Agreement. However,
before the transactions under the Agreement can be consummated, a number of
conditions must be satisfied, including obtaining approvals and consents from
shareholders of both companies, the United States Federal Energy Regulatory
Commission ("FERC"), the United States Nuclear Regulatory Commission, the
regulatory commissions in certain of the states served by the Company and
Australian regulatory authorities. Generally, approval by the state regulatory
commission is subject to a finding that the transaction is in the public
interest. The commissions may attach conditions to their approval. Hearings on
the merger have been scheduled for July and August 1999 by the Oregon, Utah,
Wyoming and Idaho commissions. The parties have received early termination of
the waiting period under the provisions of the Hart-Scott-Rodino Antitrust
Improvement Act. Both companies expect to have shareholder meetings in mid-1999
requesting shareholder approval of the merger.
In January 1998, the Company moved to reduce costs through an early
retirement offering that resulted in a net decrease of 759 employees. In
December 1998, the Company implemented a $30 million annual cost reduction
program focused on further work force and overhead expense reductions.
On March 4, 1999, the Utah Public Service Commission (the "UPSC") issued an
order in a general rate case. In the order, the Company was required to refund
$40 million through a credit on customer bills and to reduce annual revenues by
$85 million, or 12%, effective March 1, 1999.
21
<PAGE>
EARNINGS OVERVIEW OF THE COMPANY
<TABLE>
<CAPTION>
millions of dollars, except per share information 1998 1997 1996
- -----------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C>
EARNINGS CONTRIBUTION (LOSS) ON COMMON STOCK
Domestic Electric Operations $ 130.5 $ 165.5 $ 341.5
Australian Electric Operations1 3.0 54.2 31.9
Other Operations (52.2) (9.6) 27.1
---------------------------------------
Continuing Operations 91.3 210.1 400.5
Discontinued Operations (146.7) 446.8 74.6
Extraordinary item - (16.0) -
---------------------------------------
$ (55.4) $ 640.9 $ 475.1
=======================================
EARNINGS (LOSS) PER COMMON SHARE - BASIC AND DILUTED
Continuing Operations $ 0.30 $ 0.71 $ 1.37
Discontinued Operations (0.49) 1.50 0.25
Extraordinary item - (0.05) -
---------------------------------------
$ (0.19) $ 2.16 $ 1.62
=======================================
</TABLE>
In 1998 and 1997, the Company incurred a series of special charges, discontinued
operations of certain businesses and incurred acquisition transaction costs. The
table below sets forth the effects of these adjustments to assist the reader,
but should not be construed to represent Generally Accepted Accounting
Principles. Other than ScottishPower merger costs, the items summarized below
are not expected to be recurring.
EFFECTS OF ADJUSTMENTS ON EARNINGS (LOSS) PER COMMON SHARE
<TABLE>
<CAPTION>
1998 1997
-----------------------------------------------
millions of dollars, except per share information total per share total per share
- ------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C>
Earnings (loss) in total and per common share - as reported $(55.4) $(0.19) $640.9 $ 2.16
REMOVE DISCONTINUED OPERATIONS
(Income) loss of discontinued operations 41.7 0.14 (81.7) (0.27)
Provision for losses of discontinued operations 105.0 0.35 - -
Gain on sale of discontinued operations - - (365.1) (1.23)
Remove extraordinary item - - 16.0 0.05
-----------------------------------------------
Earnings from Continuing Operations 91.3 0.30 210.1 0.71
ADJUSTMENTS - DOMESTIC ELECTRIC OPERATIONS
Special charges 76.5 0.26 105.7 0.36
ScottishPower merger costs 13.2 0.04 - -
Utah rate refund 23.4 0.08 - -
ADJUSTMENTS - AUSTRALIAN ELECTRIC OPERATIONS
Write down of Hazelwood 17.4 0.06 - -
ADJUSTMENTS - OTHER OPERATIONS
TEG costs and option losses 55.4 0.19 64.5 0.22
Gain on sale of TEG shares (9.8) (0.03) - -
Write down of other energy businesses 32.4 0.11 - -
Asset sale gains - - (30.0) (0.10)
-----------------------------------------------
Total $299.8 $ 1.01 $350.3 $ 1.19/a
===============================================
/a In 1997, the Company reported adjusted earnings per share of $1.52.
Included in the calculation of $1.52 were earnings from discontinued
operations and adjustments similar to those recorded in 1998 operations.
</TABLE>
22
<PAGE>
Earnings on common stock for the Company decreased $696 million, or $2.35 per
share, compared to 1997. The Company's reported 1998 loss of $55 million, or
$0.19 per share, included special charges of $77 million, or $0.26 per share,
relating to the Company's early retirement program announced in January 1998 and
the additional early retirement offer announced in the fourth quarter of 1998,
$23 million, or $0.08 per share, relating to the Utah rate case, $13 million, or
$0.04 per share, for ScottishPower merger costs, $54 million, or $0.18 per
share, relating to the write off of costs associated with the TEG transaction,
$2 million, or $0.01 per share, relating to closing foreign currency options in
April 1998 associated with the termination bid for TEG and a $10 million, or
$0.03 per share, gain relating to the sale of the TEG shares. In addition, the
Company recorded charges in 1998 of $105 million, or $0.35 per share, relating
to the provision for losses on disposition of the energy trading segment, $17
million, or $0.06 per share, relating to the write down of the Company's
investment in Hazelwood, and $32 million, or $0.11 per share, relating to the
provision for losses on disposition of other energy development businesses.
The Company's 1997 earnings of $641 million included asset sale gains of $395
million, or $1.33 per share, relating to sales of the Company's
telecommunications subsidiary and independent power business. Domestic Electric
Operations recorded $106 million, or $0.36 per share, of special charges
relating to an accrual for a coal mine closure, write off of deferred regulatory
pension assets and impairment of information technology systems. Additionally,
the Company recorded losses of $65 million, or $0.22 per share, relating to
foreign currency exchange contracts associated with the bid for TEG and a $16
million, or $0.05 per share, extraordinary charge for the write off of allocable
generation regulatory assets in California and Montana.
Excluding the asset sale gains, special charges and other adjustments, the
Company's 1998 earnings on common stock from continuing operations before
extraordinary item would have been $300 million, or $1.01 per share, compared to
$350 million, or $1.19 per share, in 1997, a decrease of $50 million, or $0.18
per share.
DOMESTIC ELECTRIC OPERATIONS' contribution to earnings on common stock was
$131 million, or $0.44 per share, in 1998. After adjusting earnings by $113
million, or $0.38 per share, for special charges, the Utah rate refund and other
adjustments, the contribution was $244 million, or $0.82 per share. Domestic
Electric Operations' contribution to earnings on common stock in 1997 was $271
million, or $0.92 per share, after adjusting earnings by $106 million, or $0.36
per share, for special charges. This $27 million decrease from 1997 earnings was
the result of several factors, including lower wholesale margins in the western
United States, less favorable hydroelectric conditions, costs relating to Year
2000 issues and implementation of a new SAP software operating environment.
AUSTRALIAN ELECTRIC OPERATIONS' contribution to earnings on common stock was
$13 million, or $0.04 per share, in 1998. After adjusting earnings by $17
million, or $0.06 per share, for the write down of the Company's investment in
the Hazelwood Power Station and $7 million, or $0.02 per share, for currency
exchange rate fluctuations, the contribution was $37 million, or $0.12 per
share. The currency exchange rate for converting Australian dollars to United
States dollars averaged 0.63 in 1998 compared to 0.74 in 1997, a 15% decrease.
The effect of this change in exchange rates lowered United States dollar
revenues by $112 million and costs by $105 million in 1998. The 1998 earnings
were impacted by increased network fees due to the effects of contestability and
a product recall loss. In addition, 1997 results included earnings associated
with renegotiating certain Tariff H industrial customer contracts that added $10
million, or $0.03 per share.
OTHER OPERATIONS reported net losses of $52 million in 1998, or $0.17 per
share, as compared to a loss of $10 million, or $0.03 per share, in 1997.
Losses relating to the decision to exit the energy development businesses
totaled $32 million, or $0.11 per share. The 1998 results also included $54
million, or $0.18 per share, in costs associated with the Company's terminated
bid for TEG, $2 million, or $0.01 per share, relating to closing foreign
currency options in April 1998, and a gain of $10 million, or $0.03 per share,
relating to the sale of the TEG shares. The 1997 results included a loss of $65
million, or $0.22 per share, associated with closing foreign currency options
and initial option premium costs relating to the Company's offer for TEG. Other
Operations in 1997 also included a $30 million, or $0.10 per share, gain on the
sale of Pacific Generation Company ("PGC").
DISCONTINUED OPERATIONS reported losses of $147 million, or $0.49 per share,
in 1998 compared to income in 1997 of $447 million, or $1.50 per share. The 1998
results included $105 million, or $0.35 per share, for the losses anticipated to
dispose of TPC and exit the eastern United States energy trading business and a
loss of $42 million, or $0.14 per share, relating to these operations prior to
discontinuance. The 1997 results included the gain on the sale of the Company's
telecommunications operations and the earnings from normal operations until
their sale in December 1997.
23
<PAGE>
<TABLE>
<CAPTION>
1997 ASSET SALE GAINS
net cash pretax net
millions of dollars from sales/a gains income eps
- ---------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C>
PTI sale $1,198 $671.0 $365.1 $ 1.23
PGC sale 96 56.5 30.0 0.10
---------------------------------------------
$1,294 $727.5 $395.1 $ 1.33
=============================================
/a Cash from asset sales is net of income taxes.
</TABLE>
On December 1, 1997, the Company completed the sale of Pacific Telecom, Inc.
("PTI") for $1.5 billion in cash, plus the assumption of PTI's debt. The Company
realized an after-tax gain of $365 million, or $1.23 per share. For the eleven
months ended November 30, 1997, PTI reported net income of $89 million, or $0.30
per share, compared to $75 million, or $0.25 per share, for all of 1996.
In November 1997, the Company completed the sale of its independent power
subsidiary, PGC, for approximately $150 million in cash, which resulted in a
gain of $30 million, or $0.10 per share.
DOMESTIC ELECTRIC OPERATIONS
REVENUES
<TABLE>
<CAPTION>
millions of dollars 1998 1997 1996
- ----------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C>
REVENUES
Wholesale sales and market trading $ 2,583.6 $ 1,428.0 $ 738.8
Residential 806.6 814.0 801.4
Industrial 705.5 709.9 719.3
Commercial 653.5 640.9 623.3
Other 95.9 114.1 109.0
------------------------------------
$ 4,845.1 $ 3,706.9 $2,991.8
====================================
</TABLE>
<TABLE>
<CAPTION>
millions of kWh 1998 1997 1996
- ----------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C>
ENERGY SALES
Wholesale sales and market trading 94,077 59,143 29,665
Residential 12,969 12,902 12,819
Industrial 20,966 20,674 20,332
Commercial 12,299 11,868 11,497
Other 651 705 640
-------------------------------------
140,962 105,292 74,953
=====================================
</TABLE>
Domestic Electric Operations' revenues increased $1.14 billion, or 31%, from
1997 to $4.85 billion in 1998 primarily from an increase in wholesale revenues
of $1.16 billion, or 81%. Retail revenues were flat compared to 1997, remaining
at $2.20 billion. Although wholesale trading revenues have grown substantially
over the past few years, in 1998 the retail load represented 45% of total
Domestic Electric Operations' revenues.
The active wholesale market led to an increase in revenues of $1.16 billion,
or 81%, in 1998 to $2.58 billion. Energy volumes increased 59%, driven by a $917
million increase in short-term firm and spot market sales. Sales prices for
short-term firm and spot market sales averaged $26 per megawatt hour ("MWh") in
1998, compared to $20 per MWh in 1997, resulting in $242 million in additional
revenues. Decreased long-term firm contract volumes lowered wholesale revenues
by $3 million in 1998. The Company expects a reduced level of revenues in 1999
as a result of its decision to scale back short-term wholesale trading
activities.
24
<PAGE>
Residential revenues were down $7 million, or 1%, to $807 million in 1998.
Growth in the average number of residential customers of 2% added $19 million to
revenues. The Utah rate order reduced revenues by $16 million. Declines in
customer usage, partially attributable to weather, reduced revenues by $13
million in 1998 compared to 1997.
Industrial revenues decreased $4 million, or 1%, to $706 million in 1998. The
Utah rate order reduced revenues by $8 million. Billing adjustments of $5
million for certain industrial customers reduced revenues in 1997.
Commercial revenues increased $13 million, or 2%, to $654 million in 1998.
Energy sales volumes increased 4% over the prior year. A 2% growth in the
average number of customers added $17 million to revenues, and increased
customer usage added $5 million to revenues. The Utah rate order reduced
revenues by $13 million.
Other revenues decreased by $18 million, or 16%, to $96 million in 1998. The
primary cause of this unfavorable variance was revenue adjustments relating to
changes in property tax legislation.
1997 COMPARED TO 1996 Revenues rose 24%, or $715 million, in 1997 primarily
due to a 99% increase in kilowatt hours ("kWh") sold in the wholesale market.
Residential revenues were up $13 million primarily due to a 3% growth in the
average number of customers and a price increase in Oregon effective July 1996.
Commercial revenues increased $18 million primarily due to customer growth of 2%
in Oregon and 5% in Utah.
In early 1997, the Utah Division of Public Utilities (the "UDPU") and the
Utah Committee of Consumer Services (the "UCCS") filed a joint petition with the
UPSC requesting the UPSC to commence proceedings to establish new rates for Utah
customers. The UDPU and the UCCS suggested changes to the method for allocating
costs among the six states with retail customers served by the Company, the
Company's authorized return on equity and certain other accounting adjustments.
Subsequently in March 1997, the Utah legislature passed a bill that created a
legislative task force to study electric restructuring and customer choice
issues in Utah. The bill precluded the UPSC from holding hearings on rate
changes and froze prices at January 31, 1997 levels until May 1998, but allowed
for retroactive price changes.
The Company agreed to an interim price decrease to Utah customers of $12.4
million annually beginning on April 15, 1997.
In November 1997, the legislative task force recommended that further study
was needed and that no legislation be proposed in the 1998 legislative session
for the deregulation of electric utilities.
During 1997, the UPSC held hearings on the method used in allocating common
(generation, transmission and corporate related) costs among the Company's
jurisdictions and issued an order in April 1998. Under the order, differences in
allocations associated with the 1989 merger of Pacific Power & Light Company and
Utah Power & Light Company were to be eliminated over five years on a
straight-line basis. The phase-out of the differences was to be completed by
January 1, 2001 and could have reduced Utah customer prices by about $50 to $60
million annually once fully implemented. The ratable impact of this order was to
be included in a general rate case thereby combining it with all other
cost-of-service items in determining the ultimate impact on customer prices.
In 1998, the UPSC commenced a general rate case to consider the impact of the
April 1998 allocation order, other cost-of-service issues and the
appropriateness of the Company's authorized rate of return on equity. On March
4, 1999, an order was issued by the UPSC in the general rate case. The order
requires the Company to reduce revenues in the state of Utah by $85 million, or
12%, annually. The UPSC also ordered that the allocation order be implemented
immediately and not phased-in as originally ordered. Additionally, the UPSC
ordered a refund to be issued through a credit on customer bills of $40 million.
The Company recorded a $38 million reduction in revenues in 1998 and will record
$2 million in 1999. The refund covers a period from March 14, 1997 to February
28, 1999. The beginning date is consistent with the timing of Utah legislation
imposing a moratorium on rate changes after the UDPU and the UCCS requested a
general rate case. The $85 million reduction will commence on March 1, 1999. The
order also reduced the Company's authorized rate of return on equity from 12.1%
to 10.5%.
The Company has asked the UPSC to reconsider issues in the order involving
approximately $41 million of the $85 million rate decrease. Among these issues
is the method of implementing the April 1998 allocation order. The Company is
not seeking reconsideration of the reduction in its authorized return on equity
to 10.5% nor the changes in the way costs are allocated among the six states
served by the Company.
25
<PAGE>
OPERATING EXPENSES
<TABLE>
<CAPTION>
millions of dollars 1998 1997 1996
- ----------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C>
Purchased power $2,497.0 $ 1,296.5 $ 618.7
Fuel 477.6 454.2 443.0
Other operations and maintenance 457.3 470.0 444.2
Depreciation and amortization 386.6 389.1 343.4
Administrative, general and taxes-other 331.4 325.4 272.7
Special charges 123.4 170.4 -
-------------------------------------
$4,273.3 $ 3,105.6 $ 2,122.0
=====================================
Operating Expenses as a percent of Revenue (excluding special charges) 86% 79% 71%
</TABLE>
Operating expenses increased $1.17 billion, or 38%, to $4.27 billion in 1998, as
a result of a significant increase in purchased power costs.
In addition to base energy and capacity from its thermal and hydroelectric
resources, the Company utilizes a mix of long-term, short-term and nonfirm power
purchases to meet its own retail load commitments and to make wholesale power
sales to other utilities. Purchased power expense increased $1.20 billion, or
93%, to $2.50 billion in 1998. The higher expense was primarily due to a 33.9
million MWh increase in short-term firm and spot market energy purchases, a 74%
increase from 1997, which increased purchased power expense by $937 million.
Short-term firm and spot market purchase prices averaged $26 per MWh in 1998
versus $19 per MWh in 1997, a 36% increase. The increase in purchase prices
added $255 million to costs in 1998. Lower volumes offset by higher prices
relating to long-term firm purchased power contracts resulted in a $4 million
increase in purchased power costs in 1998. The Company expects a reduced level
of power purchases in 1999 as a result of its decision to scale back short-term
wholesale trading activities.
SHORT-TERM FIRM AND SPOT MARKET SALES AND PURCHASES
<TABLE>
<CAPTION>
1998 1997 1996
- -----------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C>
Total sales volume (thousands of MWh) 80,097 44,927 16,394
Average sales price ($/MWh) $ 25.88 $ 20.35 $ 14.94
---------------------------------------
Revenues (millions) $ 2,073 $ 914 $ 245
---------------------------------------
Total purchase volume (thousands of MWh) 79,693 45,772 16,930
Average purchase price ($/MWh) $ 25.88 $ 19.04 $ 13.31
---------------------------------------
Expenses (millions) $ 2,062 $ 871 $ 225
---------------------------------------
Net (millions) $ 11 $ 43 $ 20
=======================================
</TABLE>
Fuel expense was up $23 million, or 5%, to $478 million in 1998. Thermal
generation increased 6% to 51.9 million MWh. The average cost per MWh increased
to $9.37 from $9.29 in the prior year due to increased generation at plants with
higher fuel costs. The shift in generation resulted from unscheduled plant
outages and higher market prices for energy. Hydroelectric generation decreased
6% compared to 1997 due to lower stream flows.
Other operations and maintenance expense decreased $13 million, or 3%, to
$457 million in 1998. Employee-related costs decreased $24 million primarily due
to the implementation of the early retirement plan initiated in the first
quarter of 1998. Partially offsetting this decrease were higher distribution
plant maintenance expenses of $6 million and higher customer service expenses of
$4 million.
Depreciation and amortization expense decreased $3 million, or 1%, to $387
million in 1998. Depreciation in 1997 included a $17 million increase reflecting
higher depreciation rates, and increased plant in service in 1998 added $9
million.
In July 1998, the Company withdrew its regulatory filings relating to a
depreciation study because regulatory approvals to increase depreciation rates
based on this study were unlikely. As a result of the decision to withdraw
26
<PAGE>
the filings, the Company ceased recording the increased depreciation expense in
the third quarter. For the six months ended June 30, 1998, the Company recorded
$6 million in additional depreciation as a result of the study.
In December 1998, the Company filed applications with the Oregon, Utah and
Wyoming regulatory commissions to increase depreciation annually by $77 million.
No amounts have been recorded as additional expense pending approval by these
commissions. The Company's intention is to seek revenue increases consistent
with the higher depreciation expense.
Administrative, general and taxes-other expenses increased $6 million, or 2%,
to $331 million in 1998. This increase included $6 million of expenses relating
to Year 2000 issues, $5 million relating to the ongoing implementation of the
Company's new SAP software operating environment and $5 million of employee
related costs. Administrative and general expenses in 1997 included process
re-engineering costs of $10 million relating to the Company's new SAP software
operating environment.
SPECIAL CHARGES
<TABLE>
<CAPTION>
net
millions of dollars pretax income eps
- -----------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C>
1998
Early retirement and cost reduction program $ 123.4 $ 76.5 $ 0.26
======================================
1997
Glenrock mine closure $ 64.4 $ 39.9 $ 0.14
Deferred regulatory pension cost 86.9 53.9 0.18
Impairment charges on IT systems 19.1 11.9 0.04
--------------------------------------
$ 170.4 $ 105.7 $ 0.36
======================================
</TABLE>
In January 1998, the Company announced a plan to reduce its work force in the
United States. This reduction was accomplished through a combination of
voluntary early retirement and special severance. The plan anticipated a net
reduction of approximately 600 positions, or 7% of the Company's United States
work force, from across all areas of Domestic Electric Operations. The actual
net work force reduction from this program was 759 positions, with 981 employees
accepting the offer and 222 vacated positions being backfilled. The Company
recorded a $70 million after-tax charge in 1998 relating to the early retirement
program. The actual cost of the early retirement program was approximately equal
to the amount accrued. These reductions were expected to result in annual pretax
savings to the Company of approximately $50 million. The savings in 1998 totaled
approximately $18 million.
In the fourth quarter of 1998, the Company initiated a cost reduction program
that included involuntary employee severance and enhanced early retirement for
employees who met certain age and service criteria and were displaced in
conjunction with the cost reduction initiatives. Approximately 167 employees
were displaced, with 35 of them eligible for the enhanced early retirement, and
the Company recorded a $6 million after-tax charge. It is anticipated that these
amounts will be fully paid out in early 1999.
In 1997, the Company recorded a series of special charges at Domestic
Electric Operations. The Company concluded that the Glenrock Mine was
uneconomical to continue to operate under current and expected market conditions
due to increased mining stripping ratios, reduced coal quality and related
operating costs. Therefore, a $64 million charge was recorded in 1997 to write
down asset values by $23 million in property, plant and equipment, $5 million in
other assets and to record a liability of $36 million in other deferred credits
for acceleration of reclamation cost accruals due to early closure of the mine.
The carrying amount of the net assets at December 31, 1998 is $9 million. The
reclamation costs were based on an external study and the write downs of
property, plant and equipment and other assets were based on weighing the
ongoing costs of operating the mine against purchasing coal from third party
resources. It is anticipated that reclamation of the mine site will commence in
1999 and is estimated to be completed in 2006.
The Company also determined that recovery of its regulatory assets applicable
to deferred pension costs included on the balance sheet in regulatory assets,
which related primarily to a deferred compensation plan and early retirement
incentive programs in 1987 and 1990, was not probable. As a result, the Company
recorded an $87 million charge in 1997 for these deferred regulatory assets.
27
<PAGE>
In addition, the Company recorded a $19 million charge in 1997 for the
impairment of certain information system assets ("IT systems") that were
included in its property, plant and equipment balances. These IT systems were
retired as a direct result of the Company's installation of SAP enterprise-wide
software.
1997 COMPARED TO 1996 Purchased power more than doubled in 1997 due to the
growth in the Company's wholesale trading market. Short-term firm and spot
market purchases were nearly three times the level of 1996 purchases, adding
$570 million to purchased power expense. Short-term firm and spot market
purchase prices averaged $19 per MWh in 1997 compared to $13 per MWh in 1996, a
46% increase, adding $76 million to purchased power expense. In addition,
special charges increased $170 million due to the Glenrock mine closure costs of
$64 million, the write off of deferred regulatory pension costs of $87 million,
and impairment charges on IT systems of $19 million.
OTHER INCOME AND EXPENSE
Other expenses increased $20 million in 1998, which included $13 million of
ScottishPower merger costs and $6 million of higher minority interest expense
relating to the issuance of quarterly income preferred securities in August
1997. Income tax expense decreased $9 million, to $103 million, due to the
decline in pretax income. See Note 14 of Notes to Consolidated Financial
Statements.
