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SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
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FORM 10-K/A
AMENDMENT NO. 1
(MARK ONE)
/X/ ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
FOR THE FISCAL YEAR ENDED DECEMBER 31, 1998
OR
/ / TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
FOR THE TRANSITION PERIOD FROM ________________ TO ________________
COMMISSION FILE NUMBER 1-5152
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PACIFICORP
(Exact name of registrant as specified in its charter)
STATE OF OREGON 93-0246090
(State or other jurisdiction (I.R.S. Employer Identification
of incorporation or organization) No.)
825 N.E. MULTNOMAH, PORTLAND, OREGON 97232
(Address of principal executive offices) (Zip Code)
Registrant's telephone number, including area code: (503) 813-5000
Securities registered pursuant to section 12(b) of the Act:
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NAME OF EACH EXCHANGE
TITLE OF EACH CLASS ON WHICH REGISTERED
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<S> <C>
Common Stock............................................................................... New York Stock Exchange
Pacific Stock Exchange
8 3/8% Quarterly Income Debt Securities (Junior Subordinated Deferrable Interest
Debentures, Series A).................................................................... New York Stock Exchange
8.55% Quarterly Income Debt Securities (Junior Subordinated Deferrable Interest Debentures,
Series B)................................................................................ New York Stock Exchange
8 1/4% Cumulative Quarterly Income Preferred Securities, Series A, of PacifiCorp Capital
I........................................................................................ New York Stock Exchange
7.70% Cumulative Quarterly Income Preferred Securities, Series B, of PacifiCorp Capital
II....................................................................................... New York Stock Exchange
</TABLE>
Securities registered pursuant to Section 12(g) of the Act:
TITLE OF EACH CLASS
------------------------------
5% Preferred Stock (Cumulative; $100 Stated Value)
Serial Preferred Stock (Cumulative; $100 Stated Value)
No Par Serial Preferred Stock (Cumulative; Various Stated Values)
Indicate by check mark whether the Registrant (1) has filed all reports
required to be filed by Section 13 or 15(d) of the Securities Exchange Act of
1934 during the preceding 12 months (or for such shorter period that the
Registrant was required to file such reports), and (2) has been subject to such
filing requirements for the past 90 days. YES /X/ NO / /
Indicate by check mark if disclosure of delinquent filers pursuant to Item
405 of Regulation S-K is not contained herein, and will not be contained, to the
best of Registrant's knowledge, in definitive proxy or information statements
incorporated by reference in Part III of this Form 10-K or any amendment to this
Form 10-K. /X/
On February 1, 1999, the aggregate market value of the shares of voting and
nonvoting common equity of the Registrant held by nonaffiliates was
approximately $6.5 billion.
As of March 1, 1999, there were 297,331,433 shares of the Registrant's
common stock outstanding.
DOCUMENTS INCORPORATED BY REFERENCE
None
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TABLE OF CONTENTS
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PAGE
NO.
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Definitions......................................................................................................... ii
Part I
Item 1. Business................................................................................... 1
The Organization........................................................................... 1
Domestic Electric Operations............................................................... 2
Australian Electric Operations............................................................. 12
Other Operations........................................................................... 18
Discontinued Operations.................................................................... 18
Employees.................................................................................. 18
Item 2. Properties................................................................................. 19
Item 3. Legal Proceedings.......................................................................... 21
Item 4. Submission of Matters to a Vote of Security Holders........................................ 22
Item 4A. Executive Officers of the Registrant....................................................... 22
Part II
Item 5. Market for Registrant's Common Equity and Related Stockholder Matters...................... 23
Item 6. Selected Financial Data.................................................................... 23
Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations...... 23
Item 7A. Quantitative and Qualitative Disclosures about Market Risk................................. 51
Item 8. Financial Statements and Supplementary Data................................................ 51
Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure....... 96
Part III
Item 10. Directors and Executive Officers of the Registrant......................................... 96
Item 11. Executive Compensation..................................................................... 97
Item 12. Security Ownership of Certain Beneficial Owners and Management............................. 110
Item 13. Certain Relationships and Related Transactions............................................. 110
Part IV
Item 14. Exhibits, Financial Statement Schedules and Reports on Form 8-K............................ 111
Signatures.......................................................................................................... 114
Appendices
Statements of Computation of Ratio of Earnings to Fixed Charges
Statements of Computation of Ratio of Earnings to Combined
Fixed Charges and Preferred Stock Dividends
Subsidiaries of the Company
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DEFINITIONS
When the following terms are used in the text they will have the meanings
indicated:
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<CAPTION>
TERM MEANING
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BPA.................................... Bonneville Power Administration
Company................................ PacifiCorp and its subsidiaries
FERC................................... Federal Energy Regulatory Commission
Hazelwood.............................. Hazelwood Power Partnership, a 19.9% indirectly owned investment of
Holdings
Holdings............................... PacifiCorp Group Holdings Company, a wholly owned subsidiary of the
Company and its wholly owned subsidiary, PacifiCorp International
Group Holdings Company
PGC.................................... Pacific Generation Company, a wholly owned subsidiary of Holdings until
its sale in November 1997, and its subsidiaries
PFS.................................... PacifiCorp Financial Services, Inc., a wholly owned subsidiary of
Holdings, and its subsidiaries
PacifiCorp............................. PacifiCorp, an Oregon corporation
Pacific Power.......................... Pacific Power & Light Company, the assumed business name of the Company
under which it conducts a portion of its retail electric operations
PPM.................................... PacifiCorp Power Marketing, Inc., a wholly owned subsidiary of Holdings
PTI.................................... Pacific Telecom, Inc., a wholly owned subsidiary of Holdings until its
sale in December 1997, and its subsidiaries
Powercor............................... Powercor Australia Limited, an indirect, wholly owned subsidiary of
Holdings, and its immediate parent companies, PacifiCorp Australia
Holdings Pty Ltd and PacifiCorp Australia LLC
TPC.................................... TPC Corporation, a wholly owned subsidiary of Holdings, and its
subsidiaries
Utah Power............................. Utah Power & Light Company, the assumed business name of the Company
under which it conducts a portion of its retail electric operations
</TABLE>
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PART I
ITEM 1. BUSINESS
THE ORGANIZATION
The Company is an electricity company in the United States and Australia. In
the United States, the Company conducts its retail electric utility business as
Pacific Power and Utah Power, and engages in power production and sales on a
wholesale basis under the name PacifiCorp. Holdings, a wholly owned subsidiary
of the Company, holds the stock of subsidiaries conducting businesses not
regulated as domestic electric utilities. Holdings indirectly owns 100% of
Powercor, the largest of the five electric distribution companies in Victoria,
Australia.
The Company's strategic business plan is to focus on its electricity
businesses in the western United States and Australia. As part of its strategic
business plan, the Company will sell its other domestic and international
businesses, and terminate all of its business development activities outside of
the United States and Australia. Holdings continues to liquidate portions of the
loan, leasing, real estate and affordable housing investment portfolio of PFS.
PFS presently expects to retain only its tax-advantaged investments in leveraged
lease assets and limit its pursuit of tax-advantaged investment opportunities.
See "DISCONTINUED OPERATIONS" and "OTHER OPERATIONS."
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, 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 commissions is subject to a finding that the transaction is in the
public interest. Hearings on the merger have been scheduled for July and August
1999 by the Utah, Oregon, Wyoming and Idaho Commissions. The parties have
received early termination of the waiting period under the provisions of the
Hart-Scott-Rodino Antitrust Improvement
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Act. Both companies expect to have shareholder meetings in mid-1999 requesting
shareholder approval of the merger.
See ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS and Note 2, Proposed ScottishPower Merger, of Notes to
Consolidated Financial Statements under ITEM 8.
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, 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 higher price and, on April 30, 1998, the Company announced
that it would not increase its offer for TEG.
For the year ended December 31, 1998, 87% of the Company's revenues from
operations were derived from Domestic Electric Operations, Australian Electric
Operations contributed 11% and Other Operations contributed 2%. Note 17 of Notes
to Consolidated Financial Statements, included under ITEM 8, contains
information with respect to the revenue and income from operations contributed
by each of the Company's industry segments for the past three years and the
identifiable assets attributable to each segment at the end of each of those
years.
From time to time, the Company may issue forward-looking statements that
involve a number of risks and uncertainties. The following factors are among the
factors that could cause actual results to differ materially from the
forward-looking statements: utility commission practices; regional, national 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.
The Company's common stock (symbol PPW) is traded on the New York and
Pacific Stock Exchanges. The Company's 8 3/8% Quarterly Income Debt Securities
(Junior Subordinated Deferrable Interest Debentures, Series A) and 8.55%
Quarterly Income Debt Securities (Junior Subordinated Deferrable Interest
Debentures, Series B) are traded on the New York Stock Exchange. The 8 1/4%
Cumulative Quarterly Income Preferred Securities (Series A Preferred Securities)
of PacifiCorp Capital I, a wholly owned subsidiary trust, and the 7.70% Trust
Preferred Securities (Series B Preferred Securities) of PacifiCorp Capital II, a
wholly owned subsidiary trust, are also traded on the New York Stock Exchange.
DOMESTIC ELECTRIC OPERATIONS
The Company conducts its domestic retail electric utility operations as
Pacific Power and Utah Power, and engages in wholesale electric transactions
under the name PacifiCorp. Pacific Power and Utah Power provide electric service
within their respective service territories. Power production, wholesale sales,
fuel supply and administrative functions are managed on a coordinated basis.
SERVICE AREA
The Company serves 1.5 million retail customers in service territories
aggregating about 135,800 square miles in portions of six western states: Utah,
Oregon, Wyoming, Washington, Idaho, and California. In addition, prior to the
November 1998 sale of its Montana distribution assets to Flathead Electric
Cooperative, Inc., the Company served 35,000 retail electric customers in
Montana. The Company's service area contains diversified industrial and
agricultural economies. Principal industrial customers include oil and gas
extraction, lumber and wood products, paper and allied products, chemicals,
primary
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metals, mining companies, high technology, and agribusiness. Agricultural
products include potatoes, hay, grain and livestock.
The geographical distribution of the Company's retail electric operating
revenues for the year ended December 31, 1998 was Utah, 38%; Oregon, 33%;
Wyoming, 12%; Washington, 8%; Idaho, 6%; California, 2%; and Montana, 1%.
CUSTOMERS
Electric utility revenues and energy sales, by class of customer, for the
three years ended December 31, 1998 were as follows:
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<CAPTION>
1998 1997 1996
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Operating Revenues (Dollars in millions):
Residential............................................. $ 806.6 17% $ 814.0 22% $ 801.4 27%
Commercial.............................................. 653.5 14 640.9 18 623.3 21
Industrial.............................................. 705.5 15 709.9 20 719.3 25
Government, Municipal and Other......................... 30.2 1 31.7 1 32.5 1
---------- --- ---------- --- --------- ---
Total Retail Sales.................................... 2,195.8 47 2,196.5 61 2,176.5 74
Wholesale Sales and Market Trading...................... 2,583.6 53 1,428.0 39 738.8 26
---------- --- ---------- --- --------- ---
Total Energy Sales.................................... 4,779.4 100% 3,624.5 100% 2,915.3 100%
--- --- ---
--- --- ---
Other Revenues.......................................... 65.7 82.4 76.5
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Total Operating Revenues.............................. $ 4,845.1 $ 3,706.9 $ 2,991.8
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Kilowatt-hours Sold (kWh in millions):
Residential............................................. 12,969 9% 12,902 12% 12,819 17%
Commercial.............................................. 12,299 9 11,868 11 11,497 15
Industrial.............................................. 20,966 15 20,674 20 20,332 27
Government, Municipal and Other......................... 651 -- 705 1 640 1
---------- --- ---------- --- --------- ---
Total Retail Sales.................................... 46,885 33 46,149 44 45,288 60
Wholesale Sales and Market Trading...................... 94,077 67 59,143 56 29,665 40
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Total kWh Sold........................................ 140,962 100% 105,292 100% 74,953 100%
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</TABLE>
The Company's service territory has complementary seasonal load patterns. In
the western sector, customer demand peaks in the winter months due to space
heating requirements. In the eastern sector, customer demand peaks in the summer
when irrigation and cooling systems are heavily used. Many factors affect per
customer consumption of electricity. For residential customers, within a given
year, weather conditions are the dominant cause of usage variations from normal
seasonal patterns. However, the price of electricity is also considered a
significant factor.
During 1998, no single retail customer accounted for more than 1.7% of the
Company's retail utility revenues and the 20 largest retail customers accounted
for 13.9% of total retail electric revenues.
COMPETITION
During 1998, Domestic Electric Operations continued to operate its
electricity distribution and retail sales business as a regulated monopoly
throughout most of its franchise service territories. However, Domestic Electric
Operations is facing increasing competition, principally as a result of industry
restructuring, deregulation and increased marketing by alternative energy
suppliers. In addition, many large industrial customers have the option to build
their own generation or cogeneration facilities or to use
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alternative energy sources, such as natural gas. These competitive pressures
enable these customers to negotiate lower prices through special tariffs or
contracts.
Beginning in April 1998, California retail electric energy sales have been
subject to open market competition. The Company's provision of tariffed services
in California will continue to be regulated while any competitive sales of
electricity will be unregulated. In addition to California, the other states in
the Company's service territory have enacted legislation or initiated studies of
retail competition or are considering retail competition as part of industry
restructuring. Most of these states are involved in multi-year studies of the
impacts of competition in the electric industry, resulting in a slower move
towards competition than was originally anticipated by the Company. See
"Regulation." The Company supports increased customer choice only if it takes
place under terms and conditions that are equitable to all involved. The Company
will support direct access and other restructuring initiatives only when the
terms are fair to all customers, the Company and its shareholders.
Competition has transformed the electric utility industry at the wholesale
level. The Energy Policy Act, passed in 1992, opened wholesale competition to
energy brokers, independent power producers and power marketers. In 1996, the
FERC ordered all investor-owned utilities to allow others access to their
transmission systems for wholesale power sales. This access must be provided at
the same price and terms the utilities would apply to their own wholesale
customers. Competition is also influenced by availability and price of alternate
energy sources and the general demand for electrical power.
The Company has formulated strategies to meet these new challenges. The
Company is marketing power supply services to other utilities in the western
United States, including dispatch assistance, daily system load monitoring,
backup power, power storage and power marketing, and services to retail
customers that encourage efficient use of energy. Effective January 1, 1998, the
California Public Utilities Commission ("CPUC") adopted rules regulating the
nontariffed sale of energy and energy products and services by utilities and
their affiliates. The Company has decided to refrain from marketing products and
services to retail customers in California but intends to remain active in the
wholesale business selling to utilities in California and marketers elsewhere in
the western United States.
In July 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, including fixing prices, 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.
CURRENT POWER AND FUEL SUPPLY
The Company's generating facilities are interconnected through its own
transmission lines or by contract through the lines of others. Substantially all
generating facilities and reservoirs located within the Pacific Northwest are
managed on a coordinated basis to obtain maximum load carrying capability and
efficiency.
The Company's transmission system connects with other utilities in the
Pacific Northwest having low-cost hydroelectric generation and with utilities in
California and the southwestern United States having higher-cost, fossil-fuel
generation. The transmission system is available for common use consistent with
regulatory requirements. In periods of favorable hydroelectric generation
conditions, the Company utilizes lower-cost hydroelectric power to supply a
greater portion of its load and attempts to sell its displaced higher-cost
thermal generation to other utilities. In periods of less favorable
hydroelectric generation conditions, the Company seeks to sell its excess
thermal generation to utilities that are more
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dependent on hydroelectric generation than the Company. During the winter, the
Company is able to purchase power from utilities in the southwestern United
States, either for its own peak requirements or for resale to other Pacific
Northwest utilities. During the summer, the Company is able to sell excess power
to utilities in the southwestern United States to assist them in meeting their
peak requirements. See "Wholesale Marketing and Purchased Power."