1997 COMPARED TO 1996 Interest expense increased $27 million, or 9%, to $319
million in 1997. This increase was attributable to higher average debt balances
as a result of the Hermiston Plant acquisition in July 1996 and capital
contributions to Holdings relating to the acquisition of TPC in April 1997.
Other income increased $7 million in 1997 primarily as a result of increased
sales of emission allowances.
INDUSTRY CHANGE, COMPETITION AND DEREGULATION
INDUSTRY CHANGE The electric power industry continues to experience change.
The key driver for this change is public, regulatory and governmental support
for replacing the traditional cost-of-service regulatory framework with an open
market competitive framework where the customers have a choice of energy
supplier. The pace at which this change will occur has slowed as regulators and
legislators struggle with conversion and implementation issues. However, federal
laws and regulations have been amended to provide for open access to
transmission systems, and various states have adopted or are considering new
regulations to allow open access for all energy suppliers.
COMPETITION The Company faces competition from many areas, including other
suppliers of electricity and alternative energy sources. In many cases,
customers have the option to switch energy sources for heating and air
conditioning. In addition, certain of the Company's industrial customers are
seeking choice of suppliers, options to build their own generation or
cogeneration, or the use of alternative energy sources such as natural gas. When
a competitive marketplace exists, customers will make their energy purchasing
decision based upon many factors, including price, service and system
reliability.
To meet these competitive challenges, Domestic Electric Operations is
participating in restructuring processes that will determine the shape of future
markets and is pursuing strategies that capitalize on its competitive position,
including the development and delivery of innovative products and services. In
addition, the Company continues to negotiate long-term and short-term contracts
with its existing large volume industrial customers. Although these new
agreements have generally resulted in reduced margins, the Company has been
successful in retaining many of these customers and in extending contract lives.
DEREGULATION Domestic Electric Operations continues to develop its competitive
strategy as legislation, regulation and market opportunities evolve. The Company
supports increased customer choice if the transition to competitive markets
takes place under terms and conditions that are equitable to all involved. The
Company will support direct access and other restructuring initiatives only when
their terms are fair to all customers, the Company and its shareholders.
The move toward an open or competitive marketplace for electric power may
result in "stranded costs" relating to certain current investments, deferred
costs and contractual commitments incurred under regulation that may not be
recoverable in a competitive market. The calculation of stranded costs requires
certain complex and
28
<PAGE>
interrelated assumptions to be made, the most critical of which is the expected
market price of electricity. The Company and many industry analysts believe that
market forces will continue to drive retail energy prices down as excess
capacity of existing generation resources persists. This projected trend in
price decreases is consistent with other commodities and services that have gone
through deregulation. Contrary to historical price trends, certain other parties
believe prices will increase in the future resulting in a stranded benefit to
the Company. The key attributes that affect market price include excess
generation capacity, the marginal cost of the high-cost provider that is
required to meet market demand, the cost of adding new capacity and the price of
natural gas.
Based upon a 1997 study, the Company estimated its total stranded costs to
range from $1.4 billion to $2.8 billion. This estimate represents the net
present value of the difference between the revenues expected under competition
and the embedded cost of generating the electricity and providing the service
and does not necessarily measure any write off or impairment that would be
required.
Regulated utilities have historically applied the accounting provisions of
Statement of Financial Accounting Standards ("SFAS") 71 which is based on the
premise that regulators will set rates that allow for the recovery of a
utility's costs, including cost of capital. Accounting under SFAS 71 is
appropriate as long as: rates are established by or subject to approval by
independent, third-party regulators; rates are designed to recover the specific
enterprise's cost-of-service; and in view of demand for service, it is
reasonable to assume that rates are set at levels that will recover costs and
can be collected from customers. In applying SFAS 71, the Company must give
consideration to changes in the level of demand or competition during the cost
recovery period. In accordance with SFAS 71, Domestic Electric Operations
capitalizes certain costs, called regulatory assets, in accordance with
regulatory authority whereby those costs will be expensed and recovered in
future periods.
The Emerging Issues Task Force of the Financial Accounting Standards Board
(the "EITF") concluded in 1997 that SFAS 71 should be discontinued when detailed
legislation or a regulatory order regarding competition is issued. Additionally,
the EITF concluded that regulatory assets and liabilities applicable to
businesses being deregulated should be written off unless their recovery is
provided for through future regulated cash flows.
Legislative actions in California and Montana during 1996 and 1997 mandated
customer choice of electricity supplier, moving away from cost-based regulation
to competitive market rates for the generation portion of the electric business.
As a result of these legislative actions, the Company evaluated its generation
regulatory assets and liabilities in California and Montana based upon future
regulated cash flows and ceased the application of SFAS 71 to its generation
business allocable to California and Montana. Domestic Electric Operations
recorded an extraordinary loss of $16 million, or $0.05 per share, in 1997 for
the write off of regulatory assets in these states. The regulatory assets
written off resulted primarily from deferred taxes allocated to California and
Montana. The allocation among states was based on plant balances.
In 1998, the Company announced its intent to seek buyers for its California
and Montana electric distribution assets. This action was in response to the
continued decline in earnings on the assets and the changes in the legislative
and regulatory environments in these states. The Company issued requests for
proposals to interested parties on July 20, 1998. On November 5, 1998, the
Company sold its Montana electric distribution assets to Flathead Electric
Cooperative, Inc. and received proceeds of $89 million, net of taxes and
customer refunds. The Company returned $4 million of the $8 million gain on the
sale to Montana customers as negotiated with the Montana Public Service
Commission (the "MPSC") and the Montana Consumer Counsel. The Company has
received bids for its California electric distribution assets. These bids remain
open and the Company is holding discussions with the bidders.
In addition, the Company is participating in a docket concerning the
transition plan the Company filed in compliance with direct access legislation
in Montana. The Company has asserted in that docket that it has significant
stranded costs relating to its Montana service territory. However, the Company
has stated its willingness to forego recovery of those stranded costs as a
result of the sale of the Montana service territory. Other parties in the
proceeding believe the Company has stranded benefits, rather than stranded
costs, and that those benefits should be returned to customers. The Company
believes that the concept of stranded benefits is not addressed by Montana
legislation and there is no obligation to return stranded benefits to customers
even if the MPSC finds that such benefits exist. The outcome of this proceeding
is uncertain.
In December 1997, the California Public Utilities Commission issued an order
with respect to the Company's filing concerning transition to direct access
requirements enacted in that state. The order mandated a 10% rate reduction
effective January 1, 1998, which resulted in a $3.5 million annual reduction in
revenues. The Company is considering filing a petition for modification of this
order.
The Oregon Public Utility Commission and the Company have agreed to an
Alternate Form of Regulation ("AFOR") for the Company's Oregon distribution
business. The AFOR allows for index-related price increases in
29
<PAGE>
1998, 1999 and 2000, with an annual cap of 2% of distribution revenues in any
one year and an overall cap of 5% over the three-year period. The annual revenue
increase in 1999 is approximately $6.2 million. The AFOR also includes
incentives to invest in renewable resources and penalties for failure to
maintain the service quality levels.
As part of the Company's strategy in refocusing its efforts on its core
business, the Company intends to seek recovery of all of its prudent costs,
including stranded costs in the event of deregulation. However, due to the
current lack of definitive legislation, the Company cannot predict whether it
will be successful. At December 31, 1998, the Company's remaining regulatory
assets for all states totaled $796 million, of which approximately $350 million
is applicable to generation. Because of the potential regulatory and/or
legislative actions in Utah, Oregon, Wyoming, Idaho and Washington, the Company
may have additional regulatory asset write offs and charges for impairment of
long-lived assets in future periods relating to the generation portion of its
business. Impairment would be measured in accordance with SFAS 121, which
requires the recognition of impairment on long-lived assets when book values
exceed expected future cash flows. Integral parts of future cash flow estimates
include estimated future prices to be received, the expected future cash cost of
operations, sales and load growth forecasts and the nature of any legislative or
regulatory cost recovery mechanisms.
The Company believes that the regulatory initiatives that are underway in
each of the states may eventually bring competition for the electricity
generation services. This change in the regulatory structure may significantly
affect the Company's future financial position, results of operations and cash
flows. The Company intends to seek regular price increases to the extent it
underearns its allowed rate of return. This intention, consistent with the
strategic direction implemented in 1998, provides a continued foundation for use
of SFAS 71 in its financial statements. However, the Company announced on
January 6, 1999 that it does not plan to file for general rate increases in the
states it serves for at least the next six months, pending approval of its
proposed merger with ScottishPower.
ENVIRONMENTAL ISSUES
All of the Company's coal burning plants burn low-sulfur coal. Major
construction expenditures have already been made at many of these plants to
reduce sulfur dioxide ("SO2") emissions, but additional expenditures are
expected to be required at the Centralia Plant in Washington in which the
Company has a 47.5% ownership interest. In late 1997, the Southwest Washington
Pollution Control Authority ("SWAPCA") ordered the Centralia Plant to meet new
SO2, nitrogen oxides ("NOx"), carbon monoxide and particulate matter emission
limits. The new emission limits will require the plant to install two scrubbers
and low NOx burners at a projected cost of $240 million.
In addition, the Company and the other joint owners of the Craig Generating
Station (the "Station") in Colorado are parties to a lawsuit brought by the
Sierra Club alleging violations of the Federal Clean Air Act at the Station,
which is operated by the Tri-State Generation and Transmission Association. The
Company has a 19.3% interest in Units 1 and 2 of the Station.
Actions under the Endangered Species Act with respect to certain salmon and
other endangered or threatened species could result in restrictions on the
federal hydropower system and affect regional power supplies and costs. These
actions could also result in further restrictions on timber harvesting and
adversely affect electricity sales to Domestic Electric Operations' customers in
the wood products industry.
The Company is currently in the process of relicensing 16 separate
hydroelectric projects under the Federal Power Act. These projects, some of
which are grouped together under a single license, represent approximately 1,000
MW, or 93%, of the Company's total hydroelectric nameplate capacity. In the new
licenses, the FERC is expected to impose conditions designed to address the
impact of the projects on fish and other environmental concerns. The Company is
unable to predict the impact of imposition of such conditions, but capital
expenditures and operating costs are expected to increase in future periods and
certain projects may not be economical to operate.
Several federal and state environmental cleanup Superfund sites have been
identified where the Company has been, or may be, designated as a potentially
responsible party. In such cases, the Company reviews the circumstances and,
where possible, negotiates with other potentially responsible parties to provide
funds for clean-up and, if necessary, monitoring activities.
All of the Company's mining operations are subject to reclamation and closure
requirements. The Company monitors these requirements and annually revises its
cost estimates to meet existing legal and regulatory requirements of the various
jurisdictions in which it operates. Compliance with these requirements could
result in higher expenditures for both capital improvements and operating costs.
Future costs associated with the resolution of these matters are not expected
to be material to the Company's consolidated financial statements.
30
<PAGE>
AUSTRALIAN ELECTRIC OPERATIONS
REVENUES
<TABLE>
<CAPTION>
change due operating
millions of dollars 1998 1997 to currency variance
- -------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C>
REVENUES
Powercor area $437.8 $538.6 $ (80.0) $ (20.8)
----------------------------------------------
Outside Powercor area
Victoria 79.1 98.7 (14.5) (5.1)
New South Wales 71.6 46.0 (13.1) 38.7
Australian Capital Territory 0.6 - - 0.6
Queensland 0.3 - - 0.3
---------------------------------------------
Total Outside Powercor area 151.6 144.7 (27.6) 34.5
Other revenue 25.1 32.9 (4.6) (3.2)
---------------------------------------------
$614.5 $716.2 $(112.2) $ 10.5
=============================================
</TABLE>
<TABLE>
<CAPTION>
millions of kWh 1998 1997 1996
- -----------------------------------------------------------------------------------------------------
<S> <C> <C> <C>
ENERGY SALES
Powercor area 7,233 7,410 7,519
Outside Powercor area
Victoria 2,396 2,262 791
New South Wales 2,241 1,372 -
Australian Capital Territory 12 - -
Queensland 6 - -
--------------------------------
11,888 11,044 8,310
================================
</TABLE>
In 1998, Australian Electric Operations contributed earnings of $13 million, or
$0.04 per share, compared to $54 million, or $0.18 per share, in 1997.
Powercor's expansion of market share in New South Wales ("NSW") drove the growth
in energy sales and revenues. However, lower market prices as a result of an
increasing level of deregulation, partially offset by lower purchased power
expense, caused margins on energy sold to decline. In addition, Australian
Electric Operations recorded a $17 million, or $0.06 per share, loss on the
write down of its investment in Hazelwood to estimated net realizable value less
selling costs. The Company anticipates completing this sale by the end of 1999.
CURRENCY RISKS Australian Electric Operations' results of operations and
financial position are translated from Australian dollars into United States
dollars for consolidation into the Company's financial statements. Changes in
the prevailing exchange rate may have a material effect on the Company's
consolidated financial statements. The average currency exchange rate for
converting Australian dollars to United States dollars was 0.63 in 1998 compared
to 0.74 in 1997, a 15% decrease for the year. The effect of the exchange rate
fluctuation lowered reported revenues by $112 million and expenses by $105
million in 1998. The currency exchange rate at February 26, 1999 was 0.62. The
following discussion excludes the effects of the lower currency exchange rate in
1998.
Australia reported 1998 revenues of $615 million, an $11 million, or 1%,
increase over the prior year. The increase was attributable to growth in energy
sales volumes of 844 million kWh, or 8%.
Energy volumes sold to contestable customers outside Powercor's franchise
area were up 1,021 million kWh in 1998 and added $39 million to revenues due to
customer gains in NSW, $7 million due to customer gains in Victoria and $1
million due to gains in Queensland and the Australian Capital Territory. Lower
prices for contestable sales reduced revenues by $12 million in 1998. Inside
Powercor's franchise area, revenues declined $13 million primarily due to price
decreases for contestable customers and $8 million due to a 177 million kWh
decrease in volumes.
Other revenues decreased $3 million in 1998, principally because 1997
revenues included $15 million of income associated with renegotiating certain
Tariff H industrial customer contracts. This decrease was partially offset by an
increase in revenue from construction projects for other distribution businesses
in Australia of $6 million and a reduction in energy contract losses of $7
million.
31
<PAGE>
1997 COMPARED TO 1996
<TABLE>
<CAPTION>
change due operating
millions of dollars 1997 1996 to currency variance
- -------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C>
Powercor area $538.6 $583.6 $ (28.6) $ (16.4)
Outside Powercor area
Victoria 98.7 45.0 (5.2) 58.9
New South Wales 46.0 - - 46.0
---------------------------------------------
Total Outside Powercor area 144.7 45.0 (5.2) 104.9
Other revenue 32.9 30.2 (1.7) 4.4
---------------------------------------------
$716.2 $658.8 $ (35.5) $ 92.9
=============================================
</TABLE>
Revenues increased $93 million, or 14%, in 1997 primarily due to a 33% increase
in energy sales volumes. Increased market share in the contestable market in
Victoria added $59 million in revenues and sales in the newly contestable market
in NSW added $46 million in revenues. Revenues within Powercor's Victorian
franchise area decreased $16 million due to lower average realized prices and
decreased sales volumes.
OPERATING EXPENSES
<TABLE>
<CAPTION>
change due operating
millions of dollars 1998 1997 to currency variance
- ------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C>
Purchased power $255.0 $308.5 $ (46.6) $ (6.9)
Other operations and maintenance 140.1 134.0 (25.6) 31.7
Depreciation and amortization 58.2 67.1 (10.6) 1.7
Administrative and general 46.7 56.1 (8.6) (0.8)
---------------------------------------------
$500.0 $565.7 $ (91.4) $ 25.7
=============================================
</TABLE>
Purchased power expense decreased $7 million, or 2%, in 1998. Lower average
prices reduced power costs by $35 million. Prices for purchased power averaged
$23 per MWh in 1998 compared to $26 per MWh in 1997. The reduction resulted from
competition. The decrease was offset in part by a 9% increase in purchased power
volumes that added $28 million to costs in 1998.
Other operations and maintenance expenses increased $32 million, or 24%, in
1998. Increased sales to contestable customers outside the Powercor service area
resulted in higher network fees of $40 million. This increase was offset in part
by higher network revenues of $12 million from customers inside Powercor's
franchise area serviced by other energy suppliers. Maintenance increased $4
million primarily due to $6 million in costs transferred to administrative and
general expenses upon conversion to SAP in November 1997.
Administrative and general expenses decreased $1 million in 1998 primarily
due to an $11 million reduction in professional fees and $6 million transferred
from maintenance upon conversion to SAP in 1997. These decreases were offset by
a $15 million adjustment in 1997 to capitalize new customer connection costs.
Interest expense increased $5 million in 1998 to $58 million as a result of
higher debt balances, partially offset by declining interest rates. In the
fourth quarter of 1998, the Company began soliciting bids and intends to sell
its equity interest in the Hazelwood Power Station in connection with its
refocus on its electricity business. Other expense increased $33 million
primarily due to a pretax loss of $28 million to reduce the carrying value of
the Company's investment in the Hazelwood Power Station to its estimated net
realizable value less selling costs and $5 million in costs for removal of
certain energy efficiency devices in connection with a product recall. Powercor
is in the process of seeking recovery from the manufacturer of these devices.
Equity losses in Hazelwood were $6 million, an increase of $4 million over 1997
primarily due to increased maintenance costs. Income tax expense decreased $23
million due to a reduction in taxable income.
32
<PAGE>
1997 COMPARED TO 1996
<TABLE>
<CAPTION>
change due operating
millions of dollars 1997 1996 to currency variance
- ------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C>
Purchased power $308.5 $305.1 $ (16.4) $ 19.8
Other operations and maintenance 134.0 112.3 (7.1) 28.8
Depreciation and amortization 67.1 71.6 (3.6) (0.9)
Administrative and general 56.1 42.4 (3.0) 16.7
---------------------------------------------
$565.7 $531.4 $ (30.1) $ 64.4
=============================================
</TABLE>
Operating expenses increased $64 million, or 12%, in 1997. Increased sales to
contestable customers outside Powercor's franchise area resulted in increased
purchased power expense of $20 million and higher network and grid fees of $58
million, which was partially offset by higher network revenues of $16 million
from customers inside Powercor's franchise area that were serviced by other
energy suppliers.
CUSTOMERS AND COMPETITION
Powercor's principal businesses are to sell electricity to franchise and
contestable customers inside and outside its franchise area and to provide
electricity distribution services to customers within its regulated network
distribution service area. Franchise customers are those customers that cannot
yet choose an electricity supplier, while contestable customers have the
opportunity to choose suppliers. Powercor purchases all of its electricity
supply from a state generation pool.
Victoria and NSW are currently divided between franchise and contestable
customers. Customers in both states with annual consumption of more than 160 MWh
are now contestable and the remaining customers will become contestable over the
next few years depending on their energy demand load, with substantially all
residential customers remaining franchise customers until 2001. If a Powercor
customer chooses a different retailer, Powercor will continue to receive network
distribution revenues associated with that customer. Powercor was granted
licenses to sell electricity to customers in the States of Queensland and
Australian Capital Territory in early 1998.
REGULATION
Powercor is the largest of the five distribution businesses ("DBs") formed when
the Victorian State Government decided to privatize, and eventually deregulate,
its electricity industry. As the Victorian market becomes more open to
competition and additional customers can choose their energy supplier, Powercor
and the other DBs will continue to maintain a monopoly on their individual
network areas. These businesses derive much of their revenue from the network
fee that is paid for the use of the distribution system.
Powercor has an exclusive license to sell electricity to customers in its
distribution service area in Victoria with a demand of 160 MWh per year or less.
Powercor has nonexclusive licenses to sell electricity to customers with usage
in excess of 160 MWh per year in its distribution service area and elsewhere in
Victoria and NSW, and to customers in Queensland with annual usage exceeding
four million kWh. Customers with usage of 160 MWh per year or less will
incrementally become contestable over the period ending December 31, 2000 in
Victoria and Queensland and over the period ending June 30, 1999 in NSW
depending on their energy usage.
Hazelwood operates in an area where several large, coal-fired generating
facilities are located. It will continue to compete against these plants, as
well as others outside the geographic area.
Regulation of the Victorian electricity industry is the responsibility of the
Office of the Regulator General (the "ORG"), an independent regulatory body. The
structure of prices within the Victorian electricity industry reflects the
establishment of maximum uniform tariffs that apply to noncontestable customers
and some contestable customers. Under applicable regulations, Powercor is
required to supply electricity to noncontestable customers at prices that are no
greater than the prices specified under the applicable tariffs. The prices
specified in the tariffs are all inclusive, including grid charges and energy
costs. In general, annual movements in the tariffs for noncontestable customers
are based on the Consumer Price Index, a measure of price inflation.
Network tariffs include recovery of distribution use-of-system costs,
use-of-transmission-system fees and connection charges. Network tariffs are
intended to cover the cost of providing, operating and maintaining the
distribution network, except to the extent relevant costs are recoverable
through connection charges or other excluded services, and the charges levied
for connection to and use of the transmission systems.
33
<PAGE>
The first major review of the regulatory arrangements and respective
transmission and distribution network charges will be carried out by the ORG,
with any changes to apply from January 1, 2001. Any subsequent price control
arrangements are required to be in effect for not less than five years. The
outcome of the year 2000 regulatory review is uncertain at this time.
OTHER OPERATIONS
<TABLE>
<CAPTION>
millions of dollars 1998 1997 1996
- ------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C>
EARNINGS CONTRIBUTION
PFS $ 8.1 $ 30.2 $ 34.1
PGC - 10.4 7.8
Holdings and other:
Write down of other energy businesses (32.4) - -
TEG costs and option losses (45.6) (64.5) -
Gain on sale of PGC - 30.0 -
Other 17.7 (15.7) (14.8)
--------------------------------
$(52.2) $ (9.6) $ 27.1
================================
</TABLE>
During 1998, Other Operations included the activities of Holdings, PacifiCorp
Financial Services, Inc. ("PFS"), and energy development businesses. Losses
relating to the decision to shut down or sell its other energy development
businesses totaled $32 million, or $0.11 per share in 1998. The 1998 results
also included $54 million, or $0.18 per share, in costs associated with the
Company's terminated bid for TEG, $2 million, or $0.01 per share, relating to
closing foreign currency options in April 1998 associated with the terminated
bid for TEG, and a gain of $10 million, or $0.03 per share, relating to the sale
of the TEG shares. The 1997 results included a loss of $65 million, or $0.22 per
share, associated with closing foreign currency options and initial option
premium costs relating to the Company's initial offer for TEG, that subsequently
terminated when it was referred to the Monopolies and Mergers Commission (the
"MMC") in the United Kingdom.
Results from Other Operations in 1998 benefited from a $40 million after-tax
increase in interest income and reduced interest expense as the result of cash
received from 1997 asset sales.
PFS has tax-advantaged investments in leasing operations that consist
principally of aircraft leases. For 1998, PFS reported net income of $8 million,
a $22 million decrease from 1997. This decrease was primarily attributable to
the sale of its affordable housing properties. In May 1998, PFS sold a majority
of its investments in affordable housing for $80 million, which approximated
book value.
The energy development businesses that the Company decided to exit in 1998
are generally wholly owned subsidiaries of the Company or subsidiaries in which
the Company has a majority ownership. These businesses are consolidated in the
Company's financial statements and are included in Other Operations. The pretax
loss associated with exiting the energy development businesses was $52 million
in 1998 and was included in "Write down of investments in energy development
businesses" on the income statement. This loss consisted of reductions in net
intercompany receivables. The remaining values for these businesses were arrived
at using cash flow projections and estimated market value for fixed assets. Some
of these businesses have been exited through the discontinuance of their
operations while others are for sale. The Company believes that the businesses
currently for sale can be exited by the end of 1999. Costs relating to exiting
these businesses will be expensed as incurred.
In addition, the other energy development businesses incurred $19 million of
after-tax losses, or $0.06 per share, in 1998 compared to a loss of $16 million,
or $0.05 per share, in 1997.
On November 5, 1997, the Company completed the sale of its independent power
subsidiary, PGC, to NRG Energy, Inc. for approximately $150 million in cash,
resulting in a gain of $30 million, or $0.10 per share.
PGC contributed income of $10 million in 1997 prior to completing the sale.
1997 COMPARED TO 1996 The $37 million decrease in earnings contribution of
Other Operations in 1997 was primarily attributable to an after-tax loss of $65
million, or $0.22 per share, associated with closing foreign exchange positions
relating to the Company's terminated bid for TEG. This loss was partially offset
by an after-tax gain of $30 million, or $0.10 per share, relating to the sale of
PGC in November 1997.
34
<PAGE>
DISCONTINUED OPERATIONS
Discontinued operations reported losses in 1998 of $147 million, or $0.49 per
share, compared to income of $447 million, or $1.50 per share, in 1997. The 1998
results included $105 million, or $0.35 per share, for the loss anticipated to
exit the energy trading business and a loss of $42 million, or $0.14 per share,
relating to operating losses prior to the decision to exit.
The pretax loss associated with exiting the energy trading business was $155
million. This loss consisted of write downs of intangible assets of $83 million
and the costs to exit a portion of the business and sell another portion of the
business of $72 million. The exiting costs include anticipated severance
payments and operating costs to the selling date and selling expenses. The
remaining values for these businesses that are on the books of the Company
represent the estimated market value of the fixed assets of the companies and
the remaining working capital at the expected sale date. Activities in the
eastern United States have been discontinued and all forward electricity trading
has been closed and is going through settlement. Contracts to manage the power
supply of two municipalities will continue, the longest of such contracts will
expire in late 1999. Holdings entered into an agreement, dated February 9, 1999,
to sell TPC for approximately $133 million. In addition, a working capital
adjustment will be calculated and paid following closing of the transaction,
which is expected during the first half of 1999.
The 1997 results included the gain on the sale of the Company's
telecommunications operations and the earnings from normal operations until the
sale in December 1997. On December 1, 1997, the Company completed the sale of
PTI for $1.5 billion in cash, plus the assumption of PTI's debt. The Company
realized an after-tax gain of $365 million, or $1.23 per share. For the eleven
months ended November 30, 1997, PTI reported net income of $89 million, or
$0.30 per share, compared to $75 million, or $0.25 per share, for all of 1996.
LIQUIDITY AND CAPITAL RESOURCES
<TABLE>
<CAPTION>
CASH FLOW SUMMARY
forecasted actual
-------------------------------------------------------------------------
for the year || millions of dollars 2001 2000 1999 1998 1997 1996
- ----------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C>
NET CASH FLOW FROM CONTINUING OPERATIONS
Domestic Electric Operations $ 692 $ 727 $ 718
Australian Electric Operations 114 101 95
Other Operations (121) 8 75
----------------------------------
Total 685 836 888
Cash Dividends Paid 337 341 346
----------------------------------
Net $ 475-525 $475-525 $ 425-475 $ 348 $ 495 $ 542
=========================================================================
CONSTRUCTION
Domestic Electric Operations $ 462 $ 414 $ 479 $ 539 $ 490 $ 442
Australian Electric Operations 60 65 60 70 79 80
Other Operations - - - 1 9 7
-------------------------------------------------------------------------
Total 522 479 539 610 578 529
ACQUISITIONS AND INVESTMENTS
Domestic Electric Operations - - - - - 154
Australian Electric Operations - - - 5 5 145
Other Operations - - - 52 131 49
----------------------------------------------------------------------
Total - - - 57 136 348
----------------------------------------------------------------------
Total Capital Spending $ 522 $ 479 $ 539 $ 667 $ 714 $ 877
======================================================================
MATURITIES OF LONG-TERM DEBT
Domestic Electric Operations $ 138 $ 170 $ 300 $ 196 $ 208 $ 182
Australian Electric Operations - - - 1,339 3 42
Other Operations - - - 169 10 19
----------------------------------------------------------------------
Total $ 138 $ 170 $ 300 $ 1,704 $ 221 $ 243
======================================================================
Other Refinancings $ 28 $ 558 $ 42
===============================
</TABLE>
35
<PAGE>
OPERATING ACTIVITIES Cash flows from continuing operations decreased $151
million from 1997 to 1998. This decrease was due to cash expenditures in 1998
relating to taxes on 1998 and 1997 asset sales and cash funding of other energy
development businesses.
INVESTING ACTIVITIES While investing activities in 1997 were dominated by
asset sales of $1.8 billion and the acquisition of TPC, investing in 1998
focused on continued capital spending to improve and expand existing operations
and disposing of non-strategic assets such as the Montana electric distribution
assets and the majority of the tax-advantaged investments in affordable housing
owned by PFS.
On October 23, 1998, the Company announced its intent to exit its energy
trading business in the eastern United States and its other energy development
businesses. As a result, the Company recorded an after-tax loss of $137 million
for these businesses. In addition, the Company recorded an after-tax loss of $17
million to reduce the Company's carrying value in the Hazelwood Power Station to
its net realizable value less selling costs.
The utility partners who own the 1,340 MW coal-fired Centralia Power Plant in
Washington have hired an investment advisor to pursue the possible sale of the
plant and the adjacent Centralia coal mine. The sale of the plant and adjacent
mine is being considered by the owners, in part, because of emerging
deregulation, competition in the electricity industry and the need for
environmental compliance expenditures at the plant. The Company operates the
plant and owns a 47.5% share. In addition, the Company owns and operates the
adjacent Centralia coal mine. The Company is investigating the effect of a
potential sale on the reclamation costs for the Centralia coal mine. Preliminary
studies indicate that reclamation costs for the Centralia coal mine could be
significantly higher than previous estimates, assuming the mine is closed, with
the Company's portion being 47.5% of the final total amount. At December 31,
1998, the Company had approximately $24 million accrued for its share of the
Centralia mine reclamation costs. The final amount and timing of any charge for
additional reclamation at the mine are dependent upon a number of factors,
including the results of the sale process, completion of the preliminary
reclamation studies at the mine and the reclamation procedure used. The Company
will seek to recover through rates any increase in the reclamation costs for the
mine.
On July 9, 1998, the Company announced its intent to sell its California and
Montana electric distribution assets. This action was in response to the
continued decline in earnings on the assets and changes in the legislative and
regulatory environments in these states. The Company issued requests for
proposals to interested parties on July 20, 1998. The Company has received bids
for the California assets. These bids remain open and the Company has taken no
action related to the bids.
On November 5, 1998, the Company sold its Montana distribution assets to
Flathead Electric Cooperative, Inc. and received proceeds of $89 million, net of
taxes and customer refunds. The Company returned $4 million of the $8 million
gain to Montana customers as negotiated with the MPSC and the Montana Consumer
Counsel.
In May 1998, PFS sold a majority of its investments in affordable housing for
$80 million, which approximated book value.
During 1997, the Company generated $1.8 billion of cash from the sale of PTI
and PGC. A portion of the proceeds from the sale was used to repay short-term
debt of Holdings. The remaining proceeds were invested in short-term money
market instruments and Holdings temporarily advanced excess funds to PacifiCorp
for retirement of short-term debt.
In October 1998 Holdings paid a dividend of $500 million to PacifiCorp.
PacifiCorp used the proceeds to pay down intercompany debt owed to Holdings. In
January 1999, Holdings paid a dividend of $660 million to PacifiCorp. PacifiCorp
used the proceeds to pay down short-term debt and intercompany debt and invested
the remainder in money market funds.
The Company believes that its existing and available capital resources are
sufficient to meet working capital, dividend and construction needs in 1999.
BID FOR THE ENERGY GROUP
During 1997 and 1998, the Company sought to acquire TEG, a diversified
international energy group with operations in the United Kingdom, the United
States and Australia. The Company made three tender offers for TEG, with the
last offer valued at $11.1 billion, including the assumption of $4.1 billion of
TEG's debt. In March 1998, another United States utility made a tender offer at
a price higher than the Company's offer and, on April 30, 1998, the Company
announced that it would not increase its revised offer for TEG.
36
<PAGE>
The Company recorded an $86 million pretax charge to first quarter 1998
earnings, included in "TEG costs and option losses," for bank commitment and
facility fees, legal expenses and other related costs incurred since the
Company's original bid for TEG in June 1997. These costs had been deferred
pending the outcome of the transaction.
Upon initiation of the original tender offer in June 1997, the Company also
entered into foreign currency exchange contracts. The financing facilities
associated with the June 1997 offer for TEG terminated upon referral of the
transaction to the MMC, and the Company initiated steps to unwind its foreign
currency exchange positions consistent with its policies on derivatives. As a
result of the termination of these positions and initial option costs, the
Company realized an after-tax loss of approximately $65 million, or $0.22 per
share, in the third quarter of 1997.
Additionally, in connection with the attempt to acquire TEG, a subsidiary of
the Company purchased approximately 46 million shares of TEG stock at a price of
820 pence per share, or $625 million. The Company recorded a $10 million gain on
the sale of the TEG shares in June 1998. In addition, the Company incurred a
pretax expense of $3 million in April 1998 in connection with closing its
foreign currency option contract associated with the bid for TEG.
CAPITALIZATION
<TABLE>
<CAPTION>
millions of dollars, except percentages 1998 1997
- ---------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C>
Long-term debt $4,383 45% $ 4,237 43%
Common equity 3,957 41 4,321 44
Short-term debt 560 6 555 5
Preferred stock 241 2 241 2
Preferred securities of Trusts 341 4 340 4
Quarterly income debt securities 176 2 176 2
--------------------------------------------------
Total Capitalization $9,658 100% $ 9,870 100%
==================================================
</TABLE>
The Company manages its capitalization and liquidity position in a consolidated
manner through policies established by senior management and approved by the
Finance Committee of the Board of Directors. These policies have resulted from a
review of historical and projected practices for businesses and industries that
have financial and operating characteristics similar to the Company and its
principal business operations.
The Company's policies attempt to balance the interests of its shareholders,
ratepayers and creditors. In addition, given the changes that are occurring
within the industry and market segments in which the Company operates, these
policies are intended to remain sufficiently flexible to allow the Company to
respond to these developments.
On a consolidated basis, the Company attempts to maintain total debt at 48%
to 54% of capitalization. The debt to capitalization ratio was 51% at December
31, 1998. The Company also attempts to maintain a preferred stock ratio,
including subordinated debt, at 8% to 12% of capitalization. The preferred stock
ratio was 8% at December 31, 1998.
The Company's announced plan to repurchase up to $750 million in common
shares has been postponed pending the outcome of the proposed ScottishPower
merger.
EQUITY AND DEBT TRANSACTIONS
In January 1998, PacifiCorp Australia LLC ("PALLC") issued $400 million of 6.15%
Notes due 2008. At the same time, in order to mitigate foreign currency exchange
risk, PALLC entered into a series of currency exchange agreements in the same
amount and for the same duration as the underlying United States denominated
notes. The proceeds of the Notes were used to repay Australian bank bill
borrowings.
On May 12, 1998, the Company issued $200 million of 6.375% secured
medium-term notes due May 15, 2008 in the form of First Mortgage Bonds. Proceeds
were used to repay short-term debt.
On November 6, 1998, the Company issued $200 million of its 5.65% Series of
First Mortgage Bonds due November 1, 2006. Proceeds were used to repay
short-term debt.
37
<PAGE>
VARIABLE RATE LIABILITIES
millions of dollars 1998 1997
- -------------------------------------------------------------------------------
Domestic Electric Operations $ 830 $ 760
Australian Electric Operations 278 269
Holdings and other 12 26
------------------------
$ 1,120 $ 1,055
========================
Percentage of Total Capitalization 12% 11%
The Company's capitalization policy targets consolidated variable rate
liabilities at between 10% and 25% of total capitalization.
AVAILABLE CREDIT FACILITIES
At December 31, 1998, PacifiCorp had $700 million of committed bank revolving
credit agreements. Regulatory authorities limited PacifiCorp to $1 billion of
short-term debt, of which $370 million was outstanding at December 31, 1998. At
December 31, 1998, subsidiaries of PacifiCorp had $826 million of committed bank
revolving credit agreements. The Company had $532 million of short-term debt
classified as long-term debt at December 31, 1998, as it had the intent and
ability to support such short-term borrowings through the various revolving
credit facilities on a long-term basis. See Notes 7 and 8 of Notes to
Consolidated Financial Statements for additional information.
LIMITATIONS
In addition to the Company's capital structure policies, its debt capacity is
also governed by its credit agreements. PacifiCorp's principal debt limitation
is a 60% debt to capitalization test contained in its principal credit
agreements. Based on the Company's most restrictive credit agreements,
management believes PacifiCorp and its subsidiaries could have borrowed an
additional $2.5 billion of debt at December 31, 1998.
Under PacifiCorp's principal credit agreement, it is an event of default if
any person or group acquires 35% or more of PacifiCorp's common shares or if,
during any period of 14 consecutive months, individuals who were directors of
PacifiCorp on the first day of such period (and any new directors whose election
or nomination was approved by such individuals and directors) cease to
constitute a majority of the Board of Directors. PacifiCorp has obtained a
waiver of this provision in $200 million of its credit facilities and expects to
contact the remaining parties of the principal credit facilities requesting a
waiver of this provision in anticipation of the ScottishPower merger.
RISK MANAGEMENT
Risk is an inherent part of the Company's business and activities. The risk
management process established by the Company is designed to identify, assess,
monitor and manage each of the various types of risk involved in its business
and activities. Central to its risk management process, the Company has
established a senior risk management committee with overall responsibility for
establishing and reviewing the Company's policies and procedures for controlling
and managing its risks. The senior risk management committee relies on the
Company's treasury department and its operating units to carry out its risk
management directives and execute various hedging and energy trading strategies.
The policies and procedures that guide the Company's risk management activities
are contained in the Company's derivative policy.
The risk management process established by the Company is designed to measure
quantitative market risk exposure and identify qualitative market risk exposure
in its businesses. To assist in managing the volatility relating to these
exposures, the Company enters into various derivative transactions consistent
with the Company's derivative policy. That policy, which was originally
established in 1994, governs the Company's use of derivative instruments and its
energy trading practices and contains the Company's credit policy and management
information systems required to effectively monitor such derivative use. The
Company's derivative policy provides for the use of only those instruments that
have a close correlation with its portfolio of assets, liabilities or
anticipated transactions. The derivative policy includes as its objective that
interest rates and foreign exchange derivative
38
<PAGE>
instruments will be used for hedging and not for speculation. The derivative
policy also governs the energy trading activities and is generally designed for
hedging the Company's existing energy exposures but does provide for limited
speculation activities within defined risk limits.
RISK MEASUREMENT
VALUE AT RISK ANALYSIS The tests discussed below for exposure to interest rate
and currency exchange rate fluctuations are based on a Value at Risk ("VAR")
approach using a one-year horizon and a 95% confidence level and assuming a
one-day holding period in normal market conditions. With the Company's energy
trading activities, a 99.9% confidence level is used. The higher confidence
level results from a more active management of the risk. The VAR model is a risk
analysis tool that attempts to measure the potential losses in fair value,
earnings or cash flow from changes in market conditions and does not purport to
represent actual losses in fair value that may be incurred by the Company. The
VAR model also calculates the potential gain in fair market value or improvement
in earnings and cash flow associated with favorable market price movements.
SENSITIVITY ANALYSIS The Company measures its market risk related to its
commodities price exposure positions by utilizing a sensitivity analysis. This
sensitivity analysis measures the potential loss or gain in fair value, earnings
or cash flow based on a hypothetical immediate 10% change (increase or decrease)
in prices for its commodity derivatives. The fair value of such positions are a
summation of the fair values calculated for each commodity derivative by valuing
each position at quoted futures prices or assumed forward prices.
EXPOSURE ANALYSIS
INTEREST RATE EXPOSURE The Company's market risk to interest rate changes is
primarily related to long-term debt with fixed interest rates. The Company uses
interest rate swaps, forwards, futures and collars to adjust the characteristics
of its liability portfolio. This strategy is consistent with the Company's
capital structure policy which provides guidance on overall debt to equity and
variable rate debt as a percent of capitalization levels for both the
consolidated organization and its principal subsidiaries.
The table below shows the potential loss in fair market value of the
Company's interest rate sensitive positions as of December 31, 1997 and December
31, 1998, as well as the Company's quarterly high and low potential losses.
<TABLE>
<CAPTION>
1998 1998
confidence time quarterly quarterly
millions of dollars interval horizon 12/31/97 high low 12/31/98
- ----------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C>
Interest Rate Sensitive
Portfolio - FMV 95% 1 day $(21.1) $(22.4) $(18.4) $(18.4)
</TABLE>
Because of the size of the Company's fixed rate portfolio and lower levels of
short-term debt as a result of asset sales, the significant majority of this
average daily exposure is a noncash fair market value exposure and generally not
a cash or current interest expense exposure.
CURRENCY RATE EXPOSURE The Company's market risk to currency rate changes is
primarily related to its investment in the Australian Electric Operations. The
Company uses currency swaps, currency forwards and futures to hedge its foreign
activities and, where use is governed by the derivative policy, the Company
utilizes Australian dollar denominated borrowings to hedge the majority of the
foreign exchange risks associated with Australian Electric Operations. Results
of hedging activities relating to foreign net asset exposure are reflected in
the accumulated other comprehensive income section of shareholders' equity,
offsetting a portion of the translation of the net assets of Australian Electric
Operations.
Gains and losses relating to qualifying hedges of foreign currency firm
commitments (or anticipated transactions) are deferred on the balance sheet and
are included in the basis of the underlying transactions. To the extent that a
qualifying hedge is terminated or ceases to be effective as a hedge, any
deferred gains and losses up to that point continue to be deferred and are
included in the basis of the underlying transaction. To the extent that
anticipated transactions are no longer likely to occur, the related hedges are
closed with gains or losses charged to earnings on a current basis.
39
<PAGE>
In addition to the foreign currency exposure related to its investment in
Australian Electric Operations, the Company also includes in the currency rate
exposure VAR analysis the mark-to-market risk associated with its energy supply
related contracts for differences supporting its commitment to the customers of
Australian Electric Operations.
The table below shows the potential loss in pre-tax cash flow of the
Company's currency rate sensitive positions as of December 31, 1997 and December
31, 1998, as well as the Company's quarterly high and low potential losses.
<TABLE>
<CAPTION>
1998 1998
confidence time quarterly quarterly
millions of dollars interval horizon 12/31/97 high low 12/31/98
- ----------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C>
Currency Rate Exposure - Cash Flow 95% 1 day $(2.3) $(2.1) $(0.9) $(0.9)
</TABLE>
The December 1997 amounts have been restated to include Australian Electric
Operations contracts for differences.
COMMODITY PRICE EXPOSURE The Company's market risk to commodity price change
is primarily related to its electricity and natural gas commodities which are
subject to fluctuations due to unpredictable factors, such as weather, which
impacts supply and demand. The Company's energy trading activities are governed
by the derivative policy and the risk levels established as part of that policy.
The Company's energy commodity price exposure arises principally from its
electric supply obligation in the United States and Australia. In the United
States, the Company manages this risk principally through the operation of its
8,445 MW generation and transmission system in the western Unites States and
through its wholesale energy trading activities. Derivative instruments are not
significantly utilized in the management of the Unites States electricity
position. In Australia, the Victorian government currently limits the amount of
generation that can be owned by an electric supply company and, as a result, the
risk associated with Australian Electric Operations energy supply obligations is
managed through the use of electricity forward contracts (referred to as
"contracts for differences") with Victorian generators. Under these forward
contracts, the Company receives or makes payment based on a differential between
a contracted price and the actual spot market of electricity. Additionally,
electricity futures contracts are utilized to hedge Domestic Electric
Operations' excess or shortage of net electricity for future months. The changes
in market value of such contracts have had a high correlation to the price
changes of the hedged commodity. Derivative instruments, other than contracts
for differences, are not significantly utilized in Australian Electric
Operations' risk management process.
Gains and losses relating to qualifying hedges of firm commitments or
anticipated inventory transactions are deferred on the balance sheet and
included in the basis of the underlying transactions.
A sensitivity analysis has been prepared to estimate the Company's exposure
to market risk related to commodity price exposure of its derivative positions
for both natural gas and electricity. Based on the Company's derivative price
exposure at December 31, 1998 and 1997, a near-term adverse change in commodity
prices of 10% would negatively impact pre-tax earnings by $16 million and $12
million, respectively.
INFLATION
Due to the capital-intensive nature of the Company's core businesses, inflation
may have a significant impact on replacement of property, acquisition and
development activities and final mine reclamation costs. To date, management
does not believe that inflation has had a significant impact on any of the
Company's other businesses.
YEAR 2000
The Company's Year 2000 project has been underway since mid-1996. A standard
methodology of inventory, assessment, remediation and testing of hardware,
software and equipment has been implemented. The main areas of risk are in:
power supply (generating plant and system controls); information technology
(computer software and hardware); business disruption; and supply chain
disruption. The first two areas of risk are within the Company's own business
operations. The others are areas of risk the Company might face from interaction
with other companies, such as critical suppliers and customers. The Company's
plan is to have successfully identified, corrected and tested its existing
critical systems by July 1, 1999. The Company requires that all new hardware or
software be vendor certified Year 2000 ready before it is installed.
40
<PAGE>
A summary of the Company's progress to date in areas affected by Year 2000
issues is set forth in the following table:
<TABLE>
<CAPTION>
remediation
percent completed inventory assessment and testing
- -----------------------------------------------------------------------------------------------
<S> <C> <C> <C>
Electric Systems 100% 89% 49%
COMPUTER SYSTEMS
Central Applications To Correct 100 100 100
Central Applications To Replace 100 100 75
Desktop 100 100 30
</TABLE>
The Company's ability to maintain normal operations into the year 2000 will also
be affected by Year 2000 readiness of third parties from whom the Company
purchases products and services or with whom the Company exchanges information.
As of January 25, 1999, the Company believes it had identified 100% of its
critical third-party supplier relationships and requested that these parties
report their Year 2000 readiness. At March 10, 1999, the critical third parties
reported they would be Year 2000 ready on or before the dates in the table
below:
<TABLE>
<CAPTION>
readiness target dates, on or before percent of all critical third parties ready
- ----------------------------------------------------------------------------------------------------
<S> <C>
December 31, 1998 22%
March 31, 1999 33
June 30, 1999 77
September 30, 1999 91
December 31, 1999 97
(no Readiness Target Date reported) 3
</TABLE>
The Company is in contact with these third parties and their Year 2000 readiness
information is updated as required.
The Company is also in the process of identifying third parties that are
"super critical." An elevated Year 2000 readiness assessment, which includes a
site visit, will be performed for each of them. To date, one super critical
vendor has been identified. That vendor supplies chemical reagents used in air
emission control equipment at some generating plants. One week's supply can be
maintained. The plants would be able to generate power, but after a week may not
be able to meet air quality regulations. That vendor has advised the Company
that it will be Year 2000 ready by September 30, 1999. An on-site assessment has
been scheduled. The Company plans to identify all remaining "super critical"
third parties by mid-April 1999.
The Company has no single retail customer that accounts for more than 1.7% of
its retail utility revenues and the 20 largest retail customers account for
13.9% of total retail electric revenues. The Company has not performed a formal
assessment of its customers' Year 2000 readiness.
The Company's mining operations contingency plan calls for increased
stockpiles of fuel to be available to supply the generating plants.
The Company, the North American Electric Reliability Council ("NERC") and the
Western Systems Coordinating Council ("WSCC") are working closely together to
ensure the integrity of the interconnected electrical distribution and
transmission system in the Company's service area and the western United States.
NERC coordinates the efforts of the ten regional electric reliability councils
throughout the United States while WSCC is focused on reliable electric service
in the western United States. These agencies require Year 2000 readiness for all
interconnected electric utilities by July 1, 1999. The Company has submitted its
draft contingency plans to the WSCC as required by NERC. The Company will
participate in the NERC sponsored industry preparedness drill on April 9, 1999.
41
<PAGE>
The Company's worst case planning scenario assumes the following:
1. The public telecommunication system is not available or not functioning
reliably for up to a week.
2. At midnight on December 31, 1999, there is a near simultaneous loss of
multiple generating units resulting in transmission system instability and
regional black outs. Restoration of service will start immediately, but
some areas may not be fully restored and stable for twenty-four hours.