The Company owns or has interests in generating plants with an aggregate
nameplate rating of 9,001 MW and plant net capability of 8,445 MW. See "ITEM 2.
PROPERTIES." With its present generating facilities, under average water
conditions, the Company expects that approximately 5% of its energy requirements
for 1999 will be supplied by its hydroelectric plants and 59% by its thermal
plants. The balance of 36% is expected to be obtained under long-term purchase
contracts, interchange and other purchase arrangements. During 1998,
approximately 6% and 53% of the Company's energy requirements were supplied by
its hydroelectric and thermal generation plants, respectively, and the remaining
41% by purchased power.
The Company currently purchases 1,100 MW of firm capacity annually from BPA
pursuant to a long-term agreement. The purchase amount declines to 925 MW
annually beginning in July 2000, declining again to 750 MW annually in July 2003
and continuing through August 2011. The Company's current annual payment under
this agreement is $74 million. The agreement provides for the amount of the
payment to decline proportionately as the amount of power purchased declines and
also to change at the rate of change of BPA's average system cost. The next
change to BPA's average system cost is expected to occur in 2001 and will be
determined by BPA in future rate proceedings.
Under the requirements of the Public Utility Regulatory Policies Act of
1978, the Company purchases the output of qualifying facilities constructed and
operated by entities that are not public utilities. During 1998, the Company
purchased an average of 98 MW from qualifying facilities, compared to an average
of 114 MW in 1997. See Note 13 of Notes to the Consolidated Financial Statements
under ITEM 8 for additional details relating to the Company's purchase of power
under long-term arrangements.
The Company plans and manages its capacity and energy resources based on
critical water conditions. Under critical or better water conditions in the
Pacific Northwest, the Company believes that it has adequate reserve generation
capacity for its requirements. The Company's historical total firm peak load
(including both retail and firm wholesale sales) of 10,871 MW occurred on August
22, 1997, and its historical on-system firm peak load of 7,909 MW occurred on
December 21, 1998.
WHOLESALE MARKETING AND PURCHASED POWER
Wholesale sales of power contribute significantly to total revenues. The
Company's wholesale sales complement its retail business and enhance the
efficient use of its generating capacity. In 1998, the Company's wholesale
marketing revenues increased 81% and its wholesale energy volume sold increased
59% over the prior year, accounting for 67% of its total energy sales and 53% of
its total energy revenues. This rate of increase is expected to decline in 1999
due to a reduced focus on short-term wholesale sales.
In addition to its base of thermal and hydroelectric generation assets, the
Company utilizes a mix of long-term and short-term firm power purchases and
nonfirm purchases to meet its load obligations and to make sales to other
utilities. Long-term firm power purchases supplied 9% of the Company's total
energy requirements in 1998. Short-term firm and nonfirm power purchases
supplied 32% of the Company's total energy requirements in 1998.
During October 1998, the Company decided to dispose of its energy trading
business in the eastern United States (see "DISCONTINUED OPERATIONS"). The
Company amended its FERC tariff and PPM assumed the energy trading business in
the western United States at substantially reduced levels from that previously
conducted by Domestic Electric Operations. Certain regulatory constraints,
however, preclude this business from utilizing the Company's utility assets. In
addition, the business intends to add assets in the western United States to
support its marketing and trading activity.
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PROPOSED ASSET ADDITIONS AND DISPOSITIONS
In accordance with the Company's long-range integrated resource planning
process, the Company considers various future demand and supply options for
providing customers with reliable, low-cost energy services. See "Projected
Demand."
The Klamath Cogeneration Project is a 500 MW natural gas-fired power plant
to be constructed near Klamath Falls, Oregon. The City of Klamath Falls will own
the plant and the Company's energy trading subsidiary will be responsible for
management and operations. In addition, the energy trading subsidiary will
purchase 200 MW of output from the plant for resale to third parties and market
on behalf of the City the remaining output to municipal and commercial buyers in
the Pacific Northwest and northern California. Proceeds from revenue bonds
issued by the City of Klamath Falls will be used to finance the project.
Construction is expected to begin in early summer 1999 with commercial operation
by mid-2001.
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 is being considered by
the owners, in part, because of emerging deregulation, competition in the
electricity industry and the need for environmental compliance expenditures as
discussed under "Environmental Issues." 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 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.
PROJECTED DEMAND
The Company continues to benefit from positive economic conditions in
several portions of its service territory and retail kilowatt-hour ("kWh") sales
for the Company have experienced compound annual growth of 2.0% since 1993.
However, the downturn in international economic conditions, particularly in the
Far East and Japan have negatively impacted the Company's service territories in
the Pacific Northwest and many of the industries the Company serves. The Company
has a long history of price stability, or as in Utah, significant price
reductions. While the pursuit of price increases is not taken lightly by the
Company, it will pursue such increases in jurisdictions where it does not earn
an appropriate rate of return and will continue to seek operating efficiencies
in every area of business to retain its low-cost status in the industry.
For the period 1999 to 2002, the average annual growth in retail kWh sales
in the Company's franchise service territories is estimated to be about 2.1%.
During this period, the Company may lose energy sales to other suppliers in
connection with deregulation of the electric industry. As the electric industry
evolves toward deregulation, the Company also expects to have opportunities to
gain market share in areas outside its franchise service territories. The
Company's actual results will be determined by a variety of factors, including
the outcome of deregulation in the electric industry, economic and demographic
growth, competition and the effectiveness of energy efficiency programs.
The Company's base of existing resources, in combination with actions
outlined in its integrated resource plan, are expected to be sufficient to meet
load growth expectations through 2012. Actions outlined in the Company's
integrated resource plan include promoting efficiency improvements by customers
(demand-side management), efficiency improvements to existing generation,
transmission and distribution systems, and other cost-effective resource
acquisition opportunities that meet the future needs of the Company, including
renewable resources.
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ENVIRONMENTAL ISSUES
Federal, state and local authorities regulate many of the Company's
activities pursuant to laws designed to restore, protect and enhance the quality
of the environment. These laws have increased the cost of providing electric
service. The Company is unable to predict what impact, if any, changes in
environmental laws and regulations may have on the Company's future operations
and capital expenditure requirements.
Air Quality. The Company's operations, principally its fossil fuel-fired
electric generating plants, are subject to regulation under the Federal Clean
Air Act, individual state clean air requirements and in some cases local air
authority requirements. The primary air pollutants of concern are sulfur dioxide
("SO(2)"), nitrogen oxides ("NO(x)"), particulate matter (currently PM(10)) and
opacities. In addition, visibility requirements impact the coal-burning plants.
Although not presently regulated, emissions of carbon dioxide ("CO(2)") and
mercury from coal-burning facilities generally are of increasing public concern.
Pollutants--Emission controls, low sulfur coal, plant operating practices
and continuous emissions monitoring are all utilized to enable coal-burning
plants to comply with opacity, visibility and other air quality requirements.
All of the Company's coal-burning plants, burn low sulfur coal and are equipped
with controls to limit emissions of particulate matter. Many of the Company's
coal-burning plants representing the majority of its installed capacity, have
been equipped with controls which reduce the quantity of SO(2) emissions. The
SO(2) emission allowances awarded to the Company under the Federal Clean Air
Act, and those allowances expected to be awarded annually in the future, are
sufficient to enable the Company to meet its current and future requirements,
with the exception of the years 2006-2008 when the Company may need to acquire a
relatively small number of additional allowances depending upon the outcome of
the pending sale of the Centralia Plant and other contingencies. In addition,
the Company has taken advantage of opportunities to sell SO(2) allowances to
other entities. The Company recorded sales of surplus SO(2) allowances of $11.5
million in 1998 and $21 million in 1997 and of surplus NO(x) offsets of $0.5
million in 1998. Except for the years 2006-2008, the Company may have
approximately 30,000 to 48,000 tons of surplus SO(2) emission allowances
available for sale each year until 2028.
Visibility--Various federal and state agencies, as well as private groups,
have raised concerns about perceived visibility degradation in some areas which
are in proximity to some of the Company's coal-burning plants. Numerous
visibility studies, including the Grand Canyon Visibility Transport Commission
study, have been completed or are in the process of completion near Company
coal-burning plants in Colorado, Utah, Washington and Wyoming. To date, no
additional emission control requirements have resulted directly from these
studies, although the potential exists for significant additional control
requirements if visibility degradation in the study areas is reasonably
attributed to the Company's coal-burning plants. The United States Environmental
Protection Agency (the "EPA") also has proposed new regulations addressing
regional haze. These proposed regulations have the potential to impose
significant new control requirements on certain of the Company's older
coal-burning plants that are not otherwise subject to strict SO(2) emission
limits.
Climate Change--CO(2) emissions are the subject of growing world-wide
discussion and action in the context of global warming, but such emissions are
not currently regulated. All of the Company's coal-burning plants emit CO(2). In
late 1997, the United States and other parties to the United Nations Framework
Convention on Climate Change adopted the Kyoto Protocol regarding the control
and reduction of so-called greenhouse gas emissions (including CO(2)). The
United States signed the protocol in November 1998, but the United States
Congress has not yet ratified it. The Kyoto Protocol, if ultimately ratified,
has the potential to impose significant new costs and operational restrictions
on the Company's coal-burning plants.
Mercury--The Company's coal-burning plants, along with all other major
coal-burning plants in the United States, are participating in an effort to
gather additional information about mercury emissions pursuant to a request
issued by the EPA. Based in part on this effort, the EPA will decide whether and
how to regulate mercury emissions from coal-burning plants. If passed, new
mercury emission requirements
7
<PAGE>
have the potential to impose significant new control and operational constraints
on the Company's coal-burning plants.
Air Operating Permits--During 1998, the Company received Title V Air
Operating Permits for most of its coal and natural gas-fired power plants. Title
V permits that were not received during 1998 are expected to be issued during
1999. A citizen group has challenged the issuance of the operating permits for
the Company's Naughton and Jim Bridger power plants, but the EPA has not yet
acted on that challenge. The Company believes that it currently has all required
permits and management systems in place to assure compliance with operating
permit requirements.
Enforcement--In addition to general regulation, the Company is subject to
ongoing enforcement action by regulatory agencies and private citizens regarding
compliance with air quality requirements. A federal lawsuit filed in 1996 by the
Sierra Club against the owners, including the Company, of units one and two of
the Craig Generating Station alleged, among other things, violations of opacity
requirements. The lawsuit seeks civil monetary penalties and an injunction. See
"ITEM 3. LEGAL PROCEEDINGS."
The Company-operated Centralia plant, in which the Company owns a 47.5%
interest, has been the subject of a series of lawsuits and regulatory agency
actions regarding emissions and visibility issues. In February 1998, the
Southwest Washington Air Pollution Control Authority ("SWAPCA") issued a revised
order requiring the Centralia plant to meet new SO(2), NO(x), particulate matter
and carbon monoxide emission limits in 2002. These new limits resulted from the
application of the Reasonably Available Control Technology ("RACT") process as
mandated by SWAPCA and the State of Washington air quality requirements. The new
emission limits will require significant reduction of SO(2) and NO(x) emissions.
Compliance with the new limits will require the Centralia plant to install two
scrubbers and low NO(x) burners at a projected cost of $240 million. A private
citizen has appealed the SWAPCA decision asserting that it is not stringent
enough. An appeal hearing was held in late January 1999 with the Pollution
Control Hearings Board, which has taken the matter under advisement. A ruling is
expected in the spring of 1999, but it is not known at this time whether the
appeal process will impact the schedule or budget for implementing the SWAPCA
order. In addition, the Northwest Environmental Advocates, an environmental
citizen group, filed a federal lawsuit against SWAPCA, the State of Washington
and the EPA alleging failure to enforce visibility requirements throughout
Washington, including requirements relating to the Centralia plant. Portions of
that suit relating to the Centralia plant appear to be resolved, but a final
settlement has not been reached. See additional discussion of Centralia Plant
under "Proposed Asset Additions and Dispositions."
Electromagnetic Fields. A number of studies have examined the possibility
of adverse health effects from electromagnetic fields ("EMF"), without
conclusive results. Certain states and cities have enacted regulations to limit
the strength of magnetic fields at the edge of transmission line rights-of-way.
Other than in California, none of the state agencies with jurisdiction over the
Company's operations has adopted formal rules or programs with respect to EMF or
EMF considerations in the siting of electric facilities. The CPUC has issued an
interim order requiring utilities to implement no-cost or low-cost mitigation
steps in the design of new facilities. It is uncertain whether the Company's
operations may be adversely affected in other ways as a result of EMF concerns.
Endangered Species. Protection of the habitat of endangered and threatened
species makes it difficult and more costly to perform some of the core
activities of the Company, including the siting, construction and operation of
new transmission and distribution facilities, as well as generating plants. In
addition, endangered species issues impact the relicensing of existing
hydroelectric generating projects, generally raising the price the Company must
pay to purchase wholesale power from hydroelectric facilities owned by others
and increasing the costs of operating the Company's own hydroelectric resources.
Environmental Cleanups. Under the Federal Comprehensive Environmental
Response, Compensation and Liability Act and similar state statutes, entities
that disposed of or arranged for the disposal of hazardous substances may be
liable for cleanup of the contaminated property. In addition, the current or
8
<PAGE>
former owners or operators of affected sites also may be liable. The Company has
been identified as a potentially responsible party in connection with a number
of cleanup sites because of current or past ownership or operation of the
property or because the Company sent hazardous waste or other hazardous
substances to the property in the past. The Company has completed several
cleanup actions and is actively participating in investigations and remedial
actions at other sites. The costs associated with those actions are not expected
to be material to the Company's consolidated financial results.
Water Quality. The Federal Clean Water Act and individual state clean water
regulations require a permit for the discharge of waste water, including storm
water runoff from the power plants and coal storage areas, into surface waters.
Also, permits may be required in some cases for discharges into ground waters.
The Company believes that it currently has all required permits and management
systems in place to assure compliance with permit requirements.
REGULATION
The Company is subject to the jurisdiction of public utility regulatory
authorities of each of the states in which it conducts retail electric
operations as to prices, services, accounting, issuance of securities and other
matters. Commissioners are appointed by the individual state's governor for
varying terms. In the states where the Company has operations, the Company
considers the overall quality of the regulatory commissions having jurisdiction
over the Company to be about average in their treatment of the rate applications
of utilities. The Company is a "licensee" and a "public utility" as those terms
are used in the Federal Power Act and is, therefore, subject to regulation by
the FERC as to accounting policies and practices, certain prices and other
matters. Most of the Company's hydroelectric plants are licensed as major
projects under the Federal Power Act and certain of these projects are licensed
under the Oregon Hydroelectric Act.
On December 6, 1998, the Company and ScottishPower agreed to combine the two
companies. Filings relating to the merger are pending with the FERC and state
regulators in Oregon, Utah, Wyoming, Idaho and Washington. In California, the
companies have filed for an exemption from approval requirements. The approval
of the merger is currently the highest regulatory priority for the Company. As a
result, 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 the proposed merger. The Company will, however,
continue to seek price changes that result from existing mechanisms such as
Alternate Forms of Regulation ("AFOR"), systems benefit charges or price
indices.
The Company is currently in the process of relicensing or preparing to
relicense 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 about 93% of the Company's total hydroelectric
nameplate capacity and about 12% of its total generating 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. See
"Environmental Issues--Endangered Species." 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. In addition, the Company may
refuse to accept renewed licenses for certain projects if the terms of renewal
would make the projects uneconomical to operate, and the Company is considering
removal of certain project facilities as part of the licensing settlement
process.
During 1998, the Company filed new depreciation rates with the respective
regulatory commissions in the states of Oregon, Utah and Wyoming based upon a
depreciation study. The impact of the proposed changes in depreciation are
intended to be incorporated into the next general rate case in each state. The
study indicated annual depreciation expense would be increased by approximately
$77 million using the depreciation rates proposed in the study. The increase in
depreciation expense is primarily due to revisions of the estimated costs of
removal for steam production and distribution plant.
A summary of regulatory and legislative developments in the states where the
Company conducts its distribution and retail electric operations is set forth
below.
9
<PAGE>
Utah. During 1997, the Utah Public Service Commission ("UPSC") held
hearings on the method to be used in allocating common generation, transmission
and corporate related costs among the Company's jurisdictions. Under an order
issued in April 1998, differences in allocations associated with the 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
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.
On March 4, 1997, the Utah legislature passed a bill creating a legislative
task force to study restructuring issues. The task force began studying the
issue in 1997. The 1998 Utah legislature passed a resolution stating that
electric industry restructuring is to the long-term benefit of the citizens of
Utah. The task force asked the UPSC to perform a series of studies on electric
industry restructuring and report back to the task force. On June 1, 1998 the
UPSC provided a report to the task force which recommended three stages of
implementation once the decision to restructure is made. The first stage would
identify definitions and classifications and services to be unbundled. The
second stage would be a formal determination of the cost of service for
unbundled services. The third stage would be to analyze market structure and
institute rules and guidelines to promote and sustain effective competition. The
Company expects discussion will continue concerning the future direction of the
electric industry and restructuring legislation in Utah. No restructuring
legislation is anticipated by the Company in the 1999 legislative session.
Oregon. The Oregon Public Utility Commission (the "OPUC") and the Company
have agreed to an AFOR for the Company's Oregon distribution business. The AFOR
allows for price increases based on changes in the producer price index less a
productivity adjustment in 1998, 1999 and 2000. The price increases have 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.
In March 1998, the OPUC approved the Company's proposal for a customer
choice pilot program. The program allowed approximately 30,000 residential and
small commercial customers to select from a portfolio of pricing options offered
by the Company. Approximately 6% of the eligible customers chose to participate
in the pilot, which will continue through June 1999. The pilot program also
included direct access competitive choice options for schools and large
industrial customers throughout the state. Due
10
<PAGE>
primarily to high electricity market prices, no customers have chosen another
supplier to date. Customers may choose to participate through September 1999.
The Company participated in a restructuring docket which was initiated by
Portland General Electric Company. In that proceeding, the Company joined with
other parties in a coalition (the Oregon Intervenor's Coalition, or OIC) to
propose a structure for customer choice, should customer choice be adopted in
Oregon. Under the OIC proposal, large electricity customers would be allowed
direct access while small electricity customers would initially be granted
customer choice.
Wyoming. During 1998, a Wyoming legislative committee held hearings on
electric industry restructuring issues. The committee heard public comment
representing a variety of interests, including investor-owned utilities,
electric cooperatives, organized labor, large electricity customers, small
electricity customers, municipalities, and the Wyoming Public Service
Commission. The Company does not anticipate that restructuring legislation will
be introduced in the 1999 Wyoming legislative session. The Company expects,
however, that discussion will continue concerning the future direction of the
electric industry and restructuring legislation in Wyoming.
Washington. The 1998 Washington legislature passed two bills calling for
studies relating to the electric industry. The first study examined costs,
rates, consumer protection and reliability issues. The second study investigated
methods for unbundling electric utility costs. Both reports were completed by
state agencies and were provided to the Washington legislature in December of
1998.
Idaho. During 1998, the Idaho Public Utility Commission ("IPUC") conducted
rate component unbundling cases for each of the three electric utilities
providing services in the state, including the Company. The scope of these
investigations was limited to the separation of the cost components of the
current bundled tariff rates that customers pay. Stranded costs and other
restructuring issues were not addressed in these proceedings. These cases were
concluded with no action taken by the IPUC. No restructuring legislation was
enacted in 1998 by the Idaho legislature. The Company expects, however, that
discussions will continue concerning the future direction of the electric
industry and restructuring legislation in Idaho.
California. In July 1998, the Company announced its intention to sell its
California service territory electric distribution assets. The Company currently
has approximately 41,400 customers in California. Discussions are ongoing with
potential purchasers. In December 1997, the CPUC 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.
Montana. In November 1998, the sale of the Company's Montana electric
distribution facilities (with a small amount of transmission facilities) to
Flathead Electric Cooperative, Inc. was approved by the MPSC with a negotiated
net gain of $4 million to be allocated to the Company's Montana ratepayers. The
transaction did not include the sale of the Company's Montana generation
facilities or the majority of its transmission system in that state. Prior to
the sale, the Company served approximately 35,000 customers in Montana,
primarily in Flathead and Lincoln counties.
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.
11
<PAGE>
CONSTRUCTION PROGRAM
The following table shows actual construction costs for 1998 and the
Company's estimated construction costs for 1999 through 2001, including costs of
acquiring demand-side resources. The estimates of construction costs for 1999
through 2001 are subject to continuing review and appropriate revision by the
Company.
<TABLE>
<CAPTION>
ESTIMATED
ACTUAL -------------------------------
TYPE OF FACILITY 1998 1999 2000 2001
- -------------------------------------------------------------- ----------- --------- --------- ---------
(DOLLARS IN MILLIONS)
<S> <C> <C> <C> <C>
Distribution.................................................. $ 191 $ 168 $ 180 $ 180
Production.................................................... 138 120 87 113
Mining........................................................ 34 31 33 52
Transmission.................................................. 31 50 51 51
Other......................................................... 145 110 63 66
----- --------- --------- ---------
Total....................................................... $ 539 $ 479 $ 414 $ 462
----- --------- --------- ---------
----- --------- --------- ---------
</TABLE>
AUSTRALIAN ELECTRIC OPERATIONS
POWERCOR
GENERAL
Powercor, an indirect, wholly owned subsidiary of Holdings, is the largest
electricity distribution company ("Distribution Company") in Victoria,
Australia, based on sales volume, revenues, geographic scope and number of
customers. Powercor's principal business segments are its Distribution Business
and its Supply Business. The Distribution Business consists of the distribution
of electricity to approximately 560,000 customers within Powercor's distribution
area, covering from the western suburbs of Melbourne to central and western
Victoria. The Supply Business consists of the purchase of electricity from
generators and the sale of such electricity to customers in Powercor's
distribution service area and other parts of Victoria, New South Wales ("NSW")
and the Australian Capital Territory ("ACT"). Powercor's distribution service
area covers approximately 57,900 square miles (64% of the total area of
Victoria), has a population of approximately 1.5 million (32% of Victoria's
population) and accounts for 26% of Victoria's Gross State Product. In 1998,
Victoria accounted for approximately 25% of Australia's total population,
approximately 34% of Australia's manufacturing industry output and approximately
29% of Australia's Gross Domestic Product, although it represents only
approximately 3% of the total area of Australia.
DISTRIBUTION BUSINESS
Powercor's Distribution Business consists of the ownership, management and
operation of the electricity distribution and subtransmission network in its
distribution service area. The primary activity of the Distribution Business is
the receipt of electricity from Victoria's high voltage transmission system (the
"Grid") and the distribution of electricity to customers in Powercor's
distribution service area. Substantially all of the Distribution Business is a
regulated monopoly. Almost all customers within Powercor's distribution service
area are connected to its distribution network, whether electricity is supplied
by Powercor or another retail supplier. In 1998, the Distribution Business
generated all of Powercor's operating income.
The Distribution Business has grown in both its customer base and the volume
of electricity distributed, primarily reflecting economic growth in Victoria
generally and Powercor's distribution service
12
<PAGE>
area in particular. The following table sets forth the volumes of electricity
distributed by Powercor at the dates and for the periods presented. See
"Regulation--Distribution Pricing Regulation."
<TABLE>
<CAPTION>
ELECTRICITY DISTRIBUTED BY THE YEAR ENDED YEAR ENDED
DISTRIBUTION BUSINESS (KWH IN MILLIONS) DECEMBER 31, 1998 DECEMBER 31, 1997
- ------------------------------------------------------- ------------------- -------------------
<S> <C> <C>
Residential.......................................... 2,730 2,679
Commercial........................................... 1,634 1,550
Industrial........................................... 3,378 3,273
Other................................................ 545 536
----- -----
Total................................................ 8,287 8,038
----- -----
----- -----
</TABLE>
The Distribution Business of Powercor has not experienced significant
competition. Powercor believes that the economics underlying building and
maintaining a duplicate distribution network in its distribution service area
will restrict the introduction of another network. However, to the extent
customers establish or increase their own generation capacity, establish their
own private distribution networks, become directly connected to the Grid or
relocate operations outside Powercor's distribution service area, such customers
would not require the distribution services of Powercor except in certain cases
for standby connection services. As of December 31, 1998, Powercor had not lost
any distribution revenues to customers as a result of self-generation,
cogeneration or the establishment of private distribution networks. Although
Powercor believes that it has effective strategies in place to minimize this
type of load loss, there can be no assurance, particularly in view of its large
industrial customer base, that the Distribution Business will not experience
loss of revenues in the future as a result of such competition.
The major operating expenses of the Distribution Business are distribution
use-of-system costs, use-of-transmission-system fees and connection service
charges. The use-of-transmission-system fees and connection service charges,
regulated by the Tariff Order, are payable to the Victorian Power Exchange (the
"VPX"), a corporate body established under Victoria's Electricity Industry Act
1993 ("Electricity Act"), and the company that owns and maintains the Grid, GPU
Power Net Victoria ("GPU"), respectively, and constitute the VPX's and GPU's
costs associated with operation, maintenance and administration of the Grid. The
distribution use-of-system costs are Powercor's fundamental operating expenses
that result from operating and maintaining its distribution network. Unlike
use-of-transmission-system fees and connection service charges, Powercor has the
ability, and, given the current distribution price-cap regulatory structure, a
significant incentive, to control such distribution use-of-system costs through
a variety of cost reduction initiatives. However, there can be no assurance that
Powercor's cost efficiency initiatives will yield sufficient savings to increase
Powercor's margins from the Distribution Business to offset any network tariff
reductions that may result from the Office of Regulator General's (the "ORG")
review of distribution tariffs charged by Distribution Companies beginning in
2001, as described under "Regulation-- Distribution Pricing Regulation."
SUPPLY BUSINESS
The Supply Business conducts the commercial functions of purchasing,
marketing and selling of electricity and is responsible for the management of
the price, purchasing and volume risks associated with such functions and
end-use demand management. See "Regulation--Supply Pricing Regulation."
13
<PAGE>
The customer metered sites energy usage in millions of kWh and percentages
of Powercor's revenues from the Supply Business for franchise customers in
Powercor's distribution service area and for contestable customers are set forth
below:
<TABLE>
<CAPTION>
CUSTOMER SITES ENERGY USAGE REVENUES
-------------------- -------------------- -------------
1998 NO. % % %
- ----------------------------------------------- --------- --------- --- -------------
<S> <C> <C> <C> <C> <C>
Franchise Customers............................ 560,729 99.3 4,225 36 56
Contestable Customers.......................... 3,983 0.7 7,663 64 44
--------- --------- --------- --- ---
Total.......................................... 564,712 100.0 11,888 100 100
--------- --------- --------- --- ---
--------- --------- --------- --- ---
</TABLE>
<TABLE>
<CAPTION>
CUSTOMER SITES ENERGY USAGE REVENUES
-------------------- -------------------- -------------
1997 NO. % % %
- ----------------------------------------------- --------- --------- --- -------------
<S> <C> <C> <C> <C> <C>
Franchise Customers............................ 552,959 99.7 4,696 43 62
Contestable Customers.......................... 1,931 0.3 6,348 57 38
--------- --------- --------- --- ---
Total.......................................... 554,890 100.0 11,044 100 100
--------- --------- --------- --- ---
--------- --------- --------- --- ---
</TABLE>
The customer metered sites, energy usage in millions of kWh and percentages
of Powercor's revenues from the Supply Business for residential, commercial,
industrial and other customers for the years ended December 31, 1998 and 1997
are set forth below:
<TABLE>
<CAPTION>
CUSTOMER SITES(1) ENERGY USAGE REVENUES
-------------------- -------------------- -----------
NO. % % %
--------- --------- --------- -----------
<S> <C> <C> <C> <C> <C>
Residential Customers
December 31, 1998.......................... 467,505 82.8 2,725 22.9 34.7
December 31, 1997.......................... 459,780 82.8 2,683 24.3 35.0
Commercial Customers
December 31, 1998.......................... 50,768 9.0 3,952 33.2 33.1
December 31, 1997.......................... 49,821 9.0 3,082 27.9 30.4
Industrial Customers
December 31, 1998.......................... 10,400 1.8 4,689 39.4 26.1
December 31, 1997.......................... 9,440 1.7 4,755 43.1 28.1
Other Customers(2)
December 31, 1998.......................... 36,039 6.4 522 4.5 6.1
December 31, 1997.......................... 35,849 6.5 524 4.7 6.5
Total Customers
December 31, 1998.......................... 564,712 100.0 11,888 100.0 100.0
December 31, 1997.......................... 554,890 100.0 11,044 100.0 100.0
</TABLE>
- ------------------------
(1) Connections as of the date shown.
(2) Other customers include farm customers and public lighting and traction
customers.
The Supply Business revenue is derived from major industries such as
chemicals, petroleum, food and beverage, wholesale and retail, metal processing
and transport equipment. No single customer accounted for more than 3% of
Powercor's total revenues in 1998.
Powercor purchases all of its power for sale to franchise customers, other
than cogeneration output, through the competitive wholesale market for
electricity in Victoria (the "Pool"). As of December 13, 1998, the respective
state wholesale markets consolidated to a National Electricity Market ("NEM")
which is operated by the National Electricity Market Management Company
("NEMMCO"). There are two major components of the wholesale electricity market:
(i) the competitive energy market, centered
14
<PAGE>
primarily around the Pool, which establishes the spot price for the sale of
electricity by generators to suppliers and (ii) the contract trade, which
involves bilateral financial contracts between electricity buyers and sellers
outside the Pool that are used to hedge against Pool price volatility. The
principal function of the Pool is to allow market forces rather than monopolized
central planning to determine the amount, mix and cost characteristics of
generating plants and the level and shape of demand of suppliers.
Powercor is a party to a series of bilateral financial "vesting contracts"
that have been structured to hedge the price for Powercor's forecasted franchise
energy requirements through December 31, 2000. These vesting contracts take the
form of two-way and one-way contracts. Two-way vesting contracts are structured
such that generators and Distribution Companies, including Powercor, compensate
each other for the difference between the system marginal price, which is the
spot price payable to generators in the wholesale market via the Pool, and the
contract price up to a specified price cap. One-way vesting contracts provide
for amounts to be paid by generators to Distribution Companies for differences
when the system marginal price is above a specified price cap. As franchise
customers of the Supply Business become contestable, the notional amount of the
vesting contracts is reduced accordingly.
Powercor also has hedging contracts that relate to contestable customer
loads in order to manage electricity price risk. Historically, Powercor has
hedged each electricity sales contract with a back-to-back purchase contract.
Increasingly, however, as the contestable customer market grows and as an
Australian electricity futures market develops, Powercor is hedging its supply
obligations on a portfolio-wide basis. Powercor's policy is to hedge most of its
supply obligations and to monitor the financial risk exposure of its unhedged
positions.
REGULATION
The ORG. The Victorian government established the ORG pursuant to the
Office of the Regulator-General Act 1994 to regulate different Victorian
industries. In the context of regulating activities within the electricity
industry, the ORG has powers under the Electricity Act. The ORG's functions
pursuant to the Electricity Act include granting licenses to generate, transmit,
distribute or supply electricity, ensuring compliance with industry codes and
Pool rules, administering cross-ownership provisions and administering the
Victorian Electricity Supply Industry Tariff Order (the "Tariff Order").
Licenses. Unless covered by an exemption, the Electricity Act prohibits,
without a relevant license, the activities of generation of electricity for
supply or sale, transmission, distribution, supply or sale of electricity or
operation of a wholesale electricity market. Licenses are issued by the ORG
after the applicant has satisfied specific criteria and subject to the
satisfaction of ongoing conditions, such as continued compliance with industry
codes and Pool rules.