3. Temporary loss of automated transmission system monitoring and control
systems. These functions must be performed manually during restoration.
4. Temporary loss of customer billing system. Customers on billing cycles in
the early part of the month may receive an estimated billing that will be
adjusted the following month.
5. Temporary loss of receivables processing system.
6. Temporary loss of automated payroll system. Employees will be paid, but
some automated functions must be performed manually.
7. Temporary loss of automated shareholder services systems. Information must
be available to be accessed manually while automated systems are being
restored.
To address this potential scenario and in cooperation with efforts by NERC and
WSCC, the Company plans to establish a precautionary posture for its system
leading into December 31, 1999. This is similar to the posture taken when severe
winter weather is anticipated in areas of its service territory. Regional
connections would be deliberately disconnected only during, or immediately
following, a system disturbance in order to prevent further cascading outages
and to facilitate restoration. Additional personnel will be on hand at control
centers. Facilities such as power plants and key major substations will also
have additional personnel standing by. Backup systems will be serviced and
tested, as appropriate, prior to the transition period. Additional generation
will be brought on line for the transition period as needed.
The Company is continuing to expand its extensive microwave network in 1999.
Because this system is self-controlled and has been undergoing extensive
analysis for Year 2000 readiness, the Company considers this a reliable
alternative to the public telephone network if needed. Emergency power systems
will be tested and made ready. In addition to the microwave system, the Company
has an extensive radio network. Through integration of the Company's radio and
microwave, Company personnel can effectively "dial-up" telephones throughout the
Company's area. Radio units will be deployed at key locations during the
transition period. The Company is also planning to station satellite telephones
at system dispatching facilities and key power plants.
The Company's payment processing system has been certified by the vendor as
Year 2000 compliant. An emergency backup plan is being developed for deployment
by the third quarter of 1999 to enable third party off-site processing of
payments. Check issuance has been outsourced to a vendor who has represented
that it will be Year 2000 ready by the end of March 1999. To the extent
possible, accounts payable checks and wire transfers will be processed early in
December. Arrangements are expected to be made with the Company's banks to cover
critical payment obligations for up to seventy-two hours should wire transfers
be disrupted. The Company uses two systems to maintain shareholder records,
transfer stock, issue 1099 dividend statements and process dividend payments.
One system is certified compliant now, and the other is expected to be Year 2000
ready by June 30, 1999.
The Company has incurred $12.7 million in costs relating to the Year 2000
project through December 31, 1998. The majority of these costs have been
incurred to repair software problems. Estimates of the total cost of the Year
2000 project are approximately $30 million, which will be principally funded
from operating cash flows. This estimate does not include the cost of system
replacements that will be Year 2000 compliant, but are not being installed
primarily to resolve Year 2000 problems. Year 2000 information technology ("IT")
remediation costs
42
<PAGE>
amount to approximately 5% of IT's budget. The Company has not delayed any IT
projects that are critical to its operations as a result of Year 2000
remediation work. No independent verification of risk and cost estimates has
been undertaken to date.
The dates on which the Company believes the Year 2000 project will be
completed and the expected costs and other impacts of the Year 2000 issues are
based on management's best estimates, which were derived utilizing numerous
assumptions concerning future events, including the availability of certain
resources, the completion of third-party modification plans and other factors.
There can be no assurance that these estimates will be achieved, or that there
will not be a delay in, or increased costs associated with, the Company's
implementation of its Year 2000 project.
NEW ACCOUNTING STANDARDS
In June 1998, the Financial Accounting Standards Board issued SFAS 133,
"Accounting for Derivative Instruments and Hedging Activities." This statement,
which is effective for fiscal years beginning after June 15, 1999, requires an
entity to recognize all derivatives as either assets or liabilities in the
statement of financial position and measure those instruments at fair value.
Adoption of this standard will have an effect on the Company's financial
position and results of operations; however, the magnitude of the effect will be
determined by the hedges and derivatives that the Company has in place at the
date of adoption of the standard. The effects in future periods will be
dependent upon the derivatives and hedges in place at the end of each period.
In December 1998, the EITF reached a consensus on Issue No. 98-10.
"Accounting for Contracts Involved in Energy Trading and Risk Management
Activities," ("EITF 98-10"). EITF 98-10, which is effective for fiscal years
beginning after December 15, 1998, requires energy trading contracts to be
recorded at fair market value on the balance sheet, with the change in fair
market value included in earnings for the period of the change. The Company
anticipates that the cumulative effect of the adoption of EITF 98-10 at January
1, 1999 will be immaterial on the Company's financial position, results of
operations and cash flows. Restatement of prior period financial statements for
the adoption of EITF 98-10 is not permitted.
FORWARD-LOOKING STATEMENTS
The information in the tables and text in this document includes certain
forward-looking statements that involve a number of risks and uncertainties that
may influence the financial performance and earnings of the Company. When used
in this "Management's Discussion and Analysis of Financial Condition and Results
of Operations," the words "estimates," "expects," "anticipates," "forecasts,"
"plans," "intends" and variations of such words and similar expressions are
intended to identify forward-looking statements that involve risks and
uncertainties. There can be no assurance the results predicted will be realized.
Actual results will vary from those represented by the forecasts, and those
variations may be material.
The following factors are among the factors that could cause actual results
to differ materially from the forward-looking statements: utility commission
practices; regional and international economic conditions; weather variations
affecting customer usage; competition in bulk power and natural gas markets and
hydroelectric and natural gas production; energy trading activities;
environmental, regulatory and tax legislation, including industry restructure
and deregulation initiatives; technological developments in the electricity
industry; foreign exchange rates; the pending ScottishPower merger; proposed
asset dispositions; and the cost of debt and equity capital. Any forward-looking
statements issued by the Company should be considered in light of these factors.
43
<PAGE>
REPORT OF MANAGEMENT
The management of PacifiCorp and its subsidiaries (the "Company") is responsible
for preparing the accompanying consolidated financial statements and for their
integrity and objectivity. The statements were prepared in accordance with
generally accepted accounting principles. The financial statements include
amounts that are based on management's best estimates and judgments. Management
also prepared the other information in the annual report and is responsible for
its accuracy and consistency with the financial statements.
The Company's financial statements were audited by Deloitte & Touche LLP
("Deloitte & Touche"), independent public accountants. Management made available
to Deloitte & Touche all the Company's financial records and related data, as
well as the minutes of shareholders' and directors' meetings.
Management of the Company established and maintains an internal control
structure that provides reasonable assurance as to the integrity and reliability
of the financial statements, the protection of assets from unauthorized use or
disposition and the prevention and detection of materially fraudulent financial
reporting. The Company maintains an internal auditing program that independently
assesses the effectiveness of the internal control structure and recommends
possible improvements. Deloitte & Touche considered that internal control
structure in connection with their audit. Management reviews significant
recommendations by the internal auditors and Deloitte & Touche concerning the
Company's internal control structure and ensures appropriate cost-effective
actions are taken.
The Company's "Guide to Business Conduct" is distributed to employees
throughout the Company to provide a basis for ethical standards and conduct. The
guide addresses, among other things, potential conflicts of interests and
compliance with laws, including those relating to financial disclosure and the
confidentiality of proprietary information. In early 1998, the Company formed a
Business Conduct Group in order to dedicate more resources to business conduct
issues, and to provide more consistent and thorough communications and training
in legal compliance and ethical conduct.
The Audit Committee of the Board of Directors is comprised solely of outside
directors. It meets at least quarterly with management, Deloitte & Touche,
internal auditors and counsel to review the work of each and ensure the
Committee's responsibilities are being properly discharged. Deloitte & Touche
and internal auditors have free access to the Committee, without management
present, to discuss, among other things, their audit work and their evaluations
of the adequacy of the internal control structure and the quality of financial
reporting.
(signatures)
KEITH R. MCKENNON ROBERT R. DALLEY
Keith R. McKennon Robert R. Dalley
CHAIRMAN, PRESIDENT AND CONTROLLER AND
CHIEF EXECUTIVE OFFICER CHIEF ACCOUNTING OFFICER
44
<PAGE>
INDEPENDENT AUDITORS' REPORT
TO THE SHAREHOLDERS AND BOARD OF DIRECTORS OF PACIFICORP:
We have audited the accompanying consolidated balance sheets of PacifiCorp and
subsidiaries as of December 31, 1998 and 1997, and the related statements of
consolidated income, consolidated changes in common shareholders' equity and
consolidated cash flows for each of the three years in the period ended December
31, 1998. 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 financial statements present fairly, in all material
respects, the consolidated financial position of PacifiCorp and subsidiaries at
December 31, 1998 and 1997, and the results of their operations and their cash
flows for each of three years in the period ended December 31, 1998, in
conformity with generally accepted accounting principles.
(SIGNATURE)
Portland, Oregon
March 5, 1999
45
<PAGE>
<TABLE>
<CAPTION>
STATEMENTS OF CONSOLIDATED INCOME
for the year || millions of dollars, except per share amounts 1998 1997 1996
- ---------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C>
Revenues $5,580.4 $4,548.9 $3,792.0
Expenses
Purchased power 2,821.5 1,605.0 923.9
Other operations and maintenance 1,081.9 1,078.8 1,017.4
Administrative and general 322.9 319.0 241.3
Depreciation and amortization 451.2 466.1 423.8
Taxes, other than income taxes 98.7 98.9 99.3
Special charges 123.4 170.4 -
--------------------------------
Total 4,899.6 3,738.2 2,705.7
--------------------------------
Income from Operations 680.8 810.7 1,086.3
--------------------------------
Interest Expense and Other
Interest expense 371.6 437.8 415.0
Interest capitalized (14.5) (12.2) (11.4)
Losses from equity investments 13.9 12.8 4.1
TEG costs and option losses 73.0 105.6 -
Write down of investments in energy development companies 79.5 - -
Gain on sale of PGC - (56.5) -
Minority interest and other (12.4) (21.5) 11.8
--------------------------------
Total 511.1 466.0 419.5
--------------------------------
Income from continuing operations before income taxes 169.7 344.7 666.8
Income tax expense 59.1 111.8 236.5
--------------------------------
Income from continuing operations before extraordinary item 110.6 232.9 430.3
Discontinued operations (less applicable income tax
expense/(benefit): 1998/$(74.3), 1997/$361.1 and 1996/$47.4) (146.7) 446.8 74.6
Extraordinary loss from regulatory asset impairment
(less applicable income tax benefit of $9.6) - (16.0) -
--------------------------------
Net Income (Loss) $ (36.1) $ 663.7 $ 504.9
--------------------------------
Earnings (Loss) on Common Stock $ (55.4) $ 640.9 $ 475.1
Average number of common shares outstanding -
basic and diluted (Thousands) 297,229 296,094 292,424
Earnings (Loss) per Common Share - Basic and Diluted
Continuing operations $ 0.30 $ 0.71 $ 1.37
Discontinued operations (0.49) 1.50 0.25
Extraordinary item - (0.05) -
--------------------------------
Total $ (0.19) $ 2.16 $ 1.62
================================
(See accompanying Notes to Consolidated Financial Statements)
</TABLE>
46
<PAGE>
<TABLE>
<CAPTION>
STATEMENTS OF CONSOLIDATED CASH FLOWS
for the year || millions of dollars 1998 1997 1996
- ------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C>
Cash Flows from Operating Activities
Net Income (Loss) $ (36.1) $ 663.7 $ 504.9
Adjustments to reconcile net income (loss)
to net cash provided by continuing operations
Losses (income) from discontinued operations 146.7 (81.7) (74.6)
Gain on disposal of discontinued operations - (365.1) -
Extraordinary loss from regulatory asset impairment - 16.0 -
Write down of investments in energy development companies 79.5 - -
Depreciation and amortization 460.1 481.5 440.5
Deferred income taxes and investment tax credits - net (47.9) (55.5) 26.1
Special charges 123.4 170.4 -
Gain on sale of subsidiary and assets (11.0) (56.5) -
Other 23.0 46.0 (25.6)
Accounts receivable and prepayments (34.2) (135.5) (154.1)
Materials, supplies, fuel stock and inventory 6.2 (6.5) 26.8
Accounts payable and accrued liabilities (24.8) 159.1 144.4
----------------------------------------
Net cash provided by continuing operations 684.9 835.9 888.4
Net cash provided by (used in) discontinued operations (433.7) (217.3) 37.0
----------------------------------------
Net Cash Provided by Operating Activities 251.2 618.6 925.4
----------------------------------------
Cash Flows from Investing Activities
Construction (609.9) (577.7) (528.1)
Operating companies and assets acquired (44.8) (65.6) (199.4)
Investments in and advances to affiliated companies - net (11.9) (70.9) (148.4)
Proceeds from sales of assets 111.0 1,666.3 49.3
Proceeds from sales of finance assets and principal payments 311.7 103.2 55.8
Other (31.8) (58.5) (10.5)
----------------------------------------
Net Cash Provided by (Used in) Investing Activities (275.7) 996.8 (781.3)
----------------------------------------
Cash Flows from Financing Activities
Changes in short-term debt 71.5 (494.4) (247.6)
Proceeds from long-term debt 1,829.0 726.4 567.6
Proceeds from issuance of common stock 10.8 37.4 223.9
Proceeds from issuance of preferred securities
of Trust holding solely PacifiCorp debentures
- 130.6 209.6
Dividends paid (337.3) (341.2) (346.4)
Repayments of long-term debt (1,731.6) (779.6) (284.5)
Redemptions of capital stock - (72.2) (221.6)
Other 24.4 (90.0) (52.5)
----------------------------------------
Net Cash Used in Financing Activities (133.2) (883.0) (151.5)
----------------------------------------
Increase/(Decrease) in Cash and Cash Equivalents (157.7) 732.4 (7.4)
Cash and Cash Equivalents at Beginning of Year 740.8 8.4 15.8
----------------------------------------
Cash and Cash Equivalents at End of Year $ 583.1 $ 740.8 $ 8.4
========================================
(See accompanying Notes to Consolidated Financial Statements)
</TABLE>
47
<PAGE>
<TABLE>
<CAPTION>
CONSOLIDATED BALANCE SHEETS
ASSETS
December 31 || millions of dollars 1998 1997
- ---------------------------------------------------------------------------------------------------------------------
<S> <C> <C>
Current Assets
Cash and cash equivalents $ 583.1 $ 740.8
Accounts receivable less allowance for doubtful accounts:
1998/$18.0 and 1997/$17.7 703.2 723.9
Materials, supplies and fuel stock at average cost 175.8 181.9
Net assets of discontinued operations and assets held for sale 192.4 223.4
Real estate investments held for sale - 272.2
Other 87.9 55.1
--------------------------
Total Current Assets 1,742.4 2,197.3
Property, Plant and Equipment
Domestic Electric Operations
Production 4,844.2 4,720.6
Transmission 2,102.3 2,087.8
Distribution 3,319.7 3,244.0
Other 1,947.0 1,784.8
Construction work in progress 246.8 257.4
Total Domestic Electric Operations 12,460.0 12,094.6
Australian Electric Operations 1,140.4 1,161.2
Other Operations 22.2 31.0
Accumulated depreciation and amortization (4,553.2) (4,240.0)
--------------------------
Total Property, Plant and Equipment - net 9,069.4 9,046.8
Other Assets
Investments in and advances to affiliated companies 114.9 166.1
Intangible assets - net 369.4 399.0
Regulatory assets - net 795.5 871.1
Finance note receivable 204.9 211.2
Finance assets - net 313.7 349.8
Deferred charges and other 378.3 385.7
--------------------------
Total Other Assets 2,176.7 2,382.9
Total Assets $ 12,988.5 $ 13,627.0
==========================
48
<PAGE>
LIABILITIES AND SHAREHOLDERS' EQUITY
Current Liabilities
Long-term debt currently maturing $ 299.5 $ 365.4
Notes payable and commercial paper 260.6 189.2
Accounts payable 566.2 546.7
Taxes, interest and dividends payable 282.7 677.4
Customer deposits and other 168.0 84.9
Total Current Liabilities 1,577.0 1,863.6
Deferred Credits
Income taxes 1,542.6 1,666.2
Investment tax credits 125.3 135.2
Other 646.1 646.3
Total Deferred Credits 2,314.0 2,447.7
Long-Term Debt 4,559.3 4,413.0
Commitments and Contingencies (See Note 13) - -
Guaranteed Preferred Beneficial Interests
in Company's Junior Subordinated Debentures 340.5 340.4
Preferred Stock Subject to Mandatory Redemption 175.0 175.0
Preferred Stock 66.4 66.4
Common Equity
Common shareholders' capital shares authorized 750,000,000;
shares outstanding: 1998/297,343,422 and 1997/296,908,110 3,285.0 3,274.2
Retained earnings 732.0 1,106.3
Accumulated other comprehensive income (60.7) (59.6)
--------------------------
Total Common Equity 3,956.3 4,320.9
--------------------------
Total Liabilities and Shareholders' Equity $ 12,988.5 $ 13,627.0
==========================
(See accompanying Notes to Consolidated Financial Statements)
</TABLE>
49
<PAGE>
STATEMENTS OF CONSOLIDATED CHANGES IN COMMON SHAREHOLDERS' EQUITY
<TABLE>
<CAPTION>
common accumulated
shareholders' other total
capital retained comprehensive comprehensive
millions of dollars || thousands of shares shares amount earnings income income (loss)
- ----------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C>
Balance, January 1, 1996 284,277 $3,012.9 $ 632.4 $ - $ -
Comprehensive income
Net income - - 504.9 - 504.9
Other comprehensive income
Foreign currency translation adjustment,
net of tax of $8.0 - - - 12.7 12.7
Cash dividends declared
Preferred stock - - (29.1) - -
Common stock ($1.08 per share) - - (317.9) - -
Preferred stock retired - - (7.5) - -
Sales to public 8,790 177.8 - - -
Sales through Dividend Reinvestment
and Stock Purchase Plan 2,073 43.2 - - -
Redemptions and repurchases - 2.9 - - -
-------------------------------------------------------------------
Balance, December 31, 1996 295,140 3,236.8 782.8 12.7 $ 517.6
===================================================================
Comprehensive income
Net income - - 663.7 - $ 663.7
Other comprehensive income
Foreign currency translation adjustment,
net of tax of $46.9 - - - (72.3) (72.3)
Cash dividends declared
Preferred stock - - (20.0) - -
Common stock ($1.08 per share) - - (320.0) - -
Preferred stock retired - - (0.2) - -
Sales through Dividend Reinvestment
and Stock Purchase Plan 1,768 37.4 - - -
-------------------------------------------------------------------
Balance, December 31, 1997 296,908 3,274.2 1,106.3 (59.6) $ 591.4
===================================================================
Comprehensive income (loss)
Net loss - - (36.1) - $ (36.1)
Other comprehensive income (loss)
Unrealized gain on available-for-sale securities,
net of tax of $3.8 - - - 6.2 6.2
Foreign currency translation adjustment,
net of tax of $4.0 - - - (7.3) (7.3)
Cash dividends declared
Preferred stock - - (17.2) - -
Common stock ($1.08 per share) - - (321.0) - -
Sales through Dividend Reinvestment
and Stock Purchase Plan 346 9.1 - - -
Stock options exercised 89 1.7 - - -
-------------------------------------------------------------------
Balance, December 31, 1998 297,343 $3,285.0 $ 732.0 $ (60.7) $ (37.2)
===================================================================
(See accompanying Notes to Consolidated Financial Statements)
</TABLE>
50
<PAGE>
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Years ended December 31, 1998, 1997 and 1996
NOTE 1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
BASIS OF PRESENTATION The consolidated financial statements of PacifiCorp
include its integrated domestic electric utility operating divisions of Pacific
Power and Utah Power and its wholly owned and majority owned subsidiaries (the
"Company" or "Companies"). Major subsidiaries, all of which are wholly owned,
are: PacifiCorp Group Holdings Company ("Holdings"), which holds directly or
through its wholly owned subsidiary, PacifiCorp International Group Holdings
Company, all of the Company's nonintegrated electric utility investments,
including Powercor Australia Limited ("Powercor"), an Australian electricity
distributor, and PacifiCorp Financial Services, Inc. ("PFS"), a financial
services business. Significant intercompany transactions and balances have been
eliminated.
Investments in and advances to affiliated companies represent investments in
unconsolidated affiliated companies carried on the equity basis, which
approximate the Company's equity in their underlying net book value.
During October 1998, the Company decided to exit its energy trading business,
which consists of TPC Corporation ("TPC") and PacifiCorp Power Marketing
("PPM"). See Note 4.
The Company sold its wholly owned telecommunications subsidiary, Pacific
Telecom, Inc. ("PTI"), on December 1, 1997. See Note 4. The Company sold Pacific
Generation Company ("PGC") on November 5, 1997, and the natural gas gathering
and processing assets of TPC on December 1, 1997. During May 1998, the Company
sold a majority of the real estate assets held by PFS. See Note 16.
The Company has also decided to exit the majority of its other energy
development businesses and has recorded them at estimated net realizable value
less selling costs. See Note 16.
USE OF ESTIMATES The preparation of financial statements in conformity with
generally accepted accounting principles requires management to make estimates
and assumptions that affect the reported amounts of assets and liabilities and
disclosure of contingent assets and liabilities at the date of the financial
statements. Actual results could differ from those estimates.
REGULATION Accounting for the majority of the domestic electric utility
business conforms with generally accepted accounting principles as applied to
regulated public utilities and as prescribed by agencies and the commissions of
the various locations in which the domestic electric utility business operates.
The Company prepares its financial statements as they relate to Domestic
Electric Operations in accordance with Statement of Financial Accounting
Standards ("SFAS") 71, "Accounting for the Effects of Certain Types of
Regulation." See Note 5.
ASSET IMPAIRMENTS Long-lived assets and certain identifiable intangibles to be
held and used by the Company are reviewed for impairment when events or
circumstances indicate costs may not be recoverable. Such reviews are done in
accordance with SFAS No. 121. The impacts of regulation on cash flows are
considered when determining impairment. Impairment losses on long-lived assets
are recognized when book values exceed expected undiscounted future cash flows.
If impairment exists, the asset's book value will be written down to its fair
value.
CASH AND CASH EQUIVALENTS For the purposes of these financial statements, the
Company considers all liquid investments with maturities of three months or less
at the time of acquisition to be cash equivalents.
FOREIGN CURRENCY Financial statements for foreign subsidiaries are translated
into United States dollars at end of period exchange rates as to assets and
liabilities and weighted average exchange rates as to revenues and expenses. The
resulting translation gains or losses are accumulated in the "accumulated other
comprehensive income" account, a component of common equity and comprehensive
income. All gains and losses resulting from foreign currency transactions are
included in the determination of net income.
PROPERTY, PLANT AND EQUIPMENT Property, plant and equipment are stated at
original cost of contracted services, direct labor and materials, interest
capitalized during construction and indirect charges for engineering,
supervision and similar overhead items. The cost of depreciable domestic
electric utility properties retired, including the cost of removal, less
salvage, is charged to accumulated depreciation.
51
<PAGE>
DEPRECIATION AND AMORTIZATION At December 31, 1998, the average depreciable
lives of property, plant and equipment by category were: Domestic Electric
Operations - Production, 37 years; Transmission, 42 years; Distribution, 30
years; Other, 16 years; and Australian Electric Operations, 23 years.
Depreciation and amortization is generally computed by the straight-line
method in the following manner: As prescribed by the Company's various
regulatory jurisdictions for Domestic Electric Operations' regulated assets; and
over the estimated useful lives of the related assets for Domestic Electric
Operations' nonregulated generation resource assets and for other nonregulated
assets. Provisions for depreciation (excluding amortization of capital leases)
in the domestic electric and Australian electric businesses were 3.3%, 3.4% and
3.2% of average depreciable assets in 1998, 1997 and 1996, respectively.
MINE RECLAMATION AND CLOSURE COSTS The Company expenses current mine
reclamation costs and accrues for estimated final mine reclamation and closure
costs using the units-of-production method.
INVENTORY VALUATION Inventories are generally valued at the lower of average
cost or market.