Powercor has an exclusive license to distribute electricity to certain
customers in its distribution service area in Victoria and nonexclusive licenses
to supply electricity to all customers in its distribution service area and
elsewhere in Victoria, NSW, ACT and Queensland. See "--Supply Pricing
Regulation." The Hazelwood Partnership has a license to generate and sell
electricity to the wholesale market in Victoria and NSW. See "Hazelwood" below.
The Tariff Order. Pursuant to the Electricity Act, the Tariff Order
regulates charges for connection to, and use of, the transmission system,
distribution use-of-system charges that can be levied by Distribution Companies
and tariffs for the sale of electricity to franchise customers until December
31, 2000. The ORG is charged with the regulatory oversight of the Tariff Order.
The Tariff Order is designed to provide a level of stability and continuity in
tariff regulation.
Distribution Pricing Regulation. Under distribution licenses granted by the
ORG, the Distribution Companies are able to levy the following charges, which
include their profit: (i) network tariffs, which include recovery of
distribution use-of-system costs, use-of-transmission-system fees and GPU
connection service charges, (ii) connection charges for connecting customers to
the network, taking into account that a
15
<PAGE>
portion of the costs of connection are recovered through network tariffs and
(iii) charges for other services, which are required to be fair and reasonable.
The level of distribution charges, as one element of the network tariffs, is
regulated under the Tariff Order through December 31, 2000 pursuant to an
incentive-based CPI-X formula, which attempts to ensure that the weighted
average of distribution charges for each year, within the respective
distribution categories, does not exceed the average of the previous year's base
prices for each distribution category weighted by the forecast quantity of
electricity to be delivered and adjusted for inflation using a consumer-price
index formula and for under and over-recovery in previous financial years.
Subsequent to the year 2000, existing network tariffs will be subject to
review by the ORG within the framework of, and the principles set forth in, the
Tariff Order. In particular, the Tariff Order provides that the ORG, in
connection with such review of network tariffs, can only reset the network
tariffs for a period of not less than five years, the ORG must utilize CPI-X
price capping and not rate of return regulation and the ORG must consider the
need to (i) provide each Distribution Company with incentives to operate
efficiently, (ii) ensure a fair sharing of benefits achieved through efficiency
between customers and Distribution Companies and (iii) ensure appropriate
incentives for capital expenditures and maintenance of the distribution
networks. The impact on Powercor, if any, of the post year 2000 ORG review on
customer prices is not clear at this time.
Supply Pricing Regulation. Under the retail portions of their licenses,
Distribution Companies are required, pursuant to the Tariff Order, to supply
electricity to franchise customers through December 2000, at prices no greater
than the prices specified in the applicable Maximum Uniform Tariff ("MUT") for
such customers. The prices specified in the MUTs are therefore fully regulated
and inclusive of all network and distribution related charges and energy costs.
Powercor's tariffs are adjusted annually by a percentage equal to the movement
in Consumer Price Index (All Groups) for Melbourne ("CPI") minus a fixed
percentage. Commencing both July 1, 1999 and 2000, the annual adjustments for
large and medium businesses will be the CPI and will be the CPI minus one for
medium and small businesses and residential and rural customers. The CPI for the
year ended December 31, 1998 was 1.2% and it was 0.2% for the year ended
December 31, 1997.
Prices charged to contestable customers are subject to competitive forces
and, therefore, are not directly regulated by the ORG, in contrast to prices
charged to franchise customers. Prices to contestable customers include
regulated network charges (transmission and distribution) and competitively
determined energy supply charges.
Customers in Victoria and NSW with annual consumption in excess of 160
megawatt hours ("MWh") per year are now contestable. Customers with usage of 160
MWh per year or less are not currently contestable but will incrementally become
contestable over the period ending December 31, 2000 in Victoria and over the
period ending June 30, 1999 in NSW.
Customers in Queensland with annual consumption of 4 million kWh per year
can now choose their electricity retailer and there are plans to introduce
contestability for customers with annual usage of 200 MWh per year on July 1,
1999 and for all remaining customers on July 1, 2001.
For a description of Powercor's properties, see "ITEM 2.
PROPERTIES--AUSTRALIA."
ENVIRONMENTAL ISSUES
The nature of Powercor's operations exposes it to risks of varying degrees
associated with bushfires and other environmental issues.
16
<PAGE>
Approximately 63% of Powercor's assets are located in fire prone zones.
Powercor and its predecessors have developed a comprehensive bushfire risk
management and mitigation system to reduce bushfire exposure. This system is
based on regular inspections of poles and conductors and the identification and
reporting of maintenance items existing on the network that may contribute to an
electrically initiated bushfire.
Powercor is subject to various Australian federal and Victorian state
environmental regulations, the most significant of which is the Victorian
Environment Protection Act of 1970 ("VEPA"). The VEPA regulates, in particular,
the discharge of waste into air, land and water, site contamination, the
emission of noise and the storage, recycling and disposal of solid and
industrial waste. The VEPA established the Environment Protection Authority
("Authority") and grants the Authority a wide range of powers to control and
prevent environmental pollution. These powers include issuing approvals for
construction of works that may cause noise or emissions to air, water or land,
waste discharge licenses and pollution abatement notices. Powercor believes it
is currently in material compliance with the provisions of the VEPA and no
licenses or work approvals from the Authority are currently required for
activities undertaken by Powercor.
HAZELWOOD
Hazelwood Pacific Pty Ltd ("Hazelwood Pacific"), an indirect, wholly owned
subsidiary of Holdings, holds a 19.9% interest in the Hazelwood Power
Partnership (the "Hazelwood Partnership"), which owns a 1,600 MW, brown
coal-fired thermal power station (the "Hazelwood Plant") and the adjacent brown
coal mine (the "Hazelwood Mine") in Victoria, Australia. The Hazelwood
Partnership is composed of Hazelwood Pacific, an affiliate of National Power
Corporation PLC ("National Power") (71.94%), and two companies associated with
the Commonwealth Bank group of Australia (8.16%). National Power oversees the
Hazelwood Plant operations and the Company oversees operations at the Hazelwood
Mine. In the fourth quarter of 1998, the Company began soliciting bids and is
committed to selling its equity interest in the Hazelwood Partnership and,
accordingly, the Company recorded a pretax loss of $28 million ($17 million
after-tax) to reduce its carrying value in the Hazelwood Power Station to its
estimated net realizable value less selling costs.
Through March 2000, Hazelwood Pacific estimates that its contribution to the
capital expenditure commitments of the Hazelwood Plant will be $4 million and $5
million for the years 1999 and 2000, respectively. The investment is accounted
for on an equity basis. For 1998 and 1997, equity losses from Hazelwood were
$5,483, and $2,919, respectively.
The Hazelwood Partnership sells its power through a statewide generation
pool and enters into bilateral financial contracts with Australian distribution
companies, such as Powercor. Prices vary with weather, economic growth and other
factors affecting the supply of and demand for power. Power prices tend to be
lowest during Australia's summer months (the fourth and first calendar
quarters), except during periods of unusually high temperatures.
For a description of Hazelwood properties, see ITEM 2.
PROPERTIES--AUSTRALIA.
ENVIRONMENTAL ISSUES
The operations of the Hazelwood Partnership are subject to environmental
regulation. The Hazelwood Partnership is required to obtain licenses from the
Authority in connection with certain of its operations, including operations
involving the emission or discharge of pollutants. These licenses are generally
issued to the Hazelwood Partnership in the ordinary course of business and are
terminable upon breach or violation.
The Hazelwood Plant is fired by brown coal and consequently emits more
greenhouse gas per unit of power produced than is emitted by power plants fired
by black coal or natural gas. The Australian
17
<PAGE>
government has participated in negotiations with governments of other countries
with respect to greenhouse gas emission levels. As a result of the December 1997
Kyoto Climate Change Conference, the Australian government committed to
limitations on greenhouse gas emissions. It is anticipated that the Australian
government will introduce some measures to control greenhouse gas emissions.
Such measures could increase capital expenditures at the Hazelwood Plant and
could have the effect of making brown coal fired generators less competitive.
OTHER OPERATIONS
PACIFICORP FINANCIAL SERVICES
PFS is a holding company principally engaged in holding investments in tax
advantaged and leveraged lease assets (primarily aircraft).
PFS made its last investment in aircraft or loans relating to aircraft in
1992. At December 31, 1998, approximately 90% of the aircraft in PFS's portfolio
investment were Stage III noise compliant. At December 31, 1998, PFS's aviation
finance portfolio had total leveraged lease and other financial assets of $348
million (30 aircraft), representing approximately 82% of PFS's consolidated
assets.
PFS has completed the construction of four plants in the Birmingham, Alabama
area which produce a synthetic coal fuel designed to qualify for tax credits
under Section 29 of the Internal Revenue Code. The technology utilized by the
plants is licensed from Covol Technologies, Inc. ("Covol"). PFS owns
approximately 8% of the outstanding shares of Covol common stock.
INTERNATIONAL OPERATIONS
Through its subsidiaries, Holdings has been engaged in the acquisition or
development of electrical power projects or systems internationally. The most
significant of these projects is a 33% interest in a 75 MW hydroelectric project
in the Philippines.
In October 1998, the Company decided to focus on its western United States
electric business and its electric distribution business in Australia and to
sell or shut down all international businesses and activities, subject to
achieving reasonable economic and other terms. The process of exiting the
international businesses is underway.
DISCONTINUED OPERATIONS
The Company's discontinued energy trading business includes the eastern
United States electricity trading operations of PPM and the natural gas
marketing and storage operations of TPC. PPM was a wholesale power trading
company focusing in the eastern United States. PPM's activities in the eastern
United States have been discontinued, and all forward energy trading has been
closed and is going through settlement. PPM continues to honor services under
long-term contracts to utilities in Minnesota and Oklahoma. Holdings entered
into a Stock Purchase Agreement with NI Energy Services, Inc., dated February 9,
1999, for the sale of the stock of TPC for approximately $132.5 million. In
addition, a working capital adjustment will be calculated and paid following
closing of the TPC transaction, which is anticipated during the first half of
1999.
EMPLOYEES
PacifiCorp and its subsidiaries had 9,120 employees on December 31, 1998. Of
these employees, 7,847 were employed by PacifiCorp and its mining affiliates,
1,117 were employed by Powercor and 156 were employed by PPM, TPC, PFS and other
subsidiaries.
Approximately 62% of the employees of PacifiCorp and its mining affiliates
are covered by union contracts, principally with the International Brotherhood
of Electrical Workers, the Utility Workers Union
18
<PAGE>
of America and the United Mine Workers of America. Due to changes in Australian
laws, information concerning union membership is no longer available to
employers.
In the Company's judgment, employee relations are satisfactory.
ITEM 2. PROPERTIES
UNITED STATES
The Company owns 52 hydroelectric generating plants and has an interest in
one additional plant, with an aggregate nameplate rating of 1,069 MW and plant
net capability of 1,126 MW. It also owns or has interests in 15 thermal-electric
generating plants with an aggregate nameplate rating of 7,573 MW and plant net
capability of 7,039 MW. The Company also owns one gas turbine generating plant
and has interests in one combined-cycle and one wind power generating plant with
an aggregate nameplate rating of 359 MW and plant net capability of 281 MW. The
following table summarizes the Company's existing generating facilities:
<TABLE>
<CAPTION>
NAMEPLATE PLANT NET
INSTALLATION RATING CAPABILITY
LOCATION ENERGY SOURCE DATES (MW) (MW)
----------------------- ----------------------- ----------- ----------- -----------
<S> <C> <C> <C> <C> <C>
HYDROELECTRIC PLANTS
Swift........................ Cougar, Washington Lewis River 1958 240.0 263.0
Merwin....................... Ariel, Washington Lewis River 1931-1958 136.0 142.0
Yale......................... Amboy, Washington Lewis River 1953 134.0 134.0
Five North Umpqua Plants..... Toketee Falls, Oregon N. Umpqua River 1950-1956 133.5 138.0
John C. Boyle................ Keno, Oregon Klamath River 1958 80.0 90.0
Copco Nos. 1 and 2 Plants.... Hornbrook, California Klamath River 1918-1925 47.0 54.5
Clearwater Nos. 1 and 2 Toketee Falls, Oregon Clearwater River
Plants..................... 1953 41.0 41.0
Grace........................ Grace, Idaho Bear River 1914-1923 33.0 33.0
Prospect No. 2............... Prospect, Oregon Rogue River 1928 32.0 36.0
Cutler....................... Collinston, Utah Bear River 1927 30.0 29.1
Oneida....................... Preston, Idaho Bear River 1915-1920 30.0 28.0
Iron Gate.................... Hornbrook, California Klamath River 1962 18.0 20.0
Soda......................... Soda Springs, Idaho Bear River 1924 14.0 14.0
Fish Creek................... Toketee Falls, Oregon Fish Creek 1952 11.0 12.0
33 Minor Hydroelectric Plants Various Various 1896-1990 89.3* 90.9*
----------- -----------
Subtotal (53 Hydroelectric Plants) 1,068.8 1,125.5
----------- -----------
THERMAL ELECTRIC PLANTS
Jim Bridger.................. Rock Springs, Wyoming Coal-Fired 1974-1979 1,529.5* 1,406.7*
Huntington................... Huntington, Utah Coal-Fired 1974-1977 996.0 895.0
Dave Johnston................ Glenrock, Wyoming Coal-Fired 1959-1972 816.7 772.0
Naughton..................... Kemmerer, Wyoming Coal-Fired 1963-1971 707.2 700.0
Centralia.................... Centralia, Washington Coal-Fired 1972 693.5* 636.5*
Hunter 1 and 2............... Castle Dale, Utah Coal-Fired 1978-1980 703.5* 648.4*
Hunter 3..................... Castle Dale, Utah Coal-Fired 1983 495.6 460.0
Cholla Unit 4................ Joseph City, Arizona Coal-Fired 1981 414.0 380.0
Wyodak....................... Gillette, Wyoming Coal-Fired 1978 289.7* 268.0*
Gadsby....................... Salt Lake City, Utah Gas-Fired 1951-1955 251.6 235.0
Carbon....................... Castle Gate, Utah Coal-Fired 1954-1957 188.6 175.0
Craig 1 and 2................ Craig, Colorado Coal-Fired 1979-1980 172.1* 165.0*
Colstrip 3 and 4............. Colstrip, Montana Coal-Fired 1984-1986 155.6* 144.0*
Hayden 1 and 2............... Hayden, Colorado Coal-Fired 1965-1976 81.3* 78.0*
Blundell..................... Milford, Utah Geothermal 1984 26.1 23.0
James River.................. Camas, Washington Black Liquor 1996 52.2 52.0
----------- -----------
Subtotal (15 Thermal Electric Plants) 7,573.2 7,038.6
----------- -----------
OTHER PLANTS
Little Mountain.............. Ogden, Utah Gas Turbine 1971 16.0 14.0
Hermiston.................... Hermiston, Oregon Combined Cycle 1996 310.6* 234.0*
Foote Creek.................. Arlington, Wyoming Wind Turbines 1998 32.6 32.6*
----------- -----------
Subtotal (3 Other Plants) 359.2 280.6
----------- -----------
Total Hydro, Thermal and Other Generating Facilities (71) 9,001.2 8,444.7
----------- -----------
----------- -----------
</TABLE>
- ------------------------------
* Jointly owned plants; amount shown represents the Company's share only.
NOTE: Hydroelectric project locations are stated by locality and river
watershed.
19
<PAGE>
The Company's generating facilities are interconnected through its own
transmission lines or by contract through the lines of others. Substantially all
generating facilities and reservoirs located within the Pacific Northwest region
are managed on a coordinated basis to obtain maximum load carrying capability
and efficiency. Portions of the Company's transmission and distribution systems
are located, by franchise or permit, upon public lands, roads and streets and,
by easement or license, upon the lands of other third parties.
Substantially all of the Company's electric utility plants are subject to
the lien of the Company's Mortgage and Deed of Trust.
The following table describes the Company's recoverable coal reserves as of
December 31, 1998. All coal reserves are dedicated to nearby Company operated
generating plants. Recoverability by surface mining methods typically ranges
between 90% and 95%. Recoverability by underground mining techniques ranges from
50% to 70%. The Company considers that the respective coal reserves assigned to
the Centralia, Craig, Dave Johnston, Huntington, Hunter and Jim Bridger plants,
together with coal available under both long-term and short-term contracts with
external suppliers, will be sufficient to provide these plants with fuel that
meets the Clean Air Act standards effective in 1998, for their current
economically useful lives. The sulfur content of the coal reserves ranges from
0.43% to 0.84% and the British Thermal Units value per pound of the reserves
ranges from 7,600 to 11,400. Coal reserve estimates are subject to adjustment as
a result of the development of additional data, new mining technology and
changes in regulation and economic factors affecting the utilization of such
reserves.
<TABLE>
<CAPTION>
RECOVERABLE TONS
LOCATION PLANT SERVED (IN MILLIONS)
- ----------------------------------------------- -------------------------- -----------------
<S> <C> <C>
Centralia, Washington.......................... Centralia 41(1)
Craig, Colorado................................ Craig 51(2)
Glenrock, Wyoming.............................. Dave Johnston 3(1)(5)
Emery County, Utah............................. Huntington and Hunter 56(1)(3)
Rock Springs, Wyoming.......................... Jim Bridger 118(4)
</TABLE>
- ------------------------
(1) These coal reserves are mined by subsidiaries of the Company.
(2) These coal reserves are leased and mined by Trapper Mining, Inc., a
Delaware nonstock corporation operated on a cooperative basis, in which the
Company has an ownership interest of approximately 20%.
(3) These coal reserves are in underground mines.
(4) These coal reserves are leased and mined by Bridger Coal Company, a joint
venture between Pacific Minerals, Inc., a subsidiary of the Company, and a
subsidiary of Idaho Power Company. Pacific Minerals, Inc. has a two-thirds
interest in the joint venture.
(5) The Company expects to cease substantially all mining operations at this
location in 1999.
Most of the Company's coal reserves are held pursuant to leases from the
federal government through the Bureau of Land Management and from certain states
and private parties. The leases generally have multi-year terms that may be
renewed or extended and require payment of rentals and royalties. In addition,
federal and state regulations require that comprehensive environmental
protection and reclamation standards be met during the course of mining
operations and upon completion of mining activities. In 1998, the Company
expended $7 million of reclamation costs and accrued $5 million of estimated
final mining reclamation costs. Final mine reclamation funds have been
established with respect to certain of the Company's mining properties. At
December 31, 1998, the Company's pro rata portion of these reclamation funds
totaled $52 million and the Company had an accrued reclamation liability of $161
million at December 31, 1998.
20
<PAGE>
AUSTRALIA
Powercor's electrical distribution network, located in Victoria, Australia,
comprises: (i) 66 kilovolts ("kV") and 22 kV subtransmission lines and
underground subtransmission cables that transport wholesale energy from 11
terminal stations owned by GPU and controlled, under lease, by the VPX; (ii) 50
zone substations that transform electricity to lower voltages (22 kV and below)
and then distribute the energy through the distribution network; and (iii) 22
kV, 11 kV and 6.6 kV distribution lines, including distribution substations that
transform electricity to low voltages (415 volts and below) suitable for
connection to the majority of the customers. In addition, Powercor leases its
principal executive offices at 40 Market St, Melbourne in Victoria under a
four-year lease with an option to renew for another eight years.
The Hazelwood Plant has four stages, each with two 200 MW boiler and turbo
generator units, and was constructed progressively between November 1964 and
August 1971. The plant has eight units, seven of which were in service at
December 31, 1998. Unit 3 was out of service from September 26, 1998 through
January 5, 1999 to enable precipitator replacements. The Hazelwood Mine has
between 400 million and 450 million recoverable tons of brown coal, which is
expected to provide the Hazelwood Plant with sufficient quantities of coal for
the 40 years of anticipated plant operation.
ITEM 3. LEGAL PROCEEDINGS
The Company and its subsidiaries are parties to various legal claims,
actions and complaints, one of which is described below. Although it is
impossible to predict with certainty whether or not the Company and its
subsidiaries will ultimately be successful in its legal proceedings or, if not,
what the impact might be, management believes that disposition of these matters
will not have a material adverse effect on the Company's consolidated financial
results.
On October 9, 1996, the Sierra Club filed an action against the Company and
the other joint owners of Units 1 and 2 of the Craig Electric Generating Station
(the "Station") under the citizen's suit provisions of the Federal Clean Air Act
alleging, based upon reports from emissions monitors at the Station, that over
14,000 violations of state and federal opacity standards have occurred over a
five-year period at Units 1 and 2 of the Station. (SIERRA CLUB V. TRI-STATE
GENERATION AND TRANSMISSION ASSOCIATION, INC., PUBLIC SERVICE COMPANY OF
COLORADO, INC., SALT RIVER PROJECT AGRICULTURAL IMPROVEMENT AND POWER DISTRICT,
PACIFICORP AND PLATTE RIVER POWER AUTHORITY, Civil Action No. 96-B2368, US
District Court for the District of Colorado). The Company has a 19.28% interest
in Units 1 and 2 of the Station, which is operated by Tri-State Generation and
Transmission Association and located in Craig, Colorado.
The action seeks injunctive relief requiring the defendants to operate the
Station in compliance with applicable statutes and regulations, the imposition
of civil penalties, litigation costs, attorneys' fees and mitigation. The
Federal Clean Air Act provides for penalties of up to $27,500 per day for each
violation, but the level of penalties imposed in any particular instance is
discretionary. The complaint alleges that the Company and Public Service Company
of Colorado are responsible for the alleged violations beginning with the second
quarter of 1992, when they acquired their interests in the Station, and that the
other owners are responsible for the alleged violations during the entire
period. The complaint alleges that there were approximately 10,000 violations
since the second quarter of 1992. On March 18, 1999, the district court issued
its order regarding summary judgment motions filed by the parties. The court
ruled, among other things, that the emission monitors may be used by the
plaintiff to establish violations of opacity standards, but that the plant
owners are entitled to prove that the reported information is flawed.
A trial date has not yet been set. The Company is unable to predict the
level of penalties or other remedies that may be imposed upon the joint owners
of the Station or what portion of such liability may ultimately be borne by the
Company.
21
<PAGE>
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
No information is required to be reported pursuant to this item.
ITEM 4A. EXECUTIVE OFFICERS OF THE REGISTRANT
The following is a list of all executive officers of the Company. There are
no family relationships among the executive officers of the Company. Officers of
the Company are normally elected annually.
Keith R. McKennon, born December 25, 1933, Chairman, President and Chief
Executive Officer of the Company.
Mr. McKennon was elected Chairman of the Board in February 1994, Chief
Executive Officer on September 1, 1998 and President on November 18, 1998. He
has served as a Director of the Company since 1990.
Richard T. O'Brien, born March 20, 1954, Executive Vice President and Chief
Operating Officer of the Company and President and Chief Executive Officer of
Holdings.
Mr. O'Brien was elected Executive Vice President and Chief Operating Officer
of the Company in July 1998 and President and Chief Executive Officer of
Holdings in January 1998. He served as Senior Vice President and Chief Financial
Officer of the Company from August 1995 to July 1998 and Senior Vice President
of Holdings from February 1996 to January 1998. He served as Vice President of
the Company from August 1993 to August 1995.
John A. Bohling, born June 23, 1943, Senior Vice President of the Company.
Mr. Bohling was elected a Senior Vice President of the Company in February
1993.
William C. Brauer, born January 11, 1939, Senior Vice President of the
Company.
Mr. Brauer was elected a Senior Vice President of the Company in May 1996.
He served as a Vice President of the Company from 1992 to 1996.
Paul G. Lorenzini, born April 16, 1942, Senior Vice President of the
Company.
Mr. Lorenzini was elected a Senior Vice President of the Company in May
1994. He served as President of Pacific Power from January 1992 to May 1994.
Daniel L. Spalding, born December 23, 1953, Chairman and Chief Executive
Officer of Powercor and Senior Vice President of the Company.
Mr. Spalding was elected Chairman and Chief Executive Officer of Powercor in
December 1995 and was elected a Senior Vice President of the Company in February
1992.
Dennis P. Steinberg, born December 5, 1946, Senior Vice President of the
Company.
Mr. Steinberg was elected a Senior Vice President of the Company in August
1994. He served as a Vice President of the Company from February 1992 to August
1994.
Verl R. Topham, born August 25, 1934, Senior Vice President and General
Counsel of the Company and of Holdings.
Mr. Topham was elected Senior Vice President and General Counsel of Holdings
in January 1998, Senior Vice President and General Counsel and a director of the
Company in May 1994. He served as President of Utah Power from February 1990 to
May 1994. He has announced his retirement effective May 1, 1999.
Donald A. Bloodworth, born May 9, 1956, Vice President of the Company.
22
<PAGE>
Mr. Bloodworth was elected a Vice President of the Company in November 1997.
He was employed by AirTouch Communications from April 1997 to November 1997. He
served as Controller of the Company from August 1996 until April 1997. He served
as Vice President of Revenue Requirements and Controller for PTI from May 1993
until August 1996.
Thomas J. Imeson, born March 20, 1950, Vice President of the Company.
Mr. Imeson was elected a Vice President of the Company in February 1992.
Sally A. Nofziger, born July 5, 1936, Vice President and Corporate Secretary
of the Company, Secretary of Holdings and PFS.
Mrs. Nofziger was elected a Vice President of the Company in 1989 and has
been Corporate Secretary of the Company since 1983.
William E. Peressini, born May 23, 1956, Vice President and Treasurer of the
Company and Vice President, Finance of Holdings.
Mr. Peressini was elected Vice President and Treasurer of the Company in May
1996. He had served as Treasurer of the Company since January 1994. He has been
Treasurer of Holdings since February 1994. He served as Executive Vice President
of PFS from January 1992 to January 1994.
Michael J. Pittman, born March 25, 1953, Vice President of the Company.
Mr. Pittman was elected a Vice President of the Company in May 1993.
Robert R. Dalley, born April 11, 1954, Controller and Chief Accounting
Officer of the Company.
Mr. Dalley was elected Controller and Chief Accounting Officer of the
Company in August 1998. He served as Assistant Controller from March 1998 to
August 1998 and as an Assistant Vice President of the Company from July 1992 to
March 1998.
PART II
ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS
(a). The Company's common stock is traded on the New York Stock Exchange and
the Pacific Stock Exchange. Sales price information required by this item is
included under "Quarterly Financial Data" on page 95 of this Report.
(b). At March 1, 1999, there were approximately 105,100 holders of the
Company's common stock.
ITEM 6. SELECTED FINANCIAL DATA
The information required by this item is included under "Selected Financial
Information" on page 90 of this Report.
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATIONS
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
23
<PAGE>
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.
24
<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 Operations..................................................... 13.0 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
Scottish Power 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)
--------- ----------- --------- -----------
--------- ----------- --------- -----------
</TABLE>
- ------------------------
(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.
25
<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,
26
<PAGE>
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.
1997 ASSET SALE GAINS
<TABLE>
<CAPTION>
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
------ --------- --------- ---------
------ --------- --------- ---------
</TABLE>
- ------------------------
(a) Cash from asset sales is net of income taxes.
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>
REVENUES ENERGY SALES
MILLIONS OF DOLLARS 1998 1997 1996 MILLIONS OF KWH 1998 1997 1996
- --------------------------- --------- --------- --------- --------------------------- --------- --------- ---------
<S> <C> <C> <C> <C> <C> <C> <C>
Wholesale sales and $ 2,583.6 $ 1,428.0 $ 738.8 Wholesale sales and 94,077 59,143 29,665
market trading........... market trading.............
Residential................ 806.6 814.0 801.4 Residential................ 12,969 12,902 12,819
Industrial................. 705.5 709.9 719.3 Industrial................. 20,966 20,674 20,332
Commercial................. 653.5 640.9 623.3 Commercial................. 12,299 11,868 11,497
Other...................... 95.9 114.1 109.0 Other...................... 651 705 640
--------- --------- --------- --------- --------- ---------
$ 4,845.1 $ 3,706.9 $ 2,991.8 140,962 105,292 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
27
<PAGE>
("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.
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
28
<PAGE>
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.
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 % 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 $4 million
increase in purchased power costs in 1998. The Company expects a reduced level
of power purchases in 1999 as a result of its decision to scale back short-term
wholesale trading activities.
29
<PAGE>
SHORT-TERM FIRM AND SPOT MARKET SALES AND PURCHASES
<TABLE>
<CAPTION>
1998 1997 1996
--------- --------- ---------
<S> <C> <C> <C>
Total sales volume (thousands of MWh)............................................ 80,097 44,927 16,394
Average sales price ($/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 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.
30
<PAGE>
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.
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
31
<PAGE>
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 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
32
<PAGE>
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
33
<PAGE>
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 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 ("SO(2)") 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
SO(2), nitrogen oxides ("NO(x)"), carbon monoxide and particulate matter
emission limits. The new emission limits will require the plant to install two
scrubbers and low NO(x) 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.
34
<PAGE>
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.
AUSTRALIAN ELECTRIC OPERATIONS
REVENUES
<TABLE>
<CAPTION>
CHANGE
REVENUES DUE TO OPERATING
MILLIONS OF DOLLARS 1998 1997 CURRENCY VARIANCE
- ------------------------------------------------------------------------- --------- --------- ----------- -----------
<S> <C> <C> <C> <C>
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>
ENERGY SALES
MILLIONS OF KWH 1998 1997 1996
- --------------------------------------------------------------------------------------- --------- --------- ---------
<S> <C> <C> <C>
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>
35
<PAGE>
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.
1997 COMPARED TO 1996
<TABLE>
<CAPTION>
CHANGE
DUE TO OPERATING
MILLIONS OF DOLLARS 1997 1996 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>
36
<PAGE>
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 TO OPERATING
MILLIONS OF DOLLARS 1998 1997 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.
37
<PAGE>
1997 COMPARED TO 1996
<TABLE>
<CAPTION>
CHANGE
DUE TO OPERATING
MILLIONS OF DOLLARS 1997 1996 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
38
<PAGE>
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.
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>
EARNINGS CONTRIBUTION
MILLIONS OF DOLLARS 1998 1997 1996
- --------------------------------------------------------------------- --------- --------- ---------
<S> <C> <C> <C>
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.
39
<PAGE>
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.
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.
40
<PAGE>
LIQUIDITY AND CAPITAL RESOURCES
CASH FLOW SUMMARY
<TABLE>
<CAPTION>
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>
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
41
<PAGE>
$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
42
<PAGE>
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 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.
43
<PAGE>
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.
VARIABLE RATE LIABILITIES
<TABLE>
<CAPTION>
MILLIONS OF DOLLARS 1998 1997
- ----------------------------------------------------------------------------------------------- --------- ---------
<S> <C> <C>
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%
</TABLE>
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.
44
<PAGE>
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 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
45
<PAGE>
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.
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.
46
<PAGE>
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.
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>
ASSESSMENT REMEDIATION
INVENTORY (% COMPLETED) 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>
47
<PAGE>
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>
PERCENT OF ALL CRITICAL THIRD
READINESS TARGET DATES (ON OR BEFORE) PARTIES READY
- --------------------------------------------------------------------------------------- -------------------------------
<S> <C>
12/31/1998............................................................................. 22%
03/31/1999............................................................................. 33
06/30/1999............................................................................. 77
09/30/1999............................................................................. 91
12/31/1999............................................................................. 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.