INTANGIBLE ASSETS Intangible assets consist of license and other intangible
costs relating to Australian Electric Operations ($375 million and $24 million,
respectively, in 1998 and $393 million and $26 million, respectively, in 1997).
These costs are offset by accumulated amortization ($30 million in 1998 and $20
million in 1997). Licenses and other intangible costs are generally being
amortized over 40 years. Intangible assets decreased $18 million in 1998 due to
lower foreign currency exchange rates.
FINANCE ASSETS Finance assets consist of finance receivables, leveraged leases
and operating leases and are not significant to the Company in terms of revenue,
net income or assets. The Company's leasing operations consist principally of
leveraged aircraft leases. Investments in finance assets are net of allowances
for credit losses and accumulated impairment charges of $27 million and $47
million at December 31, 1998 and 1997, respectively.
DERIVATIVES Gains and losses on hedges of existing assets and liabilities are
included in the carrying amounts of those assets or liabilities and are
recognized in income as part of the carrying amounts. Gains and losses related
to hedges of anticipated transactions and firm commitments are deferred on the
balance sheet and recognized in income when the transaction occurs. Nonhedged
derivative instruments are marked-to-market with gains or losses recognized in
the determination of net income.
INTEREST CAPITALIZED Costs of debt applicable to domestic electric utility
properties are capitalized during construction. The composite capitalization
rates were 5.7% for 1998 and 1997 and 5.6% for 1996.
INCOME TAXES The Company uses the liability method of accounting for deferred
income taxes. Deferred tax liabilities and assets reflect the expected future
tax consequences, based on enacted tax law, of temporary differences between the
tax bases of assets and liabilities and their financial reporting amounts.
Prior to 1980, Domestic Electric Operations did not provide deferred taxes on
many of the timing differences between book and tax depreciation. In prior
years, these benefits were flowed through to the utility customer as prescribed
by the Company's various regulatory jurisdictions. Deferred income tax
liabilities and regulatory assets have been established for those flow through
tax benefits. See Note 14.
Investment tax credits for regulated Domestic Electric Operations are
deferred and amortized to income over periods prescribed by the Company's
various regulatory jurisdictions.
Provisions for United States income taxes are made on the undistributed
earnings of the Company's international businesses.
REVENUE RECOGNITION The Company accrues estimated unbilled revenues for
electric services provided after cycle billing to month-end.
COMPREHENSIVE INCOME Effective January 1, 1998, the Company adopted SFAS 130,
"Reporting Comprehensive Income." This statement requires items reported as a
component of common equity be more prominently reported in a separate financial
statement as a component of comprehensive income. As permitted by SFAS 130, the
Company has not included a statement of comprehensive income. Instead the
Company included the amounts on the Statement of Consolidated Changes in Common
Shareholders' Equity.
52
<PAGE>
ENERGY TRADING Revenues and purchased energy expense for the Company's energy
trading and marketing activities are recorded upon delivery of electricity.
Beginning January 1, 1999, the Company will apply marked-to-market accounting
for all energy trading activities and present the net margin.
PREFERRED STOCK RETIRED Amounts paid in excess of the net carrying value of
preferred stock retired are amortized over five years in accordance with
regulatory orders.
STOCK BASED COMPENSATION As permitted by SFAS 123, "Accounting for Stock Based
Compensation," the Company has elected to follow Accounting Principles Board
Opinion No. 25, "Accounting for Stock Issued to Employees" ("APB 25") and
related interpretations in accounting for its employee stock options. Under APB
25, because the exercise price of employee stock options equals the market price
of the underlying stock on the date of grant, no compensation expense is
recorded.
EARNINGS PER COMMON SHARE The Company computes Earnings per Common Share
("EPS") based on SFAS 128, "Earnings per Share." Basic EPS is computed by
dividing earnings on common stock by the weighted average number of common
shares outstanding. Diluted EPS for the Company is computed by dividing earnings
on common stock by the weighted average number of common shares outstanding,
including shares that would be outstanding assuming the exercise of granted
stock options. The Company's basic and diluted EPS are the same for all periods
presented herein.
NEW ACCOUNTING STANDARDS In June 1998, the Financial Accounting Standards
Board ("FASB") issued SFAS 133, "Accounting for Derivative Instruments and
Hedging Activities." This statement, which is effective for fiscal years
beginning after June 15, 1999, requires an entity to recognize all derivatives
as either assets or liabilities in the statement of financial position and to
measure those instruments at fair value. Adoption of this standard will have an
effect on the Company's financial position and results of operations. The
magnitude of the effect will be determined by the hedges and derivatives that
the Company has in place at the adoption of the standard. The effects in future
periods will be dependent upon the derivatives and hedges in place at the end of
each period.
In December 1998, the Emerging Issues Task Force (the "EITF") reached a
consensus on Issue No. 98-10. "Accounting for Contracts Involved in Energy
Trading and Risk Management Activities," ("EITF 98-10"). EITF 98-10, which is
effective for fiscal years beginning after December 15, 1998, requires energy
trading contracts to be recorded at fair market value on the balance sheet, with
the change in fair market value included in earnings for the period of the
change. The Company anticipates that the cumulative effect of the adoption of
EITF 98-10 at January 1, 1999 will be immaterial on the Company's financial
position, results of operation and cash flows. Restatement of prior period
financial statements for the adoption of EITF 98-10 is not permitted.
RECLASSIFICATION Certain amounts from prior years have been reclassified to
conform with the 1998 method of presentation. These reclassifications had no
effect on previously reported consolidated net income.
NOTE 2. PROPOSED SCOTTISHPOWER MERGER
On December 6, 1998, PacifiCorp signed an Agreement and Plan of Merger with
Scottish Power plc ("ScottishPower") and NA General Partnership. ScottishPower
subsequently announced its intention to establish a new holding company for the
ScottishPower group pursuant to a court approved reorganization in the U.K.
Accordingly, on February 23, 1999, the parties executed an amended and restated
merger agreement (the "Agreement") under which PacifiCorp will become an
indirect, wholly owned subsidiary of the new holding company, which will be
renamed Scottish Power plc ("New ScottishPower"), and ScottishPower will become
a sister company to PacifiCorp. PacifiCorp will continue to operate under its
current name, and its headquarters will remain in Portland, Oregon.
In the merger, each share of PacifiCorp's common stock will be converted into
the right to receive 0.58 New ScottishPower American Depositary Shares ("ADS")
(each New ScottishPower ADS represents four ordinary shares), which will be
listed on the New York Stock Exchange, or, upon the proper election of the
holders of PacifiCorp's common stock, 2.32 ordinary shares of New ScottishPower,
which will be listed on the London Stock Exchange.
If the proposed reorganization is not completed, the parties will proceed
under the original agreement, and PacifiCorp will become an indirect, wholly
owned subsidiary of ScottishPower. The merger is not conditional on the
reorganization becoming effective nor is the reorganization conditional upon the
merger becoming effective.
53
<PAGE>
Both companies' boards of directors have approved the Agreement. However,
before the transactions under the Agreement can be consummated, a number of
conditions must be satisfied, including obtaining approvals and consents from
shareholders of both companies, the Federal Energy Regulatory Commission
("FERC"), the Nuclear Regulatory Commission, the regulatory commissions in
certain of the states served by the Company and Australian regulatory
authorities. The parties have received early termination of the waiting period
under the provisions of the Hart-Scott-Rodino Antitrust Improvement Act.
Hearings on the merger have been scheduled for July and August 1999 by the
Oregon, Utah, Wyoming and Idaho commissions. Both companies expect to have
shareholder meetings in mid-1999 requesting shareholder approval of the merger.
The Agreement requires that the Company pay a $250 million termination fee to
New ScottishPower under certain circumstances following a bona fide proposal by
a third party to acquire the Company. The Agreement requires New ScottishPower
to pay a $250 million termination fee to the Company if the Company terminates
the Agreement upon a change in control of New ScottishPower. In addition, the
Agreement requires each party to pay a $10 million termination fee if, under
certain circumstances, its shareholder approval is not obtained and the other
party's shareholder approval is obtained.
During 1998, the Company incurred $13 million in costs associated with the
proposed ScottishPower merger.
NOTE 3. BID FOR THE ENERGY GROUP
During 1997 and 1998, the Company sought to acquire The Energy Group PLC
("TEG"), a diversified international energy group with operations in the United
Kingdom, the United States and Australia. The Company made three tender offers
for TEG. The last offer was valued at $11.1 billion, including the assumption of
$4.1 billion of TEG's debt. In March 1998, another United States utility made a
tender offer at a price higher than the Company's offer and on April 30, 1998,
the Company announced that it would not increase its revised offer for TEG.
The Company recorded an $86 million pretax charge ($54 million after-tax, or
$0.18 per share) to first quarter 1998 earnings, included in "TEG costs and
option losses," for bank commitment and facility fees, legal expenses and other
related costs incurred since the Company's original bid for TEG in June of 1997.
These costs had been deferred pending the outcome of the transaction. The
Company incurred a pretax expense of $3 million ($2 million after-tax, or $0.01
per share) in April 1998 in connection with closing its foreign currency option
contract associated with the bid for TEG.
Additionally, in connection with the attempt to acquire TEG, a subsidiary of
the Company purchased approximately 46 million shares of TEG at a price of 820
pence per share, or $625 million. The Company recorded a pretax gain on the TEG
shares of $16 million ($10 million after-tax, or $0.03 per share) when they were
sold on June 2, 1998.
Upon initiation of the original tender offer in June 1997, the Company also
entered into foreign currency exchange contracts. The financing facilities
associated with the June 1997 offer for TEG terminated upon referral to the
Monopolies and Mergers Commission and the Company initiated steps to unwind its
foreign currency exchange positions consistent with its policies on derivatives.
As a result of the termination of these positions and initial option costs, the
Company realized a pretax loss of approximately $106 million ($65 million
after-tax, or $0.22 per share) in the third quarter of 1997.
NOTE 4. DISCONTINUED OPERATIONS
In October 1998, the Company decided to exit its energy trading business by
offering for sale TPC, and ceasing the operations of PPM, which conducted
electricity trading in the eastern United States. PPM's activities in the
eastern United States have been discontinued and all forward electricity trading
has been closed and is going through settlement. PPM will continue to honor
contracts to manage the power supply of two municipalities, the longest of such
contracts will expire in late 1999. Holdings entered into an agreement, dated
February 9, 1999, to sell TPC for approximately $133 million. In addition, a
working capital adjustment will be calculated and paid following closing of the
TPC transaction, which is expected during the first half of 1999.
As a result of the pending sale agreement for TPC and the results of
discontinued operations from September 30 to December 31, the Company adjusted
its losses from discontinued operations as of the end of 1998. The following
table sets forth the changes in the write down of the energy trading segment
value and the anticipated losses to the sale or exit of those operations.
54
<PAGE>
<TABLE>
<CAPTION>
at at
September 30 December 31
millions of dollars 1998 1998
- --------------------------------------------------------------------------------------------
<S> <C> <C>
Write down of segment net assets $ 138.5 $ 83.5
Estimated operating losses to disposal date 20.0 52.3
Estimated employee related costs 14.0 9.0
Estimated facilities related costs 2.2 3.4
Estimated selling and other costs 3.5 6.8
-----------------------
Total $ 178.2 $ 155.0
=======================
</TABLE>
Operating losses from September 30 through December 31, 1998 amounted to $37.9
million and represented cash contributions to the energy trading segment. A
majority of the remaining anticipated losses of this segment are expected to be
incurred in the first half of 1999.
On December 1, 1997, Holdings completed the sale of PTI to Century Telephone
Enterprises, Inc. ("Century"). Pursuant to a stock purchase agreement dated June
11, 1997, Century acquired all the stock of PTI for $1.5 billion in cash plus
the assumption of PTI's debt of $713 million. The sale resulted in a gain of
$365 million net of income taxes of $306 million, or $1.23 per share. A portion
of the proceeds from the sale of PTI were used to repay short-term debt of
Holdings. The remaining proceeds were invested in short-term money market
instruments and Holdings temporarily advanced excess funds to Domestic Electric
Operations for retirement of short-term debt.
The net assets, operating results and cash flows of the energy trading
segment and PTI have been classified as discontinued operations for all periods
presented in the consolidated financial statements and notes.
Summarized operating results for unregulated energy trading were as follows:
<TABLE>
<CAPTION>
for the year ended December 31 || millions of dollars 1998 1997 1996
- ------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C>
Revenues $2,961.4 $1,729.0 $ 11.7
----------------------------------
Loss from discontinued operations (less applicable income tax
benefit: 1998/$24.3, 1997/$2.3, 1996/$-) $ (41.7) $ (7.5) $ (0.1)
Loss on disposal, including provision of $52.3 for operating losses
during phase-out period (less applicable
income tax benefit $50.0) (105.0) - -
----------------------------------
Net loss $ (146.7) $ (7.5) $ (0.1)
----------------------------------
</TABLE>
Summarized operating results for PTI were as follows:
<TABLE>
<CAPTION>
for the eleven for the
year ended months ended year ended
December 31 November 30 December 31
millions of dollars 1998 1997 1996
- ---------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C>
Revenues $ - $ 522.4 $ 521.1
-------------------------------------
Income from discontinued operations (less applicable income tax
expense: 1997/$57.6 and 1996/$47.4) $ - $ 89.2 $ 74.7
Gain on disposal (less applicable income tax expense of $305.8) - 365.1 -
-------------------------------------
Net income $ - $ 454.3 $ 74.7
Total income (loss) from discontinued operations $ (146.7) $ 446.8 $ 74.6
=====================================
</TABLE>
55
<PAGE>
Net assets of the discontinued operations of the energy trading segment and
assets held for sale consisted of the following:
<TABLE>
<CAPTION>
December 31 || millions of dollars 1998 1997
- -----------------------------------------------------------------------------------------------------
<S> <C> <C>
Current assets $ 148.5 $ 208.5
Noncurrent assets 152.7 269.5
Current liabilities (96.0) (241.9)
Long-term debt (1.3) (1.5)
Noncurrent liabilities (28.9) (11.2)
Assets held for sale 17.4 -
---------------------
Net Assets of Discontinued Operations and Assets Held for Sale $ 192.4 $ 223.4
=====================
</TABLE>
In 1998, Holdings recorded $34 million of additional liabilities in "Customer
deposits and other" relating to the sale of the discontinued operations.
NOTE 5. ACCOUNTING FOR THE EFFECTS OF REGULATION
Regulated utilities have historically applied the provisions of SFAS 71 which is
based on the premise that regulators will set rates that allow for the recovery
of a utility's costs, including cost of capital. Accounting under SFAS 71 is
appropriate as long as: rates are established by or subject to approval by
independent, third-party regulators; rates are designed to recover the specific
enterprise's cost-of-service; and in view of demand for service, it is
reasonable to assume that rates are set at levels that will recover costs and
can be collected from customers. In applying SFAS 71, the Company must give
consideration to changes in the level of demand or competition during the cost
recovery period. In accordance with SFAS 71, Domestic Electric Operations
capitalizes certain costs as regulatory assets in accordance with regulatory
authority whereby those costs will be expensed and recovered in future periods.
The EITF of the FASB concluded in 1997 that SFAS 71 should be discontinued
when detailed legislation or regulatory order regarding competition is issued.
Additionally, the EITF concluded that regulatory assets and liabilities
applicable to businesses being deregulated should be written off unless their
recovery is provided for through future regulated cash flows.
Legislative actions in California and Montana during 1996 and 1997 mandated
customer choice of electricity supplier, moving away from cost-based regulation
to competitive market rates for the generation portion of the electric business.
As a result of these legislative actions, the Company evaluated its generation
regulatory assets and liabilities in California and Montana based upon future
regulated cash flows and ceased the application of SFAS 71 to its generation
business allocable to California and Montana. Domestic Electric Operations
recorded an extraordinary loss of $16 million, or $0.05 per share, in 1997 for
the write off of regulatory assets in these states. The regulatory assets
written off resulted primarily from deferred taxes allocated to California and
Montana. The allocation among the states was based on plant balances.
In 1998, the Company announced its intent to sell its California and Montana
electric distribution assets. This action was in response to the continued
decline in earnings on the assets and the changes in the legislative and
regulatory environments in these states. The Company issued requests for
proposals to interested parties on July 20, 1998. On November 5, 1998, the
Company sold its Montana electric distribution assets to Flathead Electric
Cooperative, Inc. and received proceeds of $89 million, net of taxes and
customer refunds. The Company returned $4 million of the $8 million gain on the
sale to Montana customers as negotiated with the Montana Public Service
Commission and the Montana Consumer Counsel. The Company has received bids for
its California electric distribution assets. These bids remain open and the
Company is holding discussions with the bidders.
56
<PAGE>
Regulatory assets-net included the following:
<TABLE>
<CAPTION>
December 31 || millions of dollars 1998 1997
- ----------------------------------------------------------------------------------------------
<S> <C> <C>
Deferred taxes - net/a $ 602.9 $ 650.1
Demand-side resource costs 96.9 108.3
Unamortized net loss on reacquired debt 53.4 60.6
Unrecovered Trojan Plant and regulatory study costs 22.2 23.0
Various other costs 20.1 29.1
--------------------
Total $ 795.5 $ 871.1
====================
/a Excludes $125 million in 1998 and $135 million in 1997 of investment tax
credit regulatory liabilities.
</TABLE>
The Company operates in five other states (Oregon, Utah, Wyoming, Washington and
Idaho) that are in various stages of addressing deregulation of the electricity
industry. At December 31, 1998, approximately $350 million of the $796 million
total regulatory assets - net was applicable to generation. Potential regulatory
or legislative actions in the states may result in additional write offs and
charges.
The Company evaluates the recovery of all their regulatory assets annually.
The evaluation includes the probability of recovery as well as changes in the
regulatory environment. The regulatory assets associated with pensions are
substantially comprised of prior work force reductions and a deferred
compensation plan whose preexisting liabilities were transferred to the
Company's pension plan. In late 1997, because of the legislative actions taken
by California and Montana relating to the process of deregulation coupled with
the Company's belief that other regulatory bodies would proceed with
deregulation, the Company evaluated its regulatory assets for potential
impairment. This evaluation revealed that the deferred regulatory pension asset
was the least likely of the regulatory assets to be recovered and the Company at
that time decided not to seek recovery of this regulatory asset. As a result of
the evaluation and decision, the Company recorded an $87 million write off of
its deferred regulatory pension asset in 1997. During 1998, evolution toward
deregulation continued, albeit at a slower pace. Accordingly, the Company is
evaluating its position with respect to seeking recovery of these costs through
rates. The probability of such recovery cannot presently be determined.
During 1997, the Utah Public Service Commission (the "UPSC") held hearings on
the method used in allocating common (generation, transmission and corporate
related) costs among the Company's jurisdictions and issued an order in April
1998. Under the order, differences in allocations associated with the 1989
merger of Pacific Power & Light Company and Utah Power & Light Company were to
be eliminated over five years on a straight-line basis. The phase-out of the
differences was to be completed by January 1, 2001 and could have reduced Utah
customer prices by about $50 to $60 million annually once fully implemented. The
ratable impact of this order was to be included in a general rate case thereby
combining it with all other cost-of-service items in determining the ultimate
impact on customer prices.
In 1998, the UPSC commenced a general rate case to consider the impact of the
April 1998 allocation order, other cost-of-service issues and the
appropriateness of the Company's authorized rate of return on equity. On March
4, 1999, an order was issued by the UPSC in the general rate case. The order
requires the Company to reduce revenues in the state of Utah by $85 million, or
12%, annually. The UPSC also ordered that the allocation order be implemented
immediately and not phased-in as originally ordered. Additionally, the UPSC
ordered a refund to be issued through a credit on customer bills of $40 million.
The Company recorded a $38 million reduction in revenues in 1998 and will record
$2 million in 1999. The refund covers a period from March 14, 1997 to February
28, 1999. The beginning date is consistent with the timing of Utah legislation
imposing a moratorium on rate changes after the Utah Division of Public
Utilities and the Utah Committee of Consumer Services requested a general rate
case. The $85 million reduction will commence on March 1, 1999. The order also
reduced the Company's authorized rate of return on equity from 12.1% to 10.5%.
The Company has asked the UPSC to reconsider issues in the order involving
approximately $41 million of the $85 million rate decrease. Among these issues
is the method of implementing the April 1998 allocation order. The Company is
not seeking reconsideration of the reduction in its authorized return on equity
to 10.5% nor the changes in the way costs are allocated among the six states
served by the Company.
57
<PAGE>
NOTE 6. SPECIAL CHARGES
In January 1998, the Company announced a plan to reduce its work force in the
United States by approximately 600 positions, or 7% of the work force in the
United States. The Company offered enhanced early retirement to approximately
1,200 employees. The actual net work force reduction from this program was 759
positions, with 981 employees accepting the offer and 222 vacated positions
backfilled. The pretax cost of $113 million ($70 million after-tax, or $0.24 per
share) was recorded in the first quarter of 1998.
In the fourth quarter of 1998, the Company initiated a cost reduction program
that included involuntary employee severance and enhanced early retirement for
employees who met certain age and service criteria and were displaced in
conjunction with the cost reduction initiatives. Approximately 167 employees
were displaced, with 35 of them eligible for the enhanced early retirement, and
the Company recorded a $10 million ($6 million after-tax, or $0.02 per share)
expense in special charges. It is anticipated that these amounts will be paid
out in early 1999.
Below is a summary of the accrual recorded and payments made related to the
work force reduction initiatives described above.
<TABLE>
<CAPTION>
retirement severance
millions of dollars total benefits and other
- --------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C>
Accruals recorded $ 123.4 $ 108.7 $ 14.7
Payments (9.8) - (9.8)
ADDITIONS TO ACCRUED PENSION COSTS:
Termination benefits (110.9) (110.9) -
Net recognized gain 22.3 22.3 -
ADDITIONS TO POSTRETIREMENT BENEFIT COSTS:
Termination benefits (11.0) (11.0) -
Net recognized loss (3.6) (3.6) -
Adjustments 0.5 (1.4) 1.9
-----------------------------------
Ending accrual $ 10.9 $ 4.1 $ 6.8
===================================
</TABLE>
In December 1997, Domestic Electric Operations recorded in operating income
special charges of $170 million ($106 million after-tax, or $0.36 per share).
The pretax special charges included the write off of $87 million of deferred
regulatory pension assets (see Note 5), a $19 million write off of certain
information system assets associated with the Company's decision to proceed with
an installation of SAP enterprise-wide software and $64 million of costs
associated with the write down of assets and acceleration of reclamation costs
due to the early closure of the Glenrock coal mine. The inability of the mine to
remain competitive caused it to be uneconomical to continue to operate under
current and expected market conditions due to increased mining stripping ratios,
reduced coal quality and related costs. As of December 31, 1998, no cash had
been paid out for reclamation. Reclamation is anticipated to begin in 1999.
NOTE 7. SHORT-TERM DEBT AND BORROWING ARRANGEMENTS
The Companies' short-term debt and borrowing arrangements were as follows:
<TABLE>
<CAPTION>
average
December 31 || millions of dollars balance interest rate/a
- ------------------------------------------------------------------------------------
<S> <C> <C>
1998
PacifiCorp $ 253.0 5.2%
Subsidiaries 7.6 5.4
1997
PacifiCorp $ 182.2 6.5%
Subsidiaries 7.0 5.4
/a Computed by dividing the total interest on principal amounts outstanding at
the end of the period by the weighted daily principal amounts outstanding.
</TABLE>
58
<PAGE>
At December 31, 1998, PacifiCorp's commercial paper and bank line borrowings
were supported by revolving credit agreements totaling $700 million. At December
31, 1998, subsidiaries had committed bank revolving credit agreements totaling
$826 million.
The Companies have the intent and ability to support short-term borrowings on
a long-term basis through various revolving credit agreements, the earliest of
which expires in 2002. At December 31, 1998, PacifiCorp had $117 million and
subsidiaries had $414 million of short-term debt classified as long-term. See
Note 8.
NOTE 8. LONG-TERM DEBT
The Company's long-term debt was as follows:
<TABLE>
<CAPTION>
December 31 || millions of dollars 1998 1997
- ----------------------------------------------------------------------------------------------------------
<S> <C> <C>
PACIFICORP
First mortgage and collateral trust bonds
Maturing 1999 through 2003/ 5.9%-9.5% $ 816.4 $ 1,005.6
Maturing 2004 through 2008/ 5.7%-7.9% 1,032.7 632.7
Maturing 2009 through 2013/ 7%-9.2% 328.6 331.6
Maturing 2014 through 2018/ 8.3%-8.7% 98.4 100.9
Maturing 2019 through 2023/ 6.5%-8.5% 341.5 341.5
Maturing 2024 through 2026/ 6.7%-8.6% 120.0 120.0
Guaranty of pollution control revenue bonds
5.6%-5.7% due 2021 through 2023/a 71.2 71.2
Variable rate due 2009 through 2013/a, b 40.7 40.7
Variable rate due 2014 through 2024/a, b 175.8 175.8
Variable rate due 2005 through 2030/b 450.7 450.7
Funds held by trustees (7.4) (9.1)
8.4%-8.6% Junior subordinated debentures due 2025 through 2035 175.8 175.8
Commercial paper/b, d 116.8 120.6
Other 21.9 25.1
--------------------------
Total 3,783.1 3,583.1
Less current maturities 297.6 194.9
--------------------------
Total 3,485.5 3,388.2
--------------------------
SUBSIDIARIES
6.1%-12.0% Notes due through 2020 649.8 264.5
Australian bank bill borrowings and commercial paper/c, d 414.3 756.6
Variable rate notes due through 2000/b 11.6 12.1
4.5%-11% Nonrecourse debt - 160.7
Other - 1.4
--------------------------
Total 1,075.7 1,195.3
Less current maturities 1.9 170.5
--------------------------
Total 1,073.8 1,024.8
--------------------------
Total $ 4,559.3 $ 4,413.0
==========================
/a Secured by pledged first mortgage and collateral trust bonds generally at
the same interest rates, maturity dates and redemption provisions as the
pollution control revenue bonds.
/b Interest rates fluctuate based on various rates, primarily on certificate of
deposit rates, interbank borrowing rates, prime rates or other short-term
market rates.
/c Interest rates fluctuate based on Australian Bank Bill Acceptance Rates. A
revolving loan agreement requires that at least 50% of the borrowings must
be hedged against variations in interest rates. Approximately $414 million
was hedged at December 31, 1998 at an average rate of 7.2% and for an
average life of 5.3 years.
/d The Companies have the ability to support short-term borrowings and current
debt being refinanced on a long-term basis through revolving lines of credit
and, therefore, based upon management's intent, have classified $531 million
of short-term debt as long-term debt.
</TABLE>
59
<PAGE>
First mortgage and collateral trust bonds of the Company may be issued in
amounts limited by Domestic Electric Operations' property, earnings and other
provisions of the mortgage indenture. Approximately $7 billion of the assets of
the Companies secure long-term debt.
The junior subordinated debentures are unsecured obligations of the Company
and are subordinated to the Company's first mortgage and collateral trust bonds,
pollution control revenue bonds, commercial paper, bank debt and any future
senior indebtedness.
The annual maturities of long-term debt and redeemable preferred stock
outstanding are $300 million, $181 million, $387 million, $449 million and $122
million in 1999 through 2003, respectively.
The Company made interest payments, net of capitalized interest, of $444
million, $414 million and $456 million in 1998, 1997 and 1996, respectively.
NOTE 9. GUARANTEED PREFERRED BENEFICIAL INTERESTS IN
COMPANY'S JUNIOR SUBORDINATED DEBENTURES
Wholly owned subsidiary trusts of the Company (the "Trusts") have issued, in
public offerings, redeemable preferred securities ("Preferred Securities")
representing preferred undivided beneficial interests in the assets of the
Trusts, with liquidation amounts of $25 per Preferred Security. The sole assets
of the Trusts are Junior Subordinated Deferrable Interest Debentures of the
Company that bear interest at the same rates as the Preferred Securities to
which they relate, and certain rights under related guarantees by the Company.
Preferred Securities outstanding at December 31 were as follows:
<TABLE>
<CAPTION>
thousands of preferred securities || millions of dollars 1998 1997
- ----------------------------------------------------------------------------------------------------------------
<S> <C> <C>
8,680 8.25% Cumulative Quarterly Income Preferred Securities,
Series A, with Trust assets of $224 million $ 209.9 $ 209.7
5,400 7.70% Trust Preferred Securities, Series B,
with Trust assets of$139 million 130.6 130.7
---------------------
Total $ 340.5 $ 340.4
=====================
</TABLE>
NOTE 10. COMMON AND PREFERRED STOCK
COMMON STOCK At December 31, 1998, there were 26,773,426 authorized but
unissued shares of common stock reserved for issuance under the Dividend
Reinvestment and Stock Purchase Plan and the Employee Savings and Stock
Ownership Plans and for sales to the public. Eligible employees under the
employee plans may direct their pretax elective contributions into the purchase
of the Company's common stock. The Company makes matching contributions, equal
to a percentage of employee contributions, which are invested in the Company's
common stock. Employee contributions eligible for matching contributions are
limited to 6% of compensation.
STOCK OPTION INCENTIVE PLAN During 1997, the Company adopted a Stock Option
Incentive Plan (the "Plan"). Under the terms of the Plan, the exercise price of
any option may not be less that 100% of the fair market value of the common
stock on the date of the grant. Stock options generally become exercisable in
two or three equal installments on each of the first through third anniversaries
of the grant date. The maximum exercise period under the Plan is ten years. In
early 1998, the Company registered 11,500,000 shares of its common stock with
the Securities and Exchange Commission for issuance under the PacifiCorp Stock
Incentive Plan. At December 31, 1998, there were 11,410,839 authorized but
unissued shares available.
60
<PAGE>
The table below summarizes the stock option activity under the Plan.
<TABLE>
<CAPTION>
weighted number
average price of shares
- --------------------------------------------------------------------------------------------
<S> <C> <C>
OUTSTANDING OPTIONS DECEMBER 31, 1996 - -
Granted $ 19.94 1,516,000
Forfeited 19.75 (19,000)
---------
OUTSTANDING OPTIONS DECEMBER 31, 1997 19.94 1,497,000
Granted 23.79 3,469,961
Exercised 19.75 (89,161)
Forfeited 23.03 (807,628)
---------
OUTSTANDING OPTIONS DECEMBER 31, 1998 4,070,172
=========
</TABLE>
At December 31, 1998, 591,201 shares were exercisable with a weighted average
exercise price of $20.18 per share. No options were exercisable as of December
31, 1997. The weighted average life of the options outstanding at December 31,
1998 was nine years.
As permitted by SFAS 123, the Company has elected to account for these
options under APB 25. Accordingly, no compensation expense has been recognized
for these options. Had the Company determined compensation cost based on the
fair value at the grant date for its stock options under SFAS 123, the Company's
net income and earnings per share would have been reduced to the pro forma
amounts below:
<TABLE>
<CAPTION>
for the year || millions of dollars 1998 1997
- ----------------------------------------------------------------------------------------------------
<S> <C> <C>
Net income (loss) as reported $ (36.1) $ 663.7
Pro forma (39.6) 663.2
Earnings (loss) per common share as reported (0.19) 2.16
Pro forma (0.20) 2.16
</TABLE>
The weighted average fair value of options granted during the year was $3.94 and
$2.78 in 1998 and 1997, respectively. The fair value of each option grant was
estimated on the date of grant using the Black-Scholes option-pricing model with
the following assumptions used:
<TABLE>
<CAPTION>
for the year 1998 1997
- ----------------------------------------------------------------------------------------------------
<S> <C> <C>
Dividend yield 5.0% 5.5%
Risk-free interest rate 5.6% 6.8%
Volatility 20% 15%
Expected life of the options (years) 10 10
</TABLE>
61
<PAGE>
PREFERRED STOCK
<TABLE>
<CAPTION>
thousands of shares
- ----------------------------------------------------------------------------------------------------
<S> <C>
At January 1, 1996 8,299
Redemptions and repurchases (2,342)
--------
At December 31, 1996 5,957
Redemptions and repurchases (2,797)
--------
At December 31, 1997 3,160
Redemptions and repurchases -
--------
At December 31, 1998 3,160
========
</TABLE>
Generally, preferred stock is redeemable at stipulated prices plus accrued
dividends, subject to certain restrictions. Upon involuntary liquidation, all
preferred stock is entitled to stated value or a specified preference amount per
share plus accrued dividends. Any premium paid on redemptions of preferred stock
is capitalized, and recovery is sought through future rates.
PREFERRED STOCK OUTSTANDING
<TABLE>
<CAPTION>
thousands of shares || millions of dollars
December 31, 1998 and 1997 || series shares amount
- -----------------------------------------------------------------------------------------------------------------
<S> <C> <C>
Subject to Mandatory Redemption
No Par Serial Preferred, $100 stated value, 6,000 Shares authorized
$7.70 1,000 $ 100.0
7.48 750 75.0
Total 1,750 $ 175.0
-----------------------
Not Subject to Mandatory Redemption
No Par Serial Preferred, $25 stated value
$1.16 193 $ 4.8
1.18 420 10.5
1.28 381 9.5
Serial Preferred, $100 stated value, 3,500 Shares authorized
4.52% 2 0.2
4.56 85 8.5
4.72 70 7.0
5.00 42 4.2
5.40 66 6.6
6.00 6 0.6
7.00 18 1.8
5% Preferred, $100 stated value, 127 Shares authorized and outstanding 127 12.7
-----------------------
1,410 $ 66.4
-----------------------
Total 3,160 $ 241.4
-----------------------
</TABLE>
Mandatory redemption requirements at stated value plus accrued dividends on No
Par Serial Preferred Stock are as follows: the $7.70 series is redeemable in its
entirety on August 15, 2001; and 37,500 shares of the $7.48 series are
redeemable on each June 15 from 2002 through 2006, with all shares outstanding
on June 15, 2007 redeemable on that date. If the Company is in default in its
obligation to make any future redemptions on the $7.48 series, it may not pay
cash dividends on common stock.
62
<PAGE>
NOTE 11. FINANCIAL INSTRUMENTS AND RISK MANAGEMENT
Through the application of its capital structure policies that governs the use
of equity and debt, including duration, maturity and repricing intervals, the
Company seeks to reduce its net income and cash flow exposure to changing
interest and other commodity price risks. The Company utilizes derivative
instruments to modify or eliminate its exposure from adverse movements in
interest and foreign currency rates. The use of these derivative instruments is
governed by the Company's derivative policy and includes as its objective that
interest rates and foreign exchange derivative instruments will be used for
hedging and not for speculation. As such, only those instruments that have a
high correlation with the Company's underlying commodity exposure can be
utilized. The derivative policy also governs energy trading activities and is
generally designed for hedging the Company's existing energy exposures but does
provide for limited speculative activities within defined risk limits.
NOTIONAL AMOUNTS AND CREDIT EXPOSURE OF DERIVATIVES The notional amounts of
derivatives summarized below do not represent amounts exchanged and, therefore,
are not a measure of the exposure of the Company through its use of derivatives.
The amounts exchanged are calculated on the basis of the notional amounts and
other terms of the derivatives, which relate to interest rates, exchange rates
or other indexes.
The Company is exposed to credit-related losses in the event of
nonperformance by counterparties to financial instruments, but it does not
expect any counterparties to fail to meet their obligations given their high
credit rating requirements. The Company's derivative policy provides that
counterparties must satisfy established credit ratings and currently a majority
of the Company's counterparties are rated "A" or better. The credit exposure of
interest rate, foreign exchange and forward contracts is represented by the fair
value of contracts with a positive fair value at the reporting date.
INTEREST RATE RISK MANAGEMENT The Company enters into various types of
interest rate contracts to assist in managing its interest rate risk, as
indicated in the following table:
<TABLE>
<CAPTION>
notional amount
--------------------
December 31 || millions of dollars 1998 1997
- ------------------------------------------------------------------------------------------------------------------
<S> <C> <C>
Interest rate swaps $ 759.4 $ 707.5
Interest rate collars purchased 39.7 42.3
Interest rate futures and forwards 351.4 -
</TABLE>
The Company uses interest rate swaps, collars, futures and forwards to adjust
the characteristics of its liability portfolio, allowing the Company to
establish a mix of fixed or variable interest rates on its outstanding debt
within the Company's overall capital structure guidelines for leverage and
variable interest rate risk.
The use of interest rate collars, futures and forwards has been limited to
use in the Australian Electric Operations. The futures and forwards, when used,
are accounted for as hedges of the Australian bank bill borrowings. Interest
rate collar agreements entitle Australian Electric Operations to receive from
the counterparties the amounts, if any, by which the Australian bank bill
borrowings interest payments exceed 8.75% and Australian Electric Operations
would pay the counterparties if interest payments fall below 6.5%-6.8%.
Under the various interest rate swap agreements, the Company agrees with
other parties to exchange, at specified intervals, the difference between
fixed-rate and variable-rate interest amounts calculated by reference to an
agreed notional principal amount. The following table indicates the
weighted-average interest rates of the swaps. Average variable rates are based
on rates implied in the yield curve at December 31; these may change
significantly, affecting future cash flows. Swap contracts are principally
between one and fifteen years in duration.
<TABLE>
<CAPTION>
December 31 1998 1997
- ------------------------------------------------------------------------------------------------
<S> <C> <C>
PAY-FIXED SWAPS
Average pay rate 7.3% 7.7%
Average receive rate 4.9 6.5
</TABLE>
63
<PAGE>
FOREIGN EXCHANGE RISK MANAGEMENT The Company's principal foreign exchange
exposure relates to its investment in its Australian Electric Operations. The
Company has hedged its exposure through both Australian-dollar denominated bank
borrowings, which hedge approximately 55% to 60% of its total exposure, and
through a series of amortizing currency swaps, which hedge approximately half of
the remaining exposure. In January 1998, Australian Electric Operations issued
$400 million of 6.15% Notes due 2008. At the same time, in order to mitigate
foreign currency exchange risk and consistent with the directives in the
Company's derivative policy, Australian Electric Operations entered into a
series of cross currency swaps in the same amount and for the same duration as
the underlying United States denominated notes.
At December 31, 1998, Holdings held three combined interest rate and currency
swaps that terminate in 2002, with an aggregate notional amount of $240 million
to hedge a portion of its net investment in Powercor to fluctuations in the
Australian dollar. The interest rate portions of these three swaps were
effectively offset in 1997 by the purchase of an overlay swap transaction with
approximately the same terms. The net amounts of these swaps have not had a
significant impact on net income.
At December 31, 1997, Hazelwood Australia, Inc. ("HAI"), an indirect
subsidiary of Holdings, held a foreign currency forward with a notional amount
of $146 million to hedge a portion of its exposure to fluctuations in the
Australian dollar relating to its investment in the Hazelwood power station and
adjacent coal mine. This hedge was closed in January 1998 and HAI received $24
million in cash, as a result of the favorable market rate at the termination
date.
COMMODITY RISK MANAGEMENT The Company has utilized electricity forward
contracts (referred to as "contracts for differences") to hedge exposure to
electricity price risk on anticipated transactions or firm commitments in its
Australian Electric Operations. Under these forward contracts, the Company
receives or makes payment based on a differential between a contracted price and
the actual spot market of electricity. Additionally, electricity futures
contracts are utilized to hedge Domestic Electric Operations' excess or shortage
of net electricity for future months.
At December 31, 1998, Australian Electric Operations had 290 forward
contracts with electricity generation companies on notional quantities amounting
to approximately 34.4 million megawatt hours ("MWh") through the year 2007. The
average fixed price to be paid by Australian Electric Operations was $17.99 per
MWh compared to the average price of similar contracts at December 31, 1998 of
$22.20. At December 31, 1997, Australian Electric Operations had 211 forward
contracts with electricity generation companies on notional quantities amounting
to approximately 35.6 million MWh. The average fixed price to be paid by
Australian Electric Operations was $19.07 per MWh compared to the average price
of similar contracts at December 31, 1997 of $18.66. It is not practicable to
determine the fair value of the forward contracts held by Australian Electric
Operations because of the limited number of transactions and the inactive
trading in the electricity spot market.
The Company had open NYMEX futures contracts as follows:
<TABLE>
<CAPTION>
December 31 1998 1997
- ---------------------------------------------------------------------------------------------------
<S> <C> <C>
OPEN CONTRACTS (NUMBER)
Purchase 215 110
Sell 275 489
NOTIONAL QUANTITIES (MWH)
Purchase 158,200 81,000
Sell 202,400 359,900
FAIR MARKET VALUE (MILLIONS OF DOLLARS)
Purchase $ - $ 0.1
Sell 0.2 (0.7)
</TABLE>
64
<PAGE>
TRADING ACTIVITIES The fair market values of open positions at December 31,
1998 was $(1) million. Such transactions involve delivery of electricity, which
is accounted for as revenue or purchased power expense. At December 31, 1998,
the Company had open purchase positions with a notional amount of approximately
$72.9 million, or 3.0 million MWh, and open sell positions for approximately
$66.3 million, or 2.8 million MWh.
NOTE 12. FAIR VALUE OF FINANCIAL INSTRUMENTS
<TABLE>
<CAPTION>
December 31, 1998 December 31, 1997
---------------------- ----------------------
carrying fair carrying fair
millions of dollars amount value amount value
- ----------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C>
Long-term debt $ 4,835.0 $ 5,127.5 $ 4,753.7 $ 4,905.6
Preferred Securities 340.5 363.9 340.4 355.4
Preferred stock subject to mandatory redemption 175.0 195.7 175.0 194.1
DERIVATIVES RELATING TO
Currency 35.1 35.2 45.3 45.3
Interest (8.5) (65.8) (9.4) (54.3)
</TABLE>
The carrying value of cash and cash equivalents, receivables, payables, accrued
liabilities and short-term borrowings approximates fair value because of the
short-term maturity of these instruments. The fair value of the finance note
receivable approximates its carrying value at December 31, 1998 and 1997.
The fair value of the Company's long-term debt has been estimated by
discounting projected future cash flows, using the current rate at which similar
loans would be made to borrowers with similar credit ratings and for the same
maturities. Current maturities of long-term debt were included. The fair value
of the Preferred Securities was based on closing market prices and the fair
value of redeemable preferred stock was based on bid prices from an investment
bank.
The fair value of interest rate derivatives and currency swaps is the
estimated amount the Company would receive (pay) to terminate the agreements,
taking into account current interest and currency exchange rates and the current
creditworthiness of the agreement counterparties.
NOTE 13. COMMITMENTS AND CONTINGENCIES
The Company is subject to numerous environmental laws including: the Federal
Clean Air Act, as enforced by the Environmental Protection Agency and various
state agencies; the 1990 Clean Air Act Amendments; the Endangered Species Act as
it relates to certain potentially endangered species of salmon; the
Comprehensive Environmental Response, Compensation and Liability Act, relating
to environmental cleanups; along with the Federal Resource Conservation and
Recovery Act and the Clean Water Act relating to water quality. These laws could
potentially impact future operations. For those contingencies identified at
December 31, 1998, principally the Superfund sites where the Company has been or
may be designated as a potentially responsible party and Clean Air Act matters,
future costs associated with the disposition of these matters are not expected
to be material to the Company's consolidated financial statements.
The Company's mining operations are subject to reclamation and closure
requirements. The Company monitors these requirements and periodically revises
its cost estimates to meet existing legal and regulatory requirements of the
various jurisdictions in which it operates. Costs for reclamation are accrued
using the units-of-production method such that estimated final mine reclamation
and closure costs are fully accrued at completion of mining activities, except
where the Company has decided to close a mine. When a mine is closed, the
Company records the estimated cost to complete the mine closure. This is
consistent with industry practices, and the Company believes that it has
adequately provided for its reclamation obligations, assuming ongoing operations
of its mines.
65
<PAGE>
The utility partners who own the 1,340 MW coal-fired Centralia Power Plant in
Washington have hired an investment advisor to pursue the possible sale of the
plant and the adjacent Centralia coal mine. The sale of the plant and adjacent
mine is being considered by the owners, in part, because of emerging
deregulation, competition in the electricity industry and the need for
environmental compliance expenditures at the plant. The Company operates the
plant and owns a 47.5% share. In addition, the Company owns and operates the
adjacent Centralia coal mine. The Company is investigating the effect of a
potential sale on the reclamation costs for the Centralia coal mine. Preliminary
studies indicate that reclamation costs for the Centralia coal mine could be
significantly higher than previous estimates, assuming the mine is closed, with
the Company's portion being 47.5% of the final total amount. At December 31,
1998, the Company had approximately $24 million accrued for its share of the
Centralia mine reclamation costs. The final amount and timing of any charge for
additional reclamation at the mine are dependent upon a number of factors,
including the results of the sale process, completion of the preliminary
reclamation studies at the mine and the reclamation procedure used. The Company
will seek to recover through rates any increase in the reclamation costs for the
mine.
See Note 2, Proposed ScottishPower Merger, for information concerning
termination fees that are payable in certain circumstances if the merger
agreement is terminated.
The Company and its subsidiaries are parties to various legal claims, actions
and complaints, certain of which involve material amounts. Although the Company
is unable to predict with certainty whether or not it will ultimately be
successful in these legal proceedings or, if not, what the impact might be,
management currently believes that disposition of these matters will not have a
materially adverse effect on the Company's consolidated financial statements.
CONSTRUCTION AND OTHER Construction and acquisitions are estimated at $539
million for 1999. As a part of these programs, substantial commitments have been
made.
LEASES The Companies have certain properties under leases with various
expiration dates and renewal options. Rentals on lease renewals are subject to
negotiation. Certain leases provide for options to purchase at fair market
value. The Companies are also committed to pay all taxes, expenses of operation
(other than depreciation) and maintenance applicable to the leased property.
Net rent expense for the years ended December 31, 1998, 1997 and 1996 was $17
million, $15 million and $12 million, respectively.
Future minimum lease payments under noncancelable operating leases are $6
million, $5 million, $5 million, $4 million and $3 million for 1999 through
2003, respectively.
66
<PAGE>
JOINTLY OWNED FACILITIES At December 31, 1998, Domestic Electric Operations'
participation in jointly owned facilities was as follows:
<TABLE>
<CAPTION>
electric construction
operations' plant in accumulated work in
millions of dollars share service depreciation progress
- ---------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C>
Centralia/a 47.5% $ 183.2 $ 115.6 $ 0.5
Jim Bridger Units 1, 2, 3 and 4/a 66.7 811.2 336.6 0.3
Trojan/b 2.5 - - -
Colstrip Units 3 and 4/a 10.0 233.0 83.3 0.3
Hunter Unit 1 93.8 261.5 112.4 5.3
Hunter Unit 2 60.3 198.0 74.9 0.4
Wyodak 80.0 305.4 111.2 0.4
Craig Station Units 1 and 2 19.3 151.4/c 62.0 0.4
Hayden Station Unit 1 24.5 30.6/c 12.3 3.2
Hayden Station Unit 2 12.6 18.1/c 9.1 5.7
Hermiston/d 50.0 156.5 17.2 0.2
Foote Creek/a 78.8 55.7 2.5 -
Other KV lines and substations Various 82.3 10.1 -
/a Includes KV lines and substations.
/b Plant, inventory, fuel and decommissioning costs totaling $22 million
relating to the Trojan Plant were included in regulatory assets-net at
December 31, 1998.
/c Excludes unallocated acquisition adjustments of $110 million at December 31,
1998, that represents for regulatory accounting the excess of the cost of
the acquired interest in the facilities over their original cost net of
accumulated depreciation.
/d Additionally, the Company has contracted to purchase the remaining 50% of
the output of the plant.
</TABLE>
Under the joint agreements, each participating utility is responsible for
financing its share of construction, operating and leasing costs. Domestic
Electric Operations' portion is recorded in its applicable operations,
maintenance and tax accounts.