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.
48
<PAGE>
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 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.
49
<PAGE>
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.
50
<PAGE>
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
The information required by this item is included under "Risk Management,"
"Value at Risk Analysis," "Sensitivity Analysis," "Interest Rate Exposure,"
"Currency Rate Exposure" and "Commodity Price Exposure" on pages 45 through 47
of this Report under ITEM 7.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
<TABLE>
<CAPTION>
PAGE
-----
<S> <C>
Index To Consolidated Financial Statements:
Report of Management..................................................................................... 52
Independent Auditors' Report............................................................................. 53
Statements Of Consolidated Income For Each
Of The Three Years Ended December 31, 1998............................................................. 54
Statements Of Consolidated Cash Flows For Each
Of The Three Years Ended December 31, 1998............................................................. 55
Consolidated Balance Sheets At December 31, 1998 And 1997................................................ 56
Statements Of Consolidated Changes In Common Shareholders' Equity For Each Of The Three Years Ended
December 31, 1998...................................................................................... 58
Notes To Consolidated Financial Statements............................................................... 59
</TABLE>
51
<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.
Keith R. McKennon
Chairman, President and Chief Executive Officer
Robert R. Dalley
Controller and Chief Accounting Officer
52
<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.
Deloitte & Touche LLP
Portland, Oregon
March 5, 1999
53
<PAGE>
STATEMENTS OF CONSOLIDATED INCOME
<TABLE>
<CAPTION>
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 operation....................................................... (0.49) 1.50 0.25
Extraordinary item........................................................... -- (0.05) --
--------- --------- ---------
Total........................................................................ $ (0.19) $ 2.16 $ 1.62
--------- --------- ---------
--------- --------- ---------
</TABLE>
(See accompanying Notes to Consolidated Financial Statements)
54
<PAGE>
STATEMENTS OF CONSOLIDATED CASH FLOWS
<TABLE>
<CAPTION>
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
--------- --------- ---------
--------- --------- ---------
</TABLE>
(See accompanying Notes to Consolidated Financial Statements)
55
<PAGE>
CONSOLIDATED BALANCE SHEETS
<TABLE>
<CAPTION>
DECEMBER 31/MILLIONS OF DOLLARS 1998 1997
- ---------------------------------------------------------------------------------------- ---------- ----------
<S> <C> <C>
ASSETS
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
---------- ----------
---------- ----------
</TABLE>
(See accompanying Notes to Consolidated Financial Statements)
56
<PAGE>
CONSOLIDATED BALANCE SHEETS
<TABLE>
<CAPTION>
DECEMBER 31/MILLIONS OF DOLLARS 1998 1997
- ---------------------------------------------------------------------------------------- ---------- ----------
<S> <C> <C>
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
---------- ----------
---------- ----------
</TABLE>
(See accompanying Notes to Consolidated Financial Statements)
57
<PAGE>
STATEMENTS OF CONSOLIDATED CHANGES IN COMMON SHAREHOLDERS' EQUITY
<TABLE>
<CAPTION>
COMMON SHAREHOLDERS'
ACCUMULATED
CAPITAL OTHER TOTAL
-------------------- 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)
--------- --------- ----------- ------ ------
--------- --------- ----------- ------ ------
</TABLE>
(See accompanying Notes to Consolidated Financial Statements)
58
<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.
59
<PAGE>
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
YEARS ENDED DECEMBER 31, 1998, 1997 AND 1996
NOTE 1 SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (CONTINUED)
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.
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.
60
<PAGE>
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
YEARS ENDED DECEMBER 31, 1998, 1997 AND 1996
NOTE 1 SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (CONTINUED)
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.
61
<PAGE>
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
YEARS ENDED DECEMBER 31, 1998, 1997 AND 1996
NOTE 1 SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (CONTINUED)
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.
62
<PAGE>
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
YEARS ENDED DECEMBER 31, 1998, 1997 AND 1996
NOTE 1 SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (CONTINUED)
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.
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.
63
<PAGE>
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
YEARS ENDED DECEMBER 31, 1998, 1997 AND 1996
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
64
<PAGE>
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
YEARS ENDED DECEMBER 31, 1998, 1997 AND 1996
NOTE 4 DISCONTINUED OPERATIONS (CONTINUED)
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.
<TABLE>
<CAPTION>
AT SEPTEMBER 30 AT 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.
65
<PAGE>
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
YEARS ENDED DECEMBER 31, 1998, 1997 AND 1996
NOTE 4 DISCONTINUED OPERATIONS (CONTINUED)
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>
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.
66
<PAGE>
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
YEARS ENDED DECEMBER 31, 1998, 1997 AND 1996
NOTE 5 ACCOUNTING FOR THE EFFECTS OF REGULATION (CONTINUED)
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.
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
--------- ---------
--------- ---------
</TABLE>
- ------------------------
(a) Excludes $125 million in 1998 and $135 million in 1997 of investment tax
credit regulatory liabilities.
67
<PAGE>
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
YEARS ENDED DECEMBER 31, 1998, 1997 AND 1996
NOTE 5 ACCOUNTING FOR THE EFFECTS OF REGULATION (CONTINUED)
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.
68
<PAGE>
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
YEARS ENDED DECEMBER 31, 1998, 1997 AND 1996
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.
69
<PAGE>
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
YEARS ENDED DECEMBER 31, 1998, 1997 AND 1996
NOTE 7 SHORT-TERM DEBT AND BORROWING ARRANGEMENTS
The Companies' short-term debt and borrowing arrangements were as follows:
<TABLE>
<CAPTION>
AVERAGE
INTEREST
DECEMBER 31/MILLIONS OF DOLLARS BALANCE 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
</TABLE>
- ------------------------
(a) Computed by dividing the total interest on principal amounts outstanding at
the end of the period by the weighted daily principal amounts outstanding.
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.
70
<PAGE>
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
YEARS ENDED DECEMBER 31, 1998, 1997 AND 1996
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
--------- ---------
--------- ---------
</TABLE>
- ------------------------
(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.
71
<PAGE>
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
YEARS ENDED DECEMBER 31, 1998, 1997 AND 1996
NOTE 8 LONG-TERM DEBT (CONTINUED)
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.
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
- ------------------------------------------------------------------------------------------------- --------- ---------
<C> <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>
72
<PAGE>
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
YEARS ENDED DECEMBER 31, 1998, 1997 AND 1996
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.
The table below summarizes the stock option activity under the Plan.
<TABLE>
<CAPTION>
WEIGHTED
AVERAGE NUMBER OF
PRICE 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,
73
<PAGE>
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
YEARS ENDED DECEMBER 31, 1998, 1997 AND 1996
NOTE 10 COMMON AND PREFERRED STOCK (CONTINUED)
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>
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
74
<PAGE>
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
YEARS ENDED DECEMBER 31, 1998, 1997 AND 1996
NOTE 10 COMMON AND PREFERRED STOCK (CONTINUED)
preference amount per share plus accrued dividends. Any premium paid on
redemptions of preferred stock is capitalized, and recovery is sought through
future rates.
<TABLE>
<CAPTION>
PREFERRED STOCK OUTSTANDING
THOUSANDS OF SHARES/MILLIONS OF DOLLARS 1998 AND 1997
DECEMBER 31 --------------------
SERIES SHARES AMOUNT
- -------------------------------------------------------------------------------------------- --------- ---------
<S> <C> <C>
SUBJECT TO MANDATORY REDEMPTION
No Par Serial Preferred, $100 stated value, 16,000 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.
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
75
<PAGE>
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
YEARS ENDED DECEMBER 31, 1998, 1997 AND 1996
NOTE 11 FINANCIAL INSTRUMENTS AND RISK MANAGEMENT (CONTINUED)
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
76
<PAGE>
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
YEARS ENDED DECEMBER 31, 1998, 1997 AND 1996
NOTE 11 FINANCIAL INSTRUMENTS AND RISK MANAGEMENT (CONTINUED)
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>
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.
77
<PAGE>
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
YEARS ENDED DECEMBER 31, 1998, 1997 AND 1996
NOTE 11 FINANCIAL INSTRUMENTS AND RISK MANAGEMENT (CONTINUED)
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>
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.
78
<PAGE>
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
YEARS ENDED DECEMBER 31, 1998, 1997 AND 1996
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.
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.
79
<PAGE>
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
YEARS ENDED DECEMBER 31, 1998, 1997 AND 1996
NOTE 13 COMMITMENTS AND CONTINGENCIES (CONTINUED)
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 noncancellable operating leases are $6
million, $5 million, $5 million, $4 million and $3 million for 1999 through
2003, respectively.
Jointly Owned Facilities--At December 31, 1998, Domestic Electric
Operations' participation in jointly owned facilities was as follows:
<TABLE>
<CAPTION>
ELECTRIC PLANT CONSTRUCTION
OPERATIONS' 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 --
</TABLE>
- ------------------------
(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.
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
80
<PAGE>
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
YEARS ENDED DECEMBER 31, 1998, 1997 AND 1996
NOTE 13 COMMITMENTS AND CONTINGENCIES (CONTINUED)
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.
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
--------- -----
--------- -----
</TABLE>
- ------------------------
(a) Annual costs, in millions of dollars, include debt service of $7.6 million.
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
81
<PAGE>
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
YEARS ENDED DECEMBER 31, 1998, 1997 AND 1996
NOTE 14 INCOME TAXES (CONTINUED)
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>
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>
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>
82
<PAGE>
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
YEARS ENDED DECEMBER 31, 1998, 1997 AND 1996
NOTE 14 INCOME TAXES (CONTINUED)
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.
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.
83
<PAGE>
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
YEARS ENDED DECEMBER 31, 1998, 1997 AND 1996
NOTE 15 EMPLOYMENT BENEFIT PLANS (CONTINUED)
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>
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
--------- ---------
--------- ---------
</TABLE>
84
<PAGE>
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
YEARS ENDED DECEMBER 31, 1998, 1997 AND 1996
NOTE 15 EMPLOYMENT BENEFIT PLANS (CONTINUED)
<TABLE>
<CAPTION>
FOR THE YEAR/MILLIONS OF DOLLARS 1998 1997
- ------------------------------------------------------------------------------------------- --------- ---------
<S> <C> <C>
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 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.
85
<PAGE>
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
YEARS ENDED DECEMBER 31, 1998, 1997 AND 1996
NOTE 15 EMPLOYMENT BENEFIT PLANS (CONTINUED)
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
--------- ---------
--------- ---------
</TABLE>
86
<PAGE>
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
YEARS ENDED DECEMBER 31, 1998, 1997 AND 1996
NOTE 15 EMPLOYMENT BENEFIT PLANS (CONTINUED)
<TABLE>
<CAPTION>
FOR THE YEAR/MILLIONS OF DOLLARS 1998 1997
- --------------------------------------------------------------------------------------------- --------- ---------
<S> <C> <C>
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
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
87
<PAGE>
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
YEARS ENDED DECEMBER 31, 1998, 1997 AND 1996
NOTE 16 ACQUISITIONS AND DISPOSITIONS (CONTINUED)
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 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
88
<PAGE>
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
YEARS ENDED DECEMBER 31, 1998, 1997 AND 1996
NOTE 17 SEGMENT INFORMATION (CONTINUED)
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>
89
<PAGE>
SELECTED FINANICAL 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
--------- --------- --------- --------- ---------
--------- --------- --------- --------- ---------
</TABLE>
- --------------------------
(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.
90
<PAGE>
DOMESTIC ELECTRIC OPERATIONS (UNAUDITED)
<TABLE>
<CAPTION>
5-YEAR
1998 TO 1997 COMPOUND
FOR THE YEAR/MILLIONS OF DOLLARS, EXCEPT PERCENTAGE ANNUAL
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)
</TABLE>
- --------------------------
* Not a meaningful number.
(a) Does not reflect elimination of interest on intercompany borrowing
arrangements and includes income taxes on a separate-company basis.
91
<PAGE>
DOMESTIC ELECTRIC OPERATIONS STATISTICS (UNAUDITED)
<TABLE>
<CAPTION>
5-YEAR
1998 TO 1997 COMPOUND
PERCENTAGE ANNUAL
FOR THE YEAR/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
</TABLE>
- ------------------------------
(a) Excludes off-system sales.
(b) Includes firm off-system sales.
(c) Generating capability and firm purchases at time of firm peak.
92
<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
--------- --------- --------- ---------
--------- --------- --------- ---------
</TABLE>
- ------------------------------
* 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.
93
<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
</TABLE>
- ------------------------
(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.
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<PAGE>
SUPPLEMENTAL INFORMATION
QUARTERLY FINANCIAL DATA (UNAUDITED)
<TABLE>
<CAPTION>
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 0.27 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
95
<PAGE>
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.
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
FINANCIAL DISCLOSURE
No information is required to be reported pursuant to this item.
PART III
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT
The PacifiCorp board is divided into three classes: Class I, Class II and
Class III, each class as nearly equal in number as possible. The directors in
each class hold office for three-year terms. The table below includes
information with respect to each director's business experience for the past
five years.
<TABLE>
<CAPTION>
DIRECTOR
NAME, AGE, CLASS, PRINCIPAL OCCUPATION AND OTHER DIRECTORSHIPS SINCE
- -------------------------------------------------------------------------------------------------------- -----------
<S> <C>
W. Charles Armstrong, 54 (Class I, 2000)................................................................ 1996
Consultant, East Sound, Washington; formerly Chief Executive Officer of Epitope, Inc., May-November
1997; Chief Executive Officer, Bank of America Oregon, 1992-1996; Director of Epitope, Inc.,
Agritope, Inc. and PacifiCorp Group Holdings Company
C. Todd Conover, 59 (Class I, 2000)..................................................................... 1991
Managing Director, Starmont Asset Management, LLC, San Francisco, California since 1998 and
President and Chief Executive Officer, The Vantage Company, a business consulting firm, Los Altos,
California, since 1992; formerly General Manager, Finance Industry Group, Tandem Computers
Incorporated, 1994-1995; Director of Blount International, Inc., Tracy Bankshares, Inc. and
PacifiCorp Group Holdings Company.
Nolan E. Karras, 54 (Class I, 2000)..................................................................... 1993
President, The Karras Company, Inc., investment advisers, Roy, Utah, since 1983; formerly Member of
Utah House of Representatives, 1981-1990; Speaker of the House, 1989-1990; Director of PacifiCorp
Group Holdings Company.
Kathryn Braun Lewis, 47 (Class II, 2001)................................................................ 1994
formerly President and Chief Operating Officer, Storage Division, since 1997, and Executive Vice
President, Western Digital Corporation, a computer equipment company, Irvine, California, 1978-1998;
Director of PacifiCorp Group Holdings Company and Artisoft, Inc.
Keith R. McKennon, 65 (Class I, 2000)................................................................... 1990
Chairman of the PacifiCorp Board, since 1994, and President and Chief Executive Officer, since 1998;
formerly Chairman (1992-1994) and Chief Executive Officer (1992-1993), Dow Corning Corporation,
Midland, Michigan; Chairman of the Board, PacifiCorp Group Holdings Company.
</TABLE>
96
<PAGE>
<TABLE>
<CAPTION>
DIRECTOR
NAME, AGE, CLASS, PRINCIPAL OCCUPATION AND OTHER DIRECTORSHIPS SINCE
- -------------------------------------------------------------------------------------------------------- -----------
<S> <C>
Robert G. Miller, 54 (Class II, 2001)................................................................... 1994
Vice Chairman and Chief Executive Officer, since 1998, formerly President and Chief Executive
Officer, since 1997, and Chairman, Fred Meyer, Inc., a retail merchandising company, Portland,
Oregon, since 1991; Director of PacifiCorp Group Holdings Company, SMG II Holdings Corporation and
Path Mark Stores, Inc.
Alan K. Simpson, 67 (Class II, 2001).................................................................... 1997
formerly U.S. Senator, 1976-1996; Director of PacifiCorp Group Holdings Company, IDS Mutual Fund
Group and Biogen Corporation.
Verl R. Topham, 64 (Class II, 2001)..................................................................... 1994
Senior Vice President and General Counsel of PacifiCorp since 1994; formerly President, Utah Power &
Light Company, 1990-1994; Director of PacifiCorp Group Holdings Company and Powercor Australia, Ltd.
Mr. Topham will retire as an employee of PacifiCorp as of May 1, 1999.
Nancy Wilgenbusch, 51 (Class III, 1999)................................................................. 1986
President, Marylhurst University, Portland, Oregon, since 1984; Director of Federal Reserve Bank of
San Francisco, Portland Branch, Cascade Corporation; PacifiCorp Group Holdings Company and Powercor
Australia Ltd.
Peter I. Wold, 51, (Class III, 1999).................................................................... 1995
Partner, Wold Oil & Gas Company, an oil and gas exploration and production company, Casper, Wyoming,
since 1981; Director of Federal Reserve Bank of Kansas City, Denver Branch, and PacifiCorp Group
Holdings Company.
</TABLE>
The information required by this item with respect to PacifiCorp's executive
officers is set forth in Part I of this report under Item 4A. There are no
family relationships among the directors and executive officers of PacifiCorp.
Section 16(a) of the Securities Exchange Act of 1934 requires PacifiCorp's
executive officers and directors, and persons who own more than 10% of the
PacifiCorp common stock outstanding, to file reports of ownership and changes in
ownership with the Securities and Exchange Commission and the New York Stock
Exchange. Based solely on reports and other information submitted by executive
officers and directors, PacifiCorp believes that during the year ended December
31, 1998, each of its executive officers, directors and persons who own more
than 10% of the PacifiCorp common stock outstanding filed all reports required
by Section 16(a).
ITEM 11. EXECUTIVE COMPENSATION
DIRECTOR COMPENSATION AND CERTAIN TRANSACTIONS
PacifiCorp's non-officer directors are compensated for their board service
by a combination of cash and PacifiCorp common stock under a non-employee
directors' stock compensation plan that seeks to increase the community of
interest between PacifiCorp's shareholders and its directors. Under this plan,
non-employee directors of PacifiCorp are granted approximately $75,000 worth of
PacifiCorp common stock every five years. Non-employee directors having fewer
than five years of service remaining before reaching retirement age receive
stock valued at approximately $15,000 for each remaining year. Stock granted
under this plan vests over the five-year period following the grant or shorter
period to retirement, and unvested shares are forfeited if the recipient ceases
to be a director. The shares are purchased in the
97
<PAGE>
market with funds supplied by PacifiCorp, and the certificates are then held by
PacifiCorp until the shares vest. During 1998, an aggregate of 13,894 shares
previously granted under the plan vested.
PacifiCorp's non-officer directors receive the balance of their compensation
in cash. They are paid $16,000 per year plus $1,000 for each PacifiCorp board or
committee meeting attended. Until his election as President and Chief Executive
Officer in 1998, Mr. McKennon was paid annually with PacifiCorp common stock
valued at $155,000 for his service as Chairman of the Board, plus his $15,000
per year participation in the non-employee directors' stock compensation plan.
Members of the Executive Committee and chairs of the other committees of the
PacifiCorp board are paid an additional $2,500 per year. Non-employee members of
the regional boards are paid $9,000 per year plus $1,000 for each board or
subcommittee meeting attended. In addition, members of the Utah Board who are
former directors of Utah Power & Light Company participate in a retirement plan
under which they are eligible to receive benefits of $560 per month upon
retirement at age 65 or older and certain death benefits.
During 1998, Messrs. Conover and Karras received $11,000 and $12,000 in
directors' fees, respectively, from PacifiCorp Group Holdings Company; Dr.
Wilgenbusch received $7,500 in directors' fees from Powercor Australia Ltd.
Don M. Wheeler, who retired as a PacifiCorp director on February 10, 1999,
was Chairman and Chief Executive Officer of Wheeler Machinery Company, a company
engaged in sales and service of large earth-moving and grading equipment,
engines and related machinery, until July 1996 when he became Chairman and Chief
Executive Officer of ICM Equipment Company ("ICM"). ICM is a materials handling
and rental services company serving industrial construction and mining markets
in the intermountain area and a former division of Wheeler Machinery Company.
Mr. Wheeler continued to serve as a director of Wheeler Machinery Company until
his resignation in April 1998. In January 1998, the assets of ICM were sold to
ICM Equipment Company L.L.C. Mr. Wheeler owns a significant interest in ICM
Equipment Company and serves as its Chairman and Chief Executive Officer.
During 1998, PacifiCorp and its subsidiaries purchased equipment and
services from Wheeler Machinery Company in the ordinary course of business for a
total of approximately $757,904. Of this amount, $336,526 was purchased from ICM
and $421,378 was purchased from Wheeler Machinery Company. Richard E. Wheeler,
Mr. Wheeler's brother, is the owner of Wyoming Machinery Company. During 1998,
PacifiCorp and its subsidiaries purchased equipment and services from Wyoming
Machinery Company in the ordinary course of business for a total of
approximately $9,012,874. PacifiCorp believes that the terms of these
transactions were no less favorable to PacifiCorp than those available from
other parties. Similar purchases have been made by PacifiCorp or its
predecessors from these companies since 1951.
PERSONNEL COMMITTEE REPORT ON EXECUTIVE COMPENSATION
The Personnel Committee of the PacifiCorp board, which is composed entirely
of independent, non-employee directors, is responsible for approving
compensation levels for officers of PacifiCorp, administering executive
compensation plans as authorized by the PacifiCorp board and recommending
executive compensation plans and compensation of the Chief Executive Officer to
the PacifiCorp board for approval. The committee is also responsible for
approving incentive plans for all employees, salary structure and merit programs
for senior management and changes in policy relating to employee benefits. The
following report of the Personnel Committee describes the components of
PacifiCorp's executive compensation program and the basis upon which 1998
compensation determinations were made.
98
<PAGE>
COMPENSATION PHILOSOPHY
PacifiCorp's philosophy is that executive compensation should be linked
closely to corporate performance and increases in shareholder value.
PacifiCorp's compensation program has the following objectives:
- Provide competitive total compensation that enables PacifiCorp to attract
and retain key executives.
- Provide variable compensation opportunities that are linked to company and
individual performance.
- Establish an appropriate balance between incentives focused on short-term
objectives and those encouraging sustained earnings performance and
increases in shareholder value.
Qualifying compensation for deductibility under IRC Section 162(m) is one of
the factors the committee considers in designing its incentive compensation
arrangements. IRC Section 162(m) limits to $1,000,000 the annual deduction by a
publicly held corporation of compensation paid to any executive, except with
respect to certain forms of incentive compensation that qualify for exclusion.
Although it is the committee's intent to design and administer compensation
programs that maximize deductibility, the committee views the objectives
outlined above as more important than compliance with the technical requirements
necessary to exclude compensation from the deductibility limit of IRC Section
162(m). Nevertheless, the committee believes that nearly all compensation paid
to the current executive officers for services rendered in 1998 is fully
deductible.
COMPENSATION PROGRAM COMPONENTS
The Personnel Committee, assisted by its outside consultant, evaluates the
total compensation package of executives annually in relation to competitive pay
levels. Given the increasingly competitive global environment in which
PacifiCorp must operate and the competitive marketplace for executive talent
required for future success, in 1996 PacifiCorp reevaluated its historical
practice of using the electric utility industry as its primary market reference
point. In 1997, the committee began using the general industry as the market
reference base for long-term incentive purposes. The transition of base salary
and annual incentives to the relevant industry was expected to be accomplished
over a three-year time frame.
In 1998, the committee continued the transition by focusing its market-based
comparisons on the relevant industry for each officer. The committee utilized
the electric utility industry as its exclusive basis for market comparison for
positions with a principal focus on electric operations. For positions with a
corporate-wide focus, the committee began the transition toward general industry
comparisons by using a weighting of approximately 67% general industry and 33%
electric utility industry.
Although most of the electric utility companies represented in the
performance graph set forth below are part of PacifiCorp's comparison group, not
all of these companies are considered PacifiCorp's competitors for executive
talent. For officers with responsibilities outside the electric operations,
relevant industry data were used for comparison. In all cases, compensation is
targeted at market median levels, with a recognition that total compensation
greater than market median requires, in any specific time period, that company
performance exceed the median performance of peer companies.
PacifiCorp's executive compensation programs have three principal elements:
base salary, annual incentive compensation and long-term incentive compensation,
as described below.
BASE SALARIES
Base salaries and target incentive amounts are reviewed for adjustment at
least annually based upon competitive pay levels, individual performance and
potential, and changes in duties and responsibilities. Base salary and the
incentive target are set at a level such that total annual compensation for
satisfactory performance would approximate the midpoint of pay levels in the
comparison group used to develop competitive data. In 1998, the base salaries of
executive officers were increased, based on market analysis,
99
<PAGE>
within a range of zero to 20% to reflect competitive market changes and changes
in the responsibilities of some officers.
ANNUAL INCENTIVES
All electric operations employees participated in an annual incentive plan
during 1998. Awards under the plan were to be earned based upon such factors as
company earnings per share and business unit performance in relation to
established objectives. The relative weights of the performance criteria varied
among organizational units in accordance with the nature of their operations.
All corporate officers, including those listed in the Summary Compensation
Table, participated in the PacifiCorp executive incentive program. Performance
goals included company earnings per share. All executive incentive program
participants may have their incentive awards modified (in the range of zero to
120%) by their individual performance, relative to established objectives, as
evaluated by their immediate supervisor. The maximum allowable award from the
executive incentive program for all participants is 150% of their guideline
award. As PacifiCorp did not achieve the earnings per share target established
for the year, neither the Chief Executive Officer nor the Chief Operating
Officer received an award for 1998 performance. Other executive officers listed
in the Summary Compensation Table received from 10% to about 32% of their
guideline awards based upon achieving certain business unit performance
objectives for the year. Other executive officers also received partial target
incentive awards based upon achieving business unit performance objectives.
LONG-TERM INCENTIVES
The Personnel Committee approved grants of restricted stock and stock
options in early 1998 under the Stock Incentive Plan. The committee considered
such criteria as:
- total shareholder return relative to peer companies;
- earnings per share growth over time relative to peer companies;
- achievement of long-term goals, strategies and plan; and
- maintenance of competitive position.
Based on a subjective assessment of these criteria, PacifiCorp established a
pool of restricted stock equal to 100% of competitive award levels. The shares
in the pool were allocated to participants based on individual performance. The
committee also approved grants of stock options based upon competitive award
levels and special stock option awards based on achievement of significant stock
appreciation during 1997. The committee concluded that the use of stock options
to reward performance contributing to the stock appreciation was appropriate and
would result in long-term benefit to the recipients only if the stock price
increased.
Restricted stock awards under the Stock Incentive Plan are subject to terms,
conditions and restrictions as may be determined by the committee to be
consistent with the plan and the best interests of the shareholders. The
restrictions include stock transfer restrictions and forfeiture provisions
designed to facilitate the participants' achievement of specified stock
ownership goals. Participants are also required to invest their own personal
resources in PacifiCorp common stock in order to meet the vesting requirements
associated with these grants. The Summary Compensation Table below shows the
grants of restricted stock made to the listed executive officers under the plan
in 1998 and under the PacifiCorp Long-Term Incentive Plan for 1996 and 1997.
During 1998, the committee established a restricted stock program that would
govern future grants of restricted stock. This program includes objective
performance criteria and involves a two-part process. The first part involves
establishing a pool of shares by adjusting competitive award levels by a formula
which includes a measure of three-year average total shareholder return
performance relative to a peer group
100
<PAGE>
and a subjective assessment by the committee of performance relative to
established strategic goals and objectives, other than shareholder return. Total
shareholder return accounts for 75% of the formula and the remaining 25% will be
subjectively determined. The peer group is comprised of the companies that make
up the S & P Electrics Index. Once the size of the pool is established,
restricted stock awards, if any, will be allocated considering individual
performance.
All stock options awarded to officers and senior management of PacifiCorp in
1998 are non-statutory, non-discounted options with a three-year vesting
requirement and a ten-year term to exercise from the date of the grant. Grants
of stock options in 1997 and 1998 to named executives are shown in the table
below.
In May 1998, the committee also approved a grant of non-statutory and
non-discounted stock options to all employees except officers and senior
managers. Full-time employees received options for 100 shares while part-time
employees were granted options for 75 shares. These grants become fully vested
two years from the grant, and employees have ten years to exercise option
shares.
CHANGE-IN-CONTROL
In 1998, the Personnel Committee, with the assistance of outside
consultants, reviewed the change-in-control provisions in all of PacifiCorp's
compensation and benefit plans and found that the definition of
change-in-control, as well as the provisions associated with the
change-in-control, varied significantly from plan to plan. The committee
recommended adoption of a common definition of change-in-control, which was
approved by the PacifiCorp board. The PacifiCorp board also amended several
plans to change the provisions relating to change-in-control. These amendments
include changes to the annual and long-term incentive programs summarized below:
- Executives would receive a payment of a bonus in an amount no less than
their target bonus award in the year of a qualifying change-in-control.
- Stock options and restricted stock awards granted prior to 1999 would
become fully vested upon a qualifying change-in-control.
Amendments to the PacifiCorp executive severance plan and the supplemental
executive retirement plan are described under "Executive Compensation" below.
COMPENSATION OF THE CHIEF EXECUTIVE OFFICER
In February 1998, the PacifiCorp board approved a grant of 21,000 restricted
shares of PacifiCorp common stock to Mr. Buckman under the Stock Incentive Plan
based upon a review of company performance during 1997. The PacifiCorp board
also granted to Mr. Buckman, in February 1998, non-qualified stock options for
276,000 shares of PacifiCorp common stock as part of its effort to provide
motivation for future stock price appreciation. Additionally, the PacifiCorp
board approved a special grant to Mr. Buckman of non-qualified stock options for
80,000 shares of PacifiCorp common stock to reward achievement of strategic
initiatives during 1997 that resulted in added shareholder value, as reflected
in increased total shareholder return. In May 1998, the PacifiCorp board
approved a salary increase of 14.72% for Mr. Buckman.
On September 1, 1998, Mr. Buckman resigned as Chief Executive Officer and
President after discussions with the PacifiCorp board about disappointing
company performance. The committee approved severance pay and benefits as part
of Mr. Buckman's separation package. The details of these arrangements are
provided in the compensation tables that follow this report.
In September 1998, Mr. McKennon assumed Mr. Buckman's responsibilities as
Chief Executive Officer and, later, President in addition to his role as
Chairman of the Board. The Personnel Committee approved an employment agreement
with Mr. McKennon that provided him with a base salary of $780,000
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<PAGE>
and set a target incentive award for 1998 of 20% of his prorated salary for
1998. No incentive award was earned by Mr. McKennon for 1998. Mr. McKennon's
employment agreement supersedes and replaces his agreement for compensation as
Chairman of the Board for so long as he remains Chief Executive Officer. Mr.
McKennon's employment agreement provides for participation in the executive
long-term incentive programs described above, although no restricted shares or
stock options were granted to him in 1998.
Mr. McKennon has waived participation in the executive severance plan and
the supplemental executive retirement plan as part of his employment agreement.
The Personnel Committee believes that Mr. McKennon's compensation pursuant to
his employment agreement provides a competitive base salary based on market
comparisons. However, as a result of Mr. McKennon's decision to waive
participation in the executive severance and supplemental executive retirement
plans, the committee believes that his total compensation is below PacifiCorp's
goal of providing competitive total compensation.