LONG-TERM WHOLESALE SALES AND PURCHASED POWER CONTRACTS Domestic Electric
Operations manages its energy resource requirements by integrating long-term
firm, short-term and spot market purchases with its own generating resources to
economically dispatch the system and meet commitments for wholesale sales and
retail load growth. The long-term wholesale sales commitments include contracts
with minimum sales requirements of $461 million, $427 million, $328 million,
$317 million and $305 million for 1999 through 2003, respectively. As part of
its energy resource portfolio, Domestic Electric Operations acquires a portion
of its power through long-term purchases and/or exchange agreements which
require minimum fixed payments of $316 million, $310 million, $286 million,
$294 million and $260 million for 1999 through 2003, respectively. The purchase
contracts include agreements with the Bonneville Power Administration, the
Hermiston Plant and a number of cogenerating facilities.
67
<PAGE>
Excluded from the minimum fixed annual payments above are commitments to
purchase power from several hydroelectric projects under long-term arrangements
with public utility districts. These purchases are made on a "cost-of-service"
basis for a stated percentage of project output and for a like percentage of
project annual costs (operating expenses and debt service). These costs are
included in operations expense. Domestic Electric Operations is required to pay
its portion of the debt service, whether or not any power is produced. The
arrangements provide for nonwithdrawable power and the majority also provide for
additional power, withdrawable by the districts upon one to five years' notice.
For 1998, such purchases approximated 2% of energy requirements.
At December 31, 1998, Domestic Electric Operations' share of long-term
arrangements with public utility districts was as follows:
<TABLE>
<CAPTION>
year contract capacity percentage annual
generating facility expires (kW) of output costs/a
- -------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C>
Wanapum 2009 155,444 18.7% $ 5.2
Priest Rapids 2005 109,602 13.9 3.3
Rocky Reach 2011 64,297 5.3 3.0
Wells 2018 59,617 7.7 2.0
--------- -------
Total 388,960 $ 13.5
========= =======
/a Annual costs, in millions of dollars, include debt service of $7.6 million.
</TABLE>
The Company has a 4% interest in the Intermountain Power Project (the
"Project"), located in central Utah. The Company and the city of Los Angeles
have agreed that the City will purchase capacity and energy from Company plants
equal to the Company's 4% entitlement of the Project at a price equivalent to 4%
of the expenses and debt service of the Project.
FUEL CONTRACTS Domestic Electric Operations has take or pay coal and natural
gas contracts which require minimum fixed payments of $108 million, $114
million, $98 million, $99 million and $101 million for 1999 through 2003,
respectively.
NOTE 14. INCOME TAXES
The Company's combined federal and state effective income tax rate from
continuing operations was 35% in 1998, 32% in 1997 and 35% in 1996. The
difference between taxes calculated as if the statutory federal tax rate of 35%
was applied to income from continuing operations before income taxes and the
recorded tax expense is reconciled as follows:
<TABLE>
<CAPTION>
millions of kWh 1998 1997 1996
- -----------------------------------------------------------------------------------------------------
<S> <C> <C> <C>
ENERGY SALES
Powercor area 7,233 7,410 7,519
Outside Powercor area
</TABLE>
<TABLE>
<CAPTION>
for the year || millions of dollars 1998 1997 1996
- -----------------------------------------------------------------------------------------------------
<S> <C> <C> <C>
Computed Federal Income Taxes $ 59.4 $ 120.6 $ 233.4
--------------------------------
INCREASE (REDUCTION) IN TAX RESULTING FROM
Depreciation differences 17.4 14.3 12.8
Investment tax credits (8.8) (8.5) (9.3)
Audit settlement - - 0.5
Affordable housing and alternative fuel credits (5.9) (13.4) (10.6)
Other items capitalized and miscellaneous differences (9.7) (10.7) (8.4)
--------------------------------
Total (7.0) (18.3) (15.0)
--------------------------------
Federal Income Tax 52.4 102.3 218.4
State Income Tax, Net of Federal Income Tax Benefit 6.7 9.5 18.1
--------------------------------
Total Income Tax Expense $ 59.1 $ 111.8 $ 236.5
================================
</TABLE>
68
<PAGE>
The provision for income taxes is summarized as follows:
<TABLE>
<CAPTION>
for the year || millions of dollars 1998 1997 1996
- -----------------------------------------------------------------------------------------------------
<S> <C> <C> <C>
CURRENT
Federal $ 89.1 $ 150.1 $ 186.3
State 17.9 17.2 24.1
--------------------------------
Total 107.0 167.3 210.4
--------------------------------
DEFERRED
Federal (31.5) (44.3) 22.4
State (7.6) (2.7) 4.9
Foreign - - 8.1
--------------------------------
Total (39.1) (47.0) 35.4
--------------------------------
Investment Tax Credits (8.8) (8.5) (9.3)
--------------------------------
Total Income Tax Expense $ 59.1 $ 111.8 $ 236.5
================================
</TABLE>
The tax effects of significant items comprising the Company's net deferred tax
liability were as follows:
<TABLE>
<CAPTION>
December 31 || millions of dollars 1998 1997
- -----------------------------------------------------------------------------------------------------
<S> <C> <C>
DEFERRED TAX LIABILITIES
Property, plant and equipment $ 1,246.0 $ 1,178.8
Regulatory assets 653.7 704.1
Other deferred liabilities 37.2 84.3
----------------------
1,936.9 1,967.2
DEFERRED TAX ASSETS
Regulatory liabilities (50.8) (54.0)
Book reserves not currently deductible for tax (138.4) (56.6)
Foreign net operating loss (28.9) (45.9)
Foreign currency adjustment (53.2) (46.4)
Pension accrual (72.7) (39.9)
Safe harbor lease (31.1) (28.4)
Other deferred assets (19.2) (29.8)
----------------------
(394.3) (301.0)
Net Deferred Tax Liability $ 1,542.6 $ 1,666.2
======================
</TABLE>
The Company has received an Internal Revenue Service ("IRS") examination report
for 1991, 1992 and 1993, proposing adjustments that would increase current taxes
payable by $97 million. The Company filed a protest of many of these proposed
adjustments on December 30, 1998. Discussions with the Appeals Division of the
IRS will commence during 1999.
During 1998, the Company completed its discussions with the Appeals Division
for the protest of the 1989 and 1990 examinations. The Company paid $10 million
in additional tax for these years for agreed issues. The Company will be filing
for relief in the Tax Court with respect to two remaining issues. The additional
tax in dispute for these issues is $4 million.
The Company expects the IRS to commence audit of 1994 through 1997 during
1999.
The Company made income tax payments of $504 million, $134 million and $208
million in 1998, 1997 and 1996, respectively. The significant increase in tax
payments during 1998 was the result of taxes paid on assets sold during 1997,
including PTI.
69
<PAGE>
NOTE 15. EMPLOYMENT BENEFIT PLANS
RETIREMENT PLANS The Companies have pension plans covering substantially all
of their employees. Benefits under the plan in the United States are based on
the employee's years of service and average monthly pay in the 60 consecutive
months of highest pay out of the last 120 months, with adjustments to reflect
benefits estimated to be received from Social Security. Pension costs are funded
annually by no more than the maximum amount of pension expense which can be
deducted for federal income tax purposes. Unfunded prior service costs are
amortized over the remaining service period of employees expected to receive
benefits. At December 31, 1998, plan assets were primarily invested in common
stocks, bonds and United States government obligations.
All permanent employees of Powercor engaged prior to October 4, 1994 are
members of Division B or C of the Superannuation Fund (the "Fund") which
provides defined benefits in the form of pensions (Division B) or lump sums
(Division C). Both defined benefit Funds are closed to new members. Members who
choose to contribute do so at rates of 3% or 6% of eligible salaries. Powercor
employees engaged after October 4, 1994 are members of Division D of the Fund,
which is a defined contribution fund in which members may contribute up to 20%
of eligible salaries. During the year ended December 31, 1998, Powercor made no
contributions to Division B and C funds due to surplus amounts in these funds
and contributed to the Division D Fund at rates ranging from 6%-10% of eligible
salaries.
The net periodic pension cost and significant assumptions are summarized as
follows:
<TABLE>
<CAPTION>
for the year || millions of dollars 1998 1997 1996
- -----------------------------------------------------------------------------------------------------
<S> <C> <C> <C>
Service cost $ 25.6 $ 27.6 $ 31.5
Interest cost 82.0 82.1 78.8
Expected return on plan assets (89.4) (76.7) (65.8)
Amortization of unrecognized net obligation 6.9 7.2 7.2
Recognized prior service cost 3.0 2.2 2.0
Recognized (gain) loss (0.3) 0.1 0.2
Regulatory deferral - - 14.2
---------------------------------
Net periodic pension cost $ 27.8 $ 42.5 $ 68.1
=================================
Discount rate 6.3%-6.8% 6.3%-7% 7.3%-7.5%
Expected long-term rate of return on assets 7.5%-9.3% 7.5%-9.3% 8.5%-9%
Rate of increase in compensation levels 4%-5% 4%-5% 4.5%-6%
</TABLE>
70
<PAGE>
The change in the projected benefit obligation, change in plan assets and funded
status are as follows:
<TABLE>
<CAPTION>
for the year || millions of dollars 1998 1997
- -----------------------------------------------------------------------------------------------------
<S> <C> <C>
CHANGE IN PROJECTED BENEFIT OBLIGATION
Projected benefit obligation - beginning of year $ 1,216.3 $ 1,125.8
Service cost 25.6 27.6
Interest cost 82.0 82.1
Foreign currency exchange rate changes (4.3) (15.2)
Plan participant contributions 1.5 1.2
Plan amendments 11.7 1.6
Curtailment gain (9.0) -
Special termination benefit loss 110.9 -
Actuarial loss 38.2 65.3
Benefits paid (202.7) (72.1)
-----------------------
Projected benefit obligation - end of year $ 1,270.2 $ 1,216.3
=======================
CHANGE IN PLAN ASSETS
Plan assets at fair value - beginning of year $ 1,003.5 $ 871.5
Foreign currency exchange rate changes (4.4) (14.7)
Actual return on plan assets 154.5 148.0
Plan participant contributions 1.5 1.2
Company contributions 96.6 69.6
Benefits paid (202.7) (72.1)
-----------------------
Plan assets at fair value - end of year $ 1,049.0 $ 1,003.5
=======================
RECONCILIATION OF ACCRUED PENSION COST AND TOTAL AMOUNT RECOGNIZED
Funded status of the plan $ (221.2) $ (212.7)
Unrecognized net (gain) loss (5.0) 4.9
Unrecognized prior service cost 22.5 15.2
Unrecognized net transition obligation 67.7 80.0
Accrued pension cost (136.0) (112.6)
-----------------------
Accrued benefit liability (138.5) (118.2)
Intangible asset 2.5 5.6
-----------------------
Accrued pension cost $ (136.0) $ (112.6)
=======================
</TABLE>
EMPLOYEE SAVINGS AND STOCK OWNERSHIP PLAN The Company has an employee savings
and stock ownership plan that qualifies as a tax-deferred arrangement under
Section 401(k), 401(a), 409, 501 and 4975(e)(7) of the Internal Revenue Code.
Participating United States employees may defer up to 16% of their compensation,
subject to certain regulatory limitations. The Company matches a portion of
employee contributions with common stock, vesting that portion over five years.
The Company makes an additional contribution of common stock to qualifying
employees equal to a percentage of the employee's eligible earnings. These
contributions are immediately vested. Company contributions to the savings plan
were $18 million, $20 million and $17 million for the years ended 1998, 1997 and
1996, respectively.
OTHER POSTRETIREMENT BENEFITS Domestic Electric Operations provides health
care and life insurance benefits through various plans for eligible retirees on
a basis substantially similar to those who are active employees. The cost of
postretirement benefits is accrued over the active service period of employees.
The transition obligation represents the unrecognized prior service cost and is
being amortized over a period of 20 years. For those employees retired at
January 1, 1993, the Company funds postretirement benefit expense on a
pay-as-you-go basis and has an unfunded accrued liability of $65 million at
December 31, 1998. For those employees retiring after January 1, 1993, the
Company funds postretirement benefit expense through a combination of funding
vehicles. The Company
71
<PAGE>
funded $27 million and $18 million of postretirement benefits during 1998 and
1997, respectively. These funds are invested in common stocks, bonds and United
States government obligations.
The net periodic postretirement benefit cost and significant assumptions are
summarized as follows:
<TABLE>
<CAPTION>
for the year || millions of dollars 1998 1997 1996
- -----------------------------------------------------------------------------------------------------
<S> <C> <C> <C>
Service cost $ 7.2 $ 7.2 $ 6.9
Interest cost 24.5 21.8 21.8
Expected return on plan assets (17.2) (12.5) (9.1)
Amortization of unrecognized net obligation 13.8 13.9 14.0
Recognized gain (2.0) (2.1) (1.4)
Regulatory deferral 1.9 6.4 3.4
----------------------------------
Net periodic postretirement benefit cost $ 28.2 $ 34.7 $ 35.6
==================================
Discount rate 6.8% 7% 7.5%
Estimated long-term rate of return on assets 9.3% 9.3% 9%
Initial health care cost trend rate - under 65 7.8% 8.3% 8.8%
Initial health care cost trend rate - over 65 7.8% 8.3% 8.4%
Ultimate health care cost trend rate 4.5% 4.5% 4.5%
</TABLE>
The change in the accumulated postretirement benefit obligation, change in plan
assets and funded status are as follows:
<TABLE>
<CAPTION>
for the year || millions of dollars 1998 1997
- -----------------------------------------------------------------------------------------------------
<S> <C> <C>
CHANGE IN ACCUMULATED POSTRETIREMENT BENEFIT OBLIGATION
Accumulated postretirement benefit obligation - beginning of year $ 327.4 $ 316.2
Service cost 7.2 7.2
Interest cost 24.5 21.8
Plan participant contributions 2.8 1.1
Curtailment loss 18.1 -
Special termination benefit loss 11.0 -
Actuarial (gain) loss 22.4 (4.9)
Benefits paid (16.8) (14.0)
---------------------
Accumulated postretirement benefit obligation - end of year $ 396.6 $ 327.4
=====================
CHANGE IN PLAN ASSETS
Plan assets at fair value - beginning of year $ 179.8 $ 139.7
Actual return on plan assets 36.4 26.6
Company contributions 37.9 28.9
Benefits paid (14.0) (12.9)
Other disbursements - (2.5)
---------------------
Plan assets at fair value - end of year $ 240.1 $ 179.8
=====================
RECONCILIATION OF ACCRUED POSTRETIREMENT COSTS AND TOTAL AMOUNT RECOGNIZED
Funded status of the plan $ (156.5) $ (147.6)
Unrecognized net gain (40.7) (64.3)
Unrecognized net transition obligation 191.5 209.3
---------------------
Accrued postretirement benefit cost, before adjustment (5.7) (2.6)
Deferred loss (0.4) -
---------------------
Accrued postretirement benefit cost after adjustment $ (6.1) $ (2.6)
=====================
</TABLE>
The assumed health care cost trend rate gradually decreases over eight years.
The health care cost trend rate assumption has a significant effect on the
amounts reported. Increasing the assumed health care cost trend rate by one
72
<PAGE>
percentage point would have increased the accumulated postretirement benefit
obligation (the "APBO") as of December 31, 1998 by $36 million, and the annual
net periodic postretirement benefit costs by $3 million. Decreasing the assumed
health care cost trend rate by one percentage point would have reduced the APBO
as of December 31, 1998 by $38 million, and the annual net periodic
postretirement benefit costs by $3 million.
POSTEMPLOYMENT BENEFITS Domestic Electric Operations provides certain
postemployment benefits to former employees and their dependents during the
period following employment but before retirement. The costs of these benefits
are accrued as they are incurred. Benefits include salary continuation,
severance benefits, disability benefits and continuation of health care benefits
for terminated and disabled employees and workers compensation benefits. Accrued
costs for postemployment benefits were $8 million and $13 million in 1998 and
1997, respectively.
EARLY RETIREMENT OFFER See Note 6 for details on the early retirement offering
in 1998.
NOTE 16. ACQUISITIONS AND DISPOSITIONS
On November 5, 1998, the Company sold its Montana distribution assets to
Flathead Electric Cooperative, Inc. and received proceeds of $89 million, net of
taxes and customer refunds. The Company returned $4 million of the $8 million
gain to Montana customers.
In October 1998, the Company decided to exit the majority of its other energy
development businesses as a result of its refocus on the western United States
and Australian electricity businesses. These energy development businesses are
generally wholly owned subsidiaries of the Company or subsidiaries in which the
Company has a majority ownership. These businesses are consolidated in the
Company's financial statements and are included in Other Operations. The pretax
loss associated with exiting the energy development businesses was $52 million
($32 million after-tax, or $0.11 per share) and is included in "Write down of
investment in energy development businesses" on the income statement. This loss
consisted of reductions in net intercompany receivables. The remaining values
for these businesses were arrived at using cash flow projections and estimated
market value for fixed assets. Some of these businesses have been exited through
the discontinuance of their operations while others are for sale. The Company
believes that the businesses currently for sale can be exited by the end of
1999. Through September 1998, these businesses recorded pretax losses of $18
million ($13 million after-tax, or $0.04 per share). From October 1, 1998
through December 31, 1998, Holdings recorded a pretax expense of $5 million ($3
million after-tax, or $0.01 per share) relating to these operations.
During May 1998, PFS received approximately $80 million in cash proceeds for
the sale of a majority of its real estate assets, which approximated book value.
On April 15, 1997, Holdings, through a subsidiary, acquired all of the
outstanding shares of common stock of TPC, a natural gas gathering, processing,
storage and marketing company based in Houston, Texas, for approximately $265
million in cash and assumed debt of approximately $140 million. Following
completion of a tender offer, TPC became a wholly owned subsidiary of Holdings
through a cash merger at the same price. During May 1997, TPC retired $131
million of its outstanding long-term debt. This transaction was funded with
capital contributions from PacifiCorp parent.
On December 1, 1997, TPC sold all of the capital stock of three subsidiaries
that hold its natural gas gathering and processing systems for $195 million in
cash, before tax payments of $23 million. No gain or loss was recognized on the
sale. In October 1998, the Company announced its intention to sell the remaining
business of TPC. See Note 4.
On November 5, 1997, Holdings completed the sale of PGC for approximately
$150 million in cash. A pretax gain on the sale of $57 million ($30 million
after-tax, or $0.10 per share) was recognized in the fourth quarter of 1997.
In September 1996, a consortium, known as the Hazelwood Power Partnership,
purchased a 1,600 megawatt, coal-fired generating station and associated coal
mine in Victoria, Australia for approximately $1.9 billion. The consortium
financed the acquisition of the Hazelwood Plant and mine with approximately $858
million in equity contributions from the partners and $1 billion of nonrecourse
borrowings at the partnership level. Holdings, which has a 19.9% interest in the
partnership, financed its $145 million portion of the equity investment and the
associated $12 million advance with long-term borrowings in the United States.
In October 1998, the Company announced its intention to sell its interest in
Hazelwood as a result of its refocus on the western United States and Australian
electricity businesses. Hazelwood is an equity investment included in the
Company's financial statements as part of Australian Electric Operations. The
Company recorded a pretax loss of $28 million ($17 million
73
<PAGE>
after-tax, or $0.06 per share), which is included in "Write down of investment
in energy development businesses" on the income statement, to reduce its
carrying value in the Hazelwood Power Station to estimated net realizable value
less selling costs. This write down was arrived at using cash flow projections.
For the year ended December 31, 1998, Hazelwood recorded a pretax loss of $7
million ($5 million after-tax, or $0.02 per share).
NOTE 17. SEGMENT INFORMATION
The Company operates in two business segments (excluding other and discontinued
operations): Domestic Electric Operations and Australian Electric Operations.
The Company identified the segments based on management responsibility within
the United States and Australia. Domestic Electric Operations includes the
regulated retail and wholesale electric operations in the six western states in
which it operates. Australian Electric Operations includes the deregulated
electric operations in Australia. Other Operations consists of PFS, the western
energy trading activities and other energy development businesses, as well as
the activities of Holdings, including financing costs. None of the businesses
within Other Operations are significant enough for segment treatment.
<TABLE>
<CAPTION>
domestic Australian other
total electric electric discontinued operations &
millions of dollars company operations operations operations eliminations
- -------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C>
1998
Net sales and revenue (all external) $ 5,580.4 $ 4,845.1 $ 614.5 $ - $ 120.8
Depreciation and amortization 451.2 386.6 58.2 - 6.4
Interest expense 371.6 319.1 57.9 - (5.4)
Losses of nonconsolidated affiliates (13.9) - (5.5) - (8.4)
Income tax expense (benefit) 59.1 102.9 7.7 - (51.5)
Extraordinary item - - - - -
Income (loss) from continuing operations 110.6 149.8 13.0 - (52.2)
Loss from discontinued operations (146.7) - - (146.7) -
Identifiable assets 12,988.5 9,834.6 1,660.8 175.0 1,318.1
Investments in nonconsolidated affiliates 114.9 6.1 100.9 - 7.9
Capital spending 667.0 539.0 75.0 - 53.0
1997
Net sales and revenue (all external) $ 4,548.9 $ 3,706.9 $ 716.2 $ - $ 125.8
Depreciation and amortization 466.1 389.1 67.1 - 9.9
Interest expense (benefit) 437.8 319.0 63.5 - 55.3
Losses of nonconsolidated affiliates (12.8) - (2.9) - (9.9)
Income tax expense 111.8 112.0 32.3 - (32.5)
Extraordinary item (16.0) (16.0) - - -
Income (loss) from continuing operations 232.9 188.3 47.9 - (3.3)
Income from discontinued operations 446.8 - - 446.8 -
Identifiable assets 13,627.0 9,862.7 1,786.3 223.4 1,754.6
Investments in nonconsolidated affiliates 166.1 6.1 123.7 - 36.3
Capital spending 714.0 490.0 84.0 - 140.0
1996
Net sales and revenue (all external) $ 3,792.0 $ 2,991.8 $ 658.8 $ - $ 141.4
Depreciation and amortization 423.8 343.4 71.6 - 8.8
Interest expense 415.0 291.8 75.2 - 48.0
Losses of nonconsolidated affiliates (4.1) - (1.3) - (2.8)
Income tax expense 236.5 216.9 18.7 - 0.9
Income from continuing operations 430.3 371.3 30.1 - 28.9
Income from discontinued operations 74.6 - - 74.6 -
Identifiable assets 13,809.0 9,864.0 2,065.0 783.0 1,097.0
Investments in nonconsolidated affiliates 253.9 6.1 145.7 - 102.1
Capital spending 877.0 596.0 225.0 - 56.0
</TABLE>
74
<PAGE>
SELECTED FINANCIAL INFORMATION (UNAUDITED)
<TABLE>
<CAPTION>
for the year || millions of dollars, except per share information 1998 1997 1996 1995 1994
- -----------------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C>
Revenues
Domestic Electric Operations $ 4,845.1 $ 3,706.9 $ 2,991.8 $ 2,646.1 $ 2,686.2
Australian Electric Operations 614.5 716.2 658.8 25.9 -
Other Operations/a 120.8 125.8 141.4 134.8 153.7
----------------------------------------------------------
Total $ 5,580.4 $ 4,548.9 $ 3,792.0 $ 2,806.8 $ 2,839.9
==========================================================
Income (Loss) from Operations
Domestic Electric Operations $ 571.8 $ 601.3 $ 869.8 $ 800.9 $ 819.3
Australian Electric Operations 114.5 150.5 127.4 5.5 -
Other Operations/a (5.5) 58.9 89.1 84.2 38.3
----------------------------------------------------------
Total $ 680.8 $ 810.7 $ 1,086.3 $ 890.6 $ 857.6
==========================================================
Net Income $ (36.1) $ 663.7 $ 504.9 $ 505.0 $ 468.0
==========================================================
Earnings Contribution (Loss)
on Common Stock
Continuing operations
Domestic Electric Operations $ 130.5 $ 165.5 $ 341.5 $ 276.4 $ 339.8
Australian Electric Operations 13.0 54.2 31.9 0.7 -
Other Operations/a (52.2) (9.6) 27.1 86.2 18.0
----------------------------------------------------------
Total 91.3 210.1 400.5 363.3 357.8
Discontinued operations/b (146.7) 446.8 74.6 103.0 70.5
Extraordinary item/c - (16.0) - - -
----------------------------------------------------------
Total $ (55.4) $ 640.9 $ 475.1 $ 466.3 $ 428.3
==========================================================
Earnings (Loss) per Share -
Basic and Diluted
Continuing operations
Domestic Electric Operations $ 0.44 $ 0.56 $ 1.17 $ 0.97 $ 1.20
Australian Electric Operations 0.04 0.18 0.11 - -
Other Operations/a (0.18) (0.03) 0.09 0.31 0.06
-----------------------------------------------------
Total 0.30 0.71 1.37 1.28 1.26
Discontinued operations/b (0.49) 1.50 0.25 0.36 0.25
Extraordinary item/c - (0.05) - - -
----------------------------------------------------------
Total $ (0.19) $ 2.16 $ 1.62 $ 1.64 $ 1.51
==========================================================
Cash Dividends Declared per Common Share $ 1.08 $ 1.08 $ 1.08 $ 1.08 $ 1.08
==========================================================
Market Price per Common Share $ 21 1/16 $ 27 5/16 $ 20 1/2 $ 21 1/8 $ 18 1/8
==========================================================
Capitalization
Short-term debt $ 560 $ 555 $ 903 $ 1,132 $ 513
Long-term debt 4,559 4,413 4,829 4,509 3,391
Preferred securities of Trusts 341 340 210 - -
Redeemable preferred stock 175 175 178 219 219
Preferred stock 66 66 136 312 367
Common equity 3,957 4,321 4,032 3,633 3,460
----------------------------------------------------------
Total $ 9,658 $ 9,870 $ 10,288 $ 9,805 $ 7,950
==========================================================
Total Assets $ 12,989 $ 13,627 $ 13,809 $ 13,167 $ 11,000
==========================================================
Total Employees 9,120 10,087 10,118 10,418 10,083
==========================================================
/a Other Operations includes the operations of PFS, PGC, the western United
States wholesale trading activities, as well as the activities of Holdings,
including financing costs, and elimination entries.
/b Discontinued operations includes the Company's interest in PTI, TPC and the
eastern energy trading business of PPM.
/c Extraordinary item includes a regulatory asset impairment pertaining to
generation resources that are allocable to operations in California and
Montana.
</TABLE>
75
<PAGE>
DOMESTIC ELECTRIC OPERATIONS (UNAUDITED)
<TABLE>
<CAPTION>
5-year
1998 to 1997 compound
for the year percentage annual
millions of dollars, except as noted 1998 1997 1996 1995 1994 comparison growth
- -----------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C> <C>
Revenues
Residential $ 806.6 $ 814.0 $ 801.4 $ 739.7 $ 746.0 (1)% 2%
Commercial 653.5 640.9 623.3 576.9 571.7 2 4
Industrial 705.5 709.9 719.3 708.8 742.3 (1) -
Other 30.2 31.7 32.5 29.7 30.7 (5) -
---------------------------------------------------------
Retail sales 2,195.8 2,196.5 2,176.5 2,055.1 2,090.7 - 2
Wholesale sales and
market trading 2,583.6 1,428.0 738.8 520.0 532.7 81 39
Other 65.7 82.4 76.5 71.0 62.8 (20) 11
---------------------------------------------------------
Total 4,845.1 3,706.9 2,991.8 2,646.1 2,686.2 31 14
---------------------------------------------------------
Expenses
Fuel 477.6 454.2 443.0 431.6 483.0 5 1
Purchased power 2,497.0 1,296.5 618.7 386.7 394.5 93 47
Other operations 292.4 292.0 276.9 273.7 263.8 - 2
Maintenance 164.9 178.0 167.3 168.4 174.5 (7) (1)
Administrative and general 233.9 227.8 176.3 160.5 142.7 3 11
Depreciation and amortization 386.6 389.1 343.4 320.4 301.6 (1) 7
Taxes, other than income taxes 97.5 97.6 96.4 103.9 106.8 - (1)
Special charges 123.4 170.4 - - - (28) -
---------------------------------------------------------
Total 4,273.3 3,105.6 2,122.0 1,845.2 1,866.9 38 19
---------------------------------------------------------
Income from Operations 571.8 601.3 869.8 800.9 819.3 (5) (6)
Interest expense 319.1 319.0 291.8 311.9 264.3 - 3
Interest capitalized (14.5) (12.2) (11.4) (14.9) (14.5) 19 1
Other (income) expense - net 14.5 (5.8) 1.2 (25.3) (30.2) * *
Income tax expense 102.9 112.0 216.9 214.1 220.2 (8) (11)
---------------------------------------------------------
Net Income 149.8 188.3 371.3 315.1 379.5 (20) (16)
Preferred Dividend
Requirement 19.3 22.8 29.8 38.7 39.7 (16) (13)
---------------------------------------------------------
Earnings Contribution/a $ 130.5 $ 165.5 $ 341.5 $ 276.4 $ 339.8 (21) (17)
=========================================================
Identifiable assets $ 9,835 $ 9,863 $ 9,864 $ 9,599 $ 9,372 - 2
Capital spending $ 539 $ 490 $ 596 $ 455 $ 638 10 (3)
* Not a meaningful number.
/a Does not reflect elimination of interest on intercompany borrowing
arrangements and includes income taxes on a separate-company basis.
</TABLE>
76
<PAGE>
DOMESTIC ELECTRIC OPERATIONS STATISTICS (UNAUDITED)
<TABLE>
<CAPTION>
5-year
1998 to 1997 compound
millions of dollars, except as noted 1998 1997 1996 1995 1994 comparison growth
- -----------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C> <C>
Energy Sales (millions of kWh)
Residential 12,969 12,902 12,819 12,030 12,127 1% 1%
Commercial 12,299 11,868 11,497 10,797 10,645 4 4
Industrial 20,966 20,674 20,332 19,748 20,306 1 1
Other 651 705 640 592 623 (8) 2
---------------------------------------------------------
Retail sales 46,885 46,149 45,288 43,167 43,701 2 2
Wholesale sales and
market trading 94,077 59,143 29,665 16,376 15,625 59 44
---------------------------------------------------------
Total 140,962 105,292 74,953 59,543 59,326 34 20
=========================================================
Energy Source (%)
Coal 51 43 60 74 79 19 (8)
Hydroelectric 6 5 7 7 5 20 -
Other 2 2 1 2 2 - 15
Purchase and
exchange contracts 41 50 32 17 14 (18) 21
=========================================================
Number of Retail
Customers (thousands)
Residential 1,255 1,228 1,194 1,167 1,147 2 2
Commercial 174 170 167 160 158 2 2
Industrial 36 36 37 35 34 - 2
Other 5 4 4 4 3 25 5
---------------------------------------------------------
Total 1,470 1,438 1,402 1,366 1,342 2 2
=========================================================
Residential Customers
Average annual usage (kWh) 10,443 10,644 10,866 10,395 10,646 (2) (1)
Average annual revenue
per customer (Dollars) 650 672 679 639 655 (1) -
Revenue per kWh (Cents) 6.2 6.3 6.3 6.1 6.1 - -
Miles of Line
Transmission 15,000 15,000 14,900 14,900 14,900 - -
Distribution
- - overhead 45,000 45,000 45,000 44,900 44,800 - -
- - underground 10,000 10,000 9,600 9,100 8,800 - 4
System Peak Demand
(Megawatts)
Net system load/a
- - summer 7,666 7,110 7,257 6,855 7,151 8 3
- - winter 7,909 7,403 7,615 7,030 7,174 7 2
Total Firm Load
- - summer/b 11,629 10,871 10,572 8,899 8,830 7 7
- - winter 12,301 10,830 10,775 8,904 8,903 14 7
System Capability
(Megawatts)/c
- - summer 12,632 12,343 12,115 10,224 10,020 2 5
- - winter 13,427 12,618 12,160 10,994 10,391 6 6
/a Excludes off-system sales.
/b Includes firm off-system sales.
/c Generating capability and firm purchases at time of firm peak.
</TABLE>
77
<PAGE>
AUSTRALIAN ELECTRIC OPERATIONS (UNAUDITED)/a
<TABLE>
<CAPTION>
1998 to 1997
Percentage
for the year || millions of dollars, except as noted 1998 1997 1996 1995 Comparison/b
- ---------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C>
Revenues
Powercor area $ 437.8 $ 538.6 $ 583.6 $ 25.4 (19)%
Outside Powercor area
Victoria 79.1 98.7 45.0 - (20)
New South Wales 71.6 46.0 - - 56
Australian Capital Territory 0.6 - - - *
Queensland 0.3 - - - *
-----------------------------------------------
Energy sales 589.4 683.3 628.6 25.4 (14)
Other 25.1 32.9 30.2 0.5 (24)
-----------------------------------------------
Total 614.5 716.2 658.8 25.9 (14)
-----------------------------------------------
Expenses
Purchased power 255.0 308.5 305.1 11.0 (17)
Other operations 108.7 100.7 62.3 2.5 8
Maintenance 31.4 33.3 50.0 0.3 (6)
Administrative and general 45.7 54.9 40.7 3.4 (17)
Depreciation and amortization 58.2 67.1 71.6 3.1 (13)
Taxes, other than income taxes 1.0 1.2 1.7 0.1 (17)
-----------------------------------------------
Total 500.0 565.7 531.4 20.4 (12)
-----------------------------------------------
Income from Operations 114.5 150.5 127.4 5.5 (24)
Interest expense 57.9 63.5 75.2 3.8 (9)
Equity in losses of Hazelwood/a 5.5 2.9 1.3 - 90
Other (income) expense - net 30.4 (2.4) 0.3 0.5 *
Income tax expense 7.7 32.3 18.7 0.5 (76)
-----------------------------------------------
Earnings Contribution $ 13.0 $ 54.2 $ 31.9 $ 0.7 (76)
===============================================
Identifiable assets $ 1,661 $ 1,786 $ 2,065 $ 1,751 (7)
Capital spending $ 75 $ 84 $ 225 $ 1,591 (11)
Energy Sales (millions of kWh)
Powercor area 7,233 7,410 7,519 362 (2)
Outside Powercor area
Victoria 2,396 2,262 791 - 6
New South Wales 2,241 1,372 - - 63
Australian Capital Territory 12 - - - *
Queensland 6 - - - *
-----------------------------------------------
Total 11,888 11,044 8,310 362 8
===============================================
Number of Customers
Powercor area 562,394 553,457 546,247 540,125 2
Outside Powercor area
Victoria 1,102 622 567 - 77
New South Wales 1,189 811 - - 47
Australian Capital Territory 23 - - - *
Queensland 4 - - - *
-----------------------------------------------
Total 564,712 554,890 546,814 540,125 2
===============================================
* Not a meaningful number.
/a Results of operations are included since dates of acquisition, December 12,
1995 for Powercor and September 13, 1996 for Hazelwood.
/b Comparison done without consideration of the changes in currency exchange
rates.
</TABLE>
78
<PAGE>
OTHER OPERATIONS (UNAUDITED)
Other Operations include the operations of PFS, PGC, the western United States
energy trading activities and several start-up-phase ventures, as well as the
activities of Holdings, including financing costs. PGC assets were sold on
November 5, 1997 and a majority of the real estate assets of PFS were sold
during May 1998.
<TABLE>
<CAPTION>
for the year || millions of dollars 1998 1997 1996 1995 1994
- ------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C>
Earnings Contribution
PFS $ 8.1 $ 30.2 $ 34.1 $ 30.4 $ 3.0
PGC - 10.4 7.8 5.6 8.5
Tax settlement - - - 32.2 -
Holdings and other (60.3) (50.2) (14.8) 18.0 6.5
--------------------------------------------------------
Total $ (52.2) $ (9.6) $ 27.1 $ 86.2 $ 18.0
========================================================
Identifiable Assets
PFS 422 692 708 697 731
PGC - - 123 116 113
Holdings and other/a 896 1,063 266 246 252
--------------------------------------------------------
Total $ 1,318 $ 1,755 $ 1,097 $ 1,059 $ 1,096
========================================================
Capital spending $ 53 $ 140 $ 56 $ 44 $ 13
/a During 1997, the Company generated $1.8 billion of cash, excluding $370
million of current income tax liabilities, from sales of assets with
carrying values of $822 million. See Notes 4 and 16.
</TABLE>
79
<PAGE>
SUPPLEMENTAL INFORMATION
<TABLE>
<CAPTION>
quarterly financial data (unaudited)
quarter ended || millions of dollars, except per share amounts March 31 June 30 September 30 December 31
- -----------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C>
1998
Revenues $ 1,260.2 $ 1,202.2 $ 1,918.2 $ 1,199.8
Income from operations 140.2 194.3 190.4 155.9
Income (loss) from continuing operations (14.6) 78.9 34.6 11.7
Discontinued operations (0.5) (38.1) (122.2) 14.1
Net income (loss) (15.1) 40.8 (87.6) 25.8
Earnings (loss) on common stock (19.9) 36.0 (92.4) 20.9
Earnings (loss) per common share:
Continuing operations (0.07) 0.25 0.10 0.02
Discontinued operations - (0.13) (0.41) 0.05
Common dividends declared and paid per share 0.27 0.27 0.27 0.27
Common stock price per share (NYSE)
High 26 3/4 24 7/16 23 1/8 22 5/16
Low 22 13/16 21 13/16 18 7/8 18 3/4
1997
Revenues $ 1,002.8 $ 998.1 $ 1,207.7 $ 1,340.3
Income from operations 262.8 223.2 279.1 45.6
Income from continuing operations 103.6 77.7 46.3 5.3
Discontinued operations 17.4 17.1 27.7 384.6
Extraordinary item - - - (16.0)
Net income 121.0 94.8 74.0 373.9
Earnings on common stock 114.9 88.7 68.2 369.1
Earnings (loss) per common share:
Continuing operations 0.33 0.24 0.14 -
Discontinued operations 0.06 0.06 0.09 1.29
Extraordinary item - - - (0.05)
Common dividends declared and paid per share 0.27 0.2 0.27 0.27
Common stock price per share (NYSE)
High 21 3/4 22 3/8 23 3/8 27 5/16
Low 20 1/8 19 1/4 20 9/16 21 7/16
</TABLE>
A significant portion of the operations are of a seasonal nature. Previously
reported quarterly information has been revised to reflect certain
reclassifications. These reclassifications had no effect on previously reported
consolidated net income.
In the first quarter of 1998, the Company recorded an after-tax charge of $54
million, or $0.18 per share, relating to the write off of TEG transaction costs
and $70 million, or $0.24 per share, relating to the early retirement offer. See
Notes 3 and 6.
In the third quarter 1998, the Company recorded an after-tax charge of $119
million, or $0.40 per share, relating to the provision for losses anticipated in
the disposition of PPM and TPC. In addition, the Company recorded an after-tax
charge of $32 million, or $0.11 per share, relating to the provision for losses
anticipated in the disposition of the Company's other energy businesses. See
Notes 4 and 16.
In the fourth quarter of 1998, the Company recorded an after-tax adjustment
of $23 million, or $0.08 per share, relating to the Utah rate case, $13 million,
or $0.04 per share, relating to ScottishPower merger costs, $17 million, or
$0.06 per share, relating to the write down of its investment in Hazelwood and
$14 million, or $0.05 per share, of income relating to revised losses for
discontinued operations due to the pending sale of TPC for $133 million plus a
working capital adjustment at closing. See Notes 2, 4, 5 and 16.
In the fourth quarter of 1997, the Company recorded after-tax amounts as
follows: asset sales gains of $395 million, or $1.33 per share, special charges
of $106 million, or $0.36 per share, and an extraordinary charge of $16 million,
or $0.05 per share. See Notes 4, 5 and 15.
See Note 4 for information regarding discontinued operations.
On March 1, 1999, there were 105,133 common shareholders of record.
80
<PAGE>
PACIFICORP OFFICERS
Keith R. McKennon, 65 Donald N. Furman, 42
Chairman, President and Vice President, Transmission
Chief Executive Officer 1994
1990 (Year joined the company)
Thomas J. Imeson, 48
Richard T. O'Brien, 44 Vice President, Public Affairs
Executive Vice President and and Communications
Chief Operating Officer 1985
1983
Craig N. Longfield, 53
John A. Bohling, 55 Vice President,
Senior Vice President Corporate Development and
1966 Investment Analysis
1989
William C. Brauer, 60
Senior Vice President, Lenore M. Martin, 53
Power Supply Corporate Secretary
1975 1986
Paul G. Lorenzini, 56 Timothy E. Meier, 46
Senior Vice President, Vice President,
PacifiCorp Chairman and Chief Chief Information Officer
Executive Officer, 1997
Powercor Australia Limited
1987 William E. Peressini, 42
Vice President and Treasurer
Daniel L. Spalding, 45 1984
Senior Vice President
1981 Michael J. Pittman, 46
Vice President, Human Resources
Dennis P. Steinberg, 52 1979
Senior Vice President
1978 Brian D. Sickels, 53
Vice President
Dan R. Baker, 49 1984
Vice President, Mining
1977 A. Richard Walje, 47
Vice President, Distribution
Donald A. Bloodworth, 42 1986
Vice President,
Business Systems Integration Ernest E. Wessman, 51
1983 Vice President, Business Centers
1979
Barry G. Cunningham, 54
Vice President, Generation Richard D. Westerberg, 49
1977 Vice President,
Customer Operations
Robert R. Dalley, 44 1978
Controller and
Chief Accounting Officer
1978
Anne E. Eakin, 48
Vice President, Regulation
1981
81
<PAGE>
<TABLE>
<CAPTION>
PACIFICORP BOARD OF DIRECTORS
name W. Charles C. Todd Conover, Keith R. Robert G. Verl R. Topham, Nancy
Armstrong, 54 59 McKennon, 65 Miller, 55 64 Wilgenbusch, 51
- ---------------- ------------------ ------------------ ----------------- ------------------ ------------------ ------------------
<S> <C> <C> <C> <C> <C> <C>
title Consultant, Managing Chairman, Vice Chairman Retired Senior President,
Former Chairman Director, President and and Chief Vice President Marylhurst
and Chief Starmont Chief Executive Executive and General University,
Executive Asset Officer, Officer, Fred Counsel, Marylhurst,
Officer, Bank of Management, PacifiCorp, Meyer, Inc., PacifiCorp, Oregon
America, LLC, San Portland, Portland, Salt Lake
Oregon, East Francisco Oregon Oregon City, Utah
Sound, Washington California
- ---------------- ------------------ ------------------ ----------------- ------------------ ------------------ ------------------
year elected 1996 1991 1990 1994 1994 1986
- ---------------- ------------------ ------------------ ----------------- ------------------ ------------------ ------------------
82
<PAGE>
name Kathryn Braun Nolan E. Karras, Alan K. Simpson, Don M. Wheeler*, Peter I. Wold,
Lewis, 47 54 67 70 51
- ---------------- ------------------ ------------------ ----------------- ------------------ ------------------
title Retired, Former Investment Former U.S. Chairman and Partner,
President and Advisor, Senator, Chief Wold Oil & Gas
Chief Operating The Karras Cody, Executive Officer, Company,
Officer, Personal Company, Roy, Wyoming CM Equipment Casper,
Storage Division Utah Company, Salt Wyoming
Western Digital Lake City, Utah
Corporation
Irving,
California
- ---------------- ------------------ ------------------ ----------------- ------------------ ------------------
year elected 1994 1993 1997 1989 1995
- ---------------- ------------------ ------------------ ----------------- ------------------ ------------------
</TABLE>
83
<PAGE>
PACIFICORP INVESTOR INFORMATION
STOCK EXCHANGE LISTINGS
PacifiCorp's common stock is listed on the New York Stock Exchange and the
Pacific Stock Exchange under the symbol PPW. The company has three other
securities which are listed and traded on the New York Stock Exchange.
issue symbol
- -----------------------------------------
8.375% Quarterly Income
Debt Securities PCQ
8.55% Quarterly Income
Debt Securities PCX
7.70% Trust Preferred
Securities, Series B PPW B Pfd
Daily quotes on the common stock and other listed securities can be obtained by
checking the New York Stock Exchange composite transactions listed in local
newspapers. The company's first mortgage bonds and most preferred stock series
are infrequently traded in the over-the-counter market.
INVESTOR RELATIONS
Financial analysts, stockbrokers, interested investors and financial media
desiring information about PacifiCorp should contact Investor Relations at (503)
813-7220.
SHAREHOLDER SERVICES AND INFORMATION
For questions regarding PacifiCorp stock ownership, Shareholder Services may be
reached from all U.S. long distance call locations at (800) 233-5453.
Portland-area callers can dial 813-7000. The toll-free telephone number is
answered between 7 a.m. and 5 p.m. Pacific Time Monday-Thursday, and 7 a.m. to 4
p.m. on Friday.
Shareholders' written correspondence may be submitted to:
PacifiCorp Shareholder Services
P.O. Box 14740
Portland, Oregon 97293-0740
TRANSFER AGENT
PacifiCorp maintains shareholder records and acts as Transfer Agent and
Registrar for the company's common and preferred stock issues.
DIVIDEND REINVESTMENT AND STOCK PURCHASE
PacifiCorp's dividend reinvestment plan allows interested investors to purchase
common shares directly from the company, with an initial minimum investment of
$250. The plan is also a convenient way for existing shareholders to increase
their investment in the company, by reinvesting all or a portion of their
quarterly dividends to acquire additional shares of common stock. Plan
participants may make optional cash purchases ($25 minimum each investment and
$100,000 maximum per year) of common stock as frequently as twice per month.
Shareholders wishing to terminate their plan account may sell these shares
through the company, provided their plan balance is less than 100 shares. If
not, a stock certificate may be requested in lieu of a sale. For a plan
prospectus, enrollment form or other information, please call or write the
Shareholder Services Department at the numbers listed above.
BONDHOLDER INFORMATION
Direct inquires concerning lost bonds, interest payments, changes of address and
other matters relating to ownership to:
Chase Manhattan Bank
Corporate Trust Services - Communications
1201 Main Street - 17 OMP
Dallas, Texas 75202
General inquiries: (800) 648-8380
Form 1099 and tax inquires: (800) 298-6805
ANNUAL MEETING
The 1999 Annual Meeting of PacifiCorp Shareholders takes place:
Thursday, June 17, 1999
1:30 p.m. Mountain Daylight Time
Salt Lake Hilton Hotel
150 West 500 South
Salt Lake City, Utah
FORM 10-K
A copy of the company's 1998 10-k, filed with the Securities and Exchange
Commission, may be obtained by contacting Investor Relations at the corporate
headquarters address. It is also available via PacifiCorp's web site through an
Internet link to the SEC EDGAR Database.
DIVIDEND PAYMENT
Dividends on the company's common and preferred stock in 1999 are expected to be
paid on or about:
February 16 May 17
August 16 November 15
CORPORATE ADDRESSES
PACIFICORP
Corporate Headquarters
825 NE Multnomah Street, 20th floor
Portland, Oregon 97232-4116
(503) 813-5000
POWERCOR AUSTRALIA LIMITED
Head Office
40 Market Street
South Melbourne
Victoria, Australia
3005 03-9679-4444 (within Australia)
011-613-9679-4444 (from U.S.)
INTERNET ADDRESS
http://www.pacificorp.com
COUNSEL
Stoel Rives LLP
INDEPENDENT AUDITORS
Deloitte & Touche LLP
84
<PAGE>
[Additional Proxy Soliciting Materials]
---------------------------------------
Understanding the Merger Proxy Process
PacifiCorp shareholders - and that includes most employees - are being reminded
by the Company's proxy solicitor, Innisfree M & A, Inc., to return their proxy
cards. These cards have been mailed by Innisfree to homes at least twice in
packets of information about the pending merger with ScottishPower. Innisfree is
an independent third party handling the proxy voting process.
Reminders - including possible telephone calls - will continue for those who
have not yet returned their proxy. All votes are important because approval of
the merger requires a favorable vote of both a majority of the Company's common
shares outstanding as well as a majority of the Company's preferred stock. If
returned by mail, the proxy cards need to be sent soon so that Innisfree will
have time to process them prior to the June 17 PacifiCorp annual meeting in Salt
Lake City. Proxies can also be submitted in person at the annual meeting.
The proxies are tabulated by computer and individual votes are confidential.
PacifiCorp and ScottishPower will receive just the final tally from Innisfree.