PERSONNEL COMMITTEE
Nolan E. Karras, Chair
W. Charles Armstrong
Kathryn Braun Lewis
Robert G. Miller
Nancy Wilgenbusch
102
<PAGE>
COMPARISON OF FIVE YEAR CUMULATIVE TOTAL RETURN
AMONG PACIFICORP, S&P 500 INDEX AND THE S&P ELECTRICS INDEX
The following graph provides comparisons of the annual percentage change in
the cumulative total shareholder return on PacifiCorp common stock, with the
cumulative total return of (a) the S&P 500 Index, and (b) the S&P Electrics
Index. The comparisons assume that $100 was invested on December 31, 1993 in
PacifiCorp common stock and in each of the foregoing indices and assumes the
reinvestment of dividends.
COMPARISON OF FIVE YEAR CUMULATIVE TOTAL RETURN
EDGAR REPRESENTATION OF DATA POINTS USED IN PRINTED GRAPHIC
<TABLE>
<CAPTION>
PACIFICORP S & P 500 S & P ELECTRICS
<S> <C> <C> <C>
1993 $100.00 $100.00 $100.00
1994 $100.15 $101.36 $87.04
1995 $123.32 $139.31 $113.97
1996 $125.95 $171.21 $113.56
1997 $175.81 $228.26 $143.16
1998 $142.45 $293.36 $165.02
</TABLE>
<TABLE>
<CAPTION>
1993 1994 1995 1996 1997 1998
--------- --------- --------- --------- --------- ---------
<S> <C> <C> <C> <C> <C> <C>
PacifiCorp.................................. $ 100.00 100.15 123.32 125.95 175.81 142.45
S & P 500................................... $ 100.00 101.36 139.31 171.21 228.26 293.36
S & P Electrics............................. $ 100.00 87.04 113.97 113.56 143.16 165.02
</TABLE>
103
<PAGE>
EXECUTIVE COMPENSATION
The following table sets forth information concerning compensation for
services in all capacities to PacifiCorp and its subsidiaries for fiscal years
ended December 31, 1998, 1997 and 1996 of those persons who were the Chief
Executive Officer of PacifiCorp during any portion of 1998 and the four other
most highly compensated executive officers of PacifiCorp during 1998.
SUMMARY COMPENSATION TABLE
<TABLE>
<CAPTION>
LONG-TERM COMPENSATION
ANNUAL COMPENSATION(1) -------------------------
------------------------ RESTRICTED SECURITIES ALL OTHER
SALARY BONUS STOCK AWARDS UNDERLYING COMPENSATION
NAME AND PRINCIPAL POSITION YEAR ($)(2) ($)(3) ($)(4) OPTIONS(#) ($)(5)
- ---------------------------------- --------- ------------ ---------- ------------ ----------- -------------
<S> <C> <C> <C> <C> <C> <C>
Keith R. McKennon ................ 1998 $ 363,349 -- (7) -- $ 1,785
President and Chief Executive
Officer(6)
Frederick W. Buckman ............. 1998 $ 1,474,602(9) -- $ 509,250 356,000 $ 9,326
President and Chief Executive 1997 635,004 -- 469,848 165,000 9,022
Officer(8) 1996 590,000 $ 486,750 498,419 -- 8,350
Richard T. O'Brien ............... 1998 $ 348,046 -- $ 194,000 111,000 $ 8,252
Executive Vice President and 1997 287,500 -- 127,530 41,000 7,690
Chief Operating Officer 1996 215,627 $ 135,000 505,557 -- 7,811
Dennis P. Steinberg .............. 1998 $ 317,502 $ 13,400 $ 169,750 86,000 $ 8,628
Senior Vice President 1997 280,002 -- 145,429 41,000 8,010
1996 220,008 132,000 469,292 -- 7,817
John A. Bohling .................. 1998 $ 307,500 $ 40,257 $ 121,250 66,000 $ 12,050
Senior Vice President 1997 285,000 -- 145,429 41,000 10,092
1996 240,000 144,000 169,292 -- 7,846
Verl R. Topham ................... 1998 $ 300,000 $ 31,500 $ 138,225 80,000 $ 9,404
Senior Vice President and 1997 277,500 -- 127,530 35,000 8,737
General Counsel 1996 270,000 162,000 281,190 -- 7,889
</TABLE>
- ------------------------
(1) May include amounts deferred pursuant to the Compensation Reduction Plan,
under which key executives and directors may defer, until retirement or a
preset future date, receipt of cash compensation to a stock account to be
invested in PacifiCorp common stock or to a cash account on which interest
is paid at a rate equal to the Moody's Intermediate Corporate Bond Yield for
Aa rated Public Utility Bonds.
(2) Base salary for named officers did not increase in 1996. 1997 increases in
annual compensation include both increases in base salary and lump sum
payments that were effective July 1, 1997. Allocations between a base salary
increase and a lump sum payment differed among officers.
(3) Please refer to the Personnel Committee Report on Executive Compensation
for a description of PacifiCorp's annual executive incentive plans.
Incentive amounts are reported for the year in which the related services
were performed.
(4) Includes restricted stock grants made in (a) February 1998, 1997 and 1996
pursuant to the Long-Term Plan, (b) March 1996 as special recognition for
1995 performance and (c) August 1996 under the Stock Incentive Plan. In
general, restricted stock awards vest over a four-year period from the date
of grant, subject to compliance with the stock ownership and other terms of
the grant. At December 31,
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<PAGE>
1998, the aggregate value of all restricted stock holdings, based on the
market value of the shares at December 31, 1998, without giving effect to
the diminution of value attributed to the restrictions on such stock, and
the aggregate number of restricted share holdings of Messrs. O'Brien,
Steinberg, Bohling and Topham were $717,974, $679,387, $321,316 and $439,880
and 34,087, 32,255, 15,255 and 20,884, respectively. Mr. Buckman resigned on
September 1, 1998 and, thereafter, his 51,963 shares of restricted stock
became fully vested. These shares had a market value of $1,043,417 as of
October 23, 1998. Regular quarterly dividends are paid on the restricted
stock. Participants may defer receipt of restricted stock awards to their
stock accounts under the Compensation Reduction Plan.
(5) Amounts shown for 1998 include (a) contributions of $8,000 to the
PacifiCorp K Plus Employee Savings and Stock Ownership Plan for each of
Messrs. Buckman, O'Brien, Steinberg, Bohling and Topham and (b) portions of
premiums on term life insurance policies which PacifiCorp paid for Messrs.
McKennon, Buckman, O'Brien, Steinberg, Bohling and Topham in the amounts of
$1,785, $1,326, $252, $628, $4,050 and $1,404, respectively. These benefits
are available to all employees.
(6) Mr. McKennon became President and Chief Executive Officer after Mr.
Buckman's resignation in September 1998. The amount listed under "Salary"
for Mr. McKennon includes $109,538 paid in PacifiCorp common stock for his
service as Chairman of the PacifiCorp board prior to his election as
President and Chief Executive Officer, and $18,159 paid in PacifiCorp common
stock as a result of his participation in the non-employee directors' stock
compensation plan through September 1, 1998.
(7) Mr. McKennon was compensated as Chairman of the Board in restricted shares
of PacifiCorp common stock. In September 1998, when Mr. McKennon accepted
the position of Chief Executive Officer, his unvested restricted stock
granted under the non-employee directors' stock compensation plan was
forfeited.
(8) Mr. Buckman resigned as President and Chief Executive Officer on September
1, 1998.
(9) Includes $939,600 of severance compensation. Mr. Buckman's restricted stock
awards vested as a consequence of his employment separation. He will receive
additional cash severance payments in 1999 and 2000 of $1,098,000 and
$1,000,000, respectively.
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<PAGE>
OPTION GRANTS IN LAST FISCAL YEAR
<TABLE>
<CAPTION>
INDIVIDUAL GRANTS
------------------------------------------------------ POTENTIAL REALIZABLE VALUE
NUMBER OF AT ASSUMED ANNUAL RATES OF
SECURITIES % OF TOTAL STOCK PRICE APPRECIATION
UNDERLYING OPTION GRANTED EXERCISE OR FOR OPTION TERM
OPTION TO EMPLOYEES IN BASE PRICE EXPIRATION --------------------------
NAME GRANTED(1) FISCAL YEAR ($/SH) DATE 5% ($) 10% ($)
- ---------------------------------- ----------- --------------- ----------- ----------- ------------ ------------
<S> <C> <C> <C> <C> <C> <C>
Frederick W. Buckman(2)........... 356,000 10.26% $ 24.00 2/10/08 N/A N/A
Keith R. McKennon................. -- -- -- -- -- --
Richard T. O'Brien................ 111,000 3.20% $ 24.00 2/10/08 $ 1,675,375 $ 4,245,730
Dennis P. Steinberg............... 86,000 2.48% $ 24.00 2/10/08 $ 1,298,039 $ 3,289,484
John A. Bohling................... 66,000 1.90% $ 24.00 2/10/08 $ 996,169 $ 2,524,488
Verl R. Topham.................... 80,000 2.31% $ 24.00 2/10/08 $ 1,207,478 $ 3,059,986
</TABLE>
- ------------------------
(1) All options become exercisable for one-third of the shares covered by the
option on each of the first three anniversaries of the grant date. The grant
date for each option shown in the table above was February 10, 1998. All
options become fully exercisable upon a qualifying "change in control" of
PacifiCorp or an "employer disposition," each as defined in the applicable
option agreement. A "change in control" generally includes (a) the
acquisition by any person of 20% or more of PacifiCorp common stock and (b)
the election of a new majority of PacifiCorp's directors. An "employer
disposition" generally includes a disposition by PacifiCorp of all of its
equity ownership in the optionee's employer.
(2) Mr. Buckman forfeited all of the options granted on February 10, 1998 upon
his resignation.
AGGREGATED OPTION EXERCISES IN LAST FISCAL YEAR
AND FY-END OPTION VALUES
<TABLE>
<CAPTION>
NUMBER OF SECURITIES VALUE OF UNEXERCISED
SHARES UNDERLYING UNEXERCISED IN-THE-MONEY OPTIONS
ACQUIRED ON OPTIONS AT FY-END (#) AT FY-END ($)
EXERCISE VALUE ----------------------- -----------------------
NAME (#) REALIZED ($) EXERCISABLE/UNEXERCISABLE EXERCISABLE/UNEXERCISABLE
- ----------------------------------- ----------- ------------ ----------------------- -----------------------
<S> <C> <C> <C> <C>
Frederick W. Buckman(1)............ 55,000 19,421.58 -- --
Keith R. McKennon.................. -- -- -- --
Richard T. O'Brien................. -- -- 13,667/152,000 $ 17,945/$53,833
Dennis P. Steinberg................ -- -- 13,667/127,000 $ 17,945/$53,833
John A. Bohling.................... -- -- 13,667/107,000 $ 17,945/$53,833
Verl R. Topham..................... -- -- 11,667/115,000 $ 15,319/$45,955
</TABLE>
- ------------------------
(1) Mr. Buckman forfeited all unvested options upon his resignation.
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<PAGE>
SEVERANCE ARRANGEMENTS
The Severance Plan provides severance benefits to certain executive level
employees who are designated by the Personnel Committee, in its sole discretion,
including the executive officers named in the Summary Compensation Table, other
than Mr. McKennon. To qualify for severance benefits, the executive must have
terminated employment for one of the following reasons:
(1) voluntary termination as a result of a material alteration in the
executive's assignment that has a detrimental impact on the executive's
employment. A "material alteration in assignment" includes any of the
following:
(a) a material reduction in the scope of the executive's duties and
responsibilities;
(b) a material reduction in the executive's authority; or
(c) any reduction in base pay or a reduction in annualized base salary
and target bonus of at least 15%, if the change is not due to a
general reduction unrelated to the change in assignment; or
(2) involuntary termination (including a company-initiated resignation) for
reasons other than for cause.
In addition, the Severance Plan provides enhanced severance benefits in the
event of certain terminations during the 24-month period following a qualifying
change-in-control transaction, including the consummation of the proposed merger
with ScottishPower described elsewhere in this report. Executives designated by
the Personnel Committee are eligible for change-in-control benefits resulting
from either a PacifiCorp-initiated termination without "cause", or a resignation
within two months after a "material alteration of position". During the 24-month
protection period under the Severance Plan, "cause" means the executive's gross
misconduct or gross negligence or conduct which indicates a reckless disregard
for the consequences and has a material adverse effect on PacifiCorp or its
affiliates, and "material alteration in position" means the occurrence of any of
the following:
(1) a change in reporting relationship to a lower level;
(2) a material reduction in the scope of duties and responsibilities;
(3) a material reduction in authority;
(4) a "material reduction in compensation"; or
(5) relocation of executive's work location to an office more than 100 miles
from the executive's office or more than 60 miles from the executive's
home.
A "material reduction in compensation" occurs when an executive's annualized
base salary is reduced by any amount or the annualized base salary and target
bonus opportunity combined is reduced by at least 15 percent of the combined
total opportunity before the change in compensation. In addition, for the Chief
Operating Officer, the Severance Plan has a "walkaway" right under which he
would be eligible for benefits if he resigns for any reason effective no earlier
than 12 months and no later than 14 months after the proposed merger with
ScottishPower becomes effective.
If qualified, an executive would receive severance pay in an amount equal to
either two, two and one-half or three times the "annual cash compensation" of
such executive, depending on the level set by the Personnel Committee. "Annual
cash compensation" is defined as annualized base salary, target annual incentive
opportunity and annualized auto allowance in effect on a material alteration or
termination, whichever is greater. If the payment would result in imposition of
an excise tax under IRC Section 4999, PacifiCorp is required to make an
additional payment to compensate the executive for the effect of such excise
tax. The executive would also receive continuation of subsidized health
insurance from six to
107
<PAGE>
24 months depending on length of service, and a minimum of 12 months'
executive-level outplacement services.
Other than in connection with a change-in-control, the definition of cause
is determined by PacifiCorp in its discretion and by the Personnel Committee in
the event of an appeal by the employee. The Severance Plan does not apply to the
termination of an executive for reasons of normal retirement, death or total
disability or to a termination for cause or for voluntary termination other than
as specified above. Other than in connection with a change-in-control,
executives named in the Summary Compensation Table (other than Mr. McKennon) are
eligible for a severance payment equal to twice the executive's total cash
compensation, three months of health insurance benefits and outplacement
benefits. Total cash compensation is defined as the annualized base salary,
target annual incentive opportunity and the annualized auto allowance in effect
on the earlier of a material alteration or termination.
During 1998, the Personnel Committee negotiated additional severance
benefits for Mr. Buckman, the details of which are set forth in the Summary
Compensation Table.
RETIREMENT PLANS
PacifiCorp and most of its subsidiaries have adopted noncontributory defined
benefit retirement plans for their employees, other than employees subject to
collective bargaining agreements that do not provide for coverage. Certain
executive officers, including the executive officers named in the Summary
Compensation Table (other than Mr. McKennon), are also eligible to participate
in PacifiCorp's non-qualified supplemental executive retirement plan. The
following description assumes participation in both the retirement plans and the
supplemental plan. Participants receive benefits at retirement payable for life
based on length of service with PacifiCorp or its subsidiaries and average pay
in the 60 consecutive months of highest pay out of the last 120 months, and pay
for this purpose would include salary and bonuses as reflected in the Summary
Compensation Table above. Benefits are based on 50% of final average pay plus up
to an additional 15% of final average pay depending upon whether PacifiCorp
meets certain performance goals set for each calendar year by the Personnel
Committee. Participants may also elect actuarially equivalent alternative forms
of benefits. Retirement benefits are reduced to reflect Social Security benefits
as well as certain prior employer retirement benefits. Participants are entitled
to receive full benefits upon retirement after age 60 with at least 15 years of
service. Participants are also entitled to receive reduced benefits upon early
retirement after age 55 or after age 50 with at least 15 years of service.
The supplemental plan provides executives "involuntarily terminated" during
the 24 months following the proposed ScottishPower merger, or who resign for any
reason effective no earlier than 12 months and no later than 14 months after the
merger, with enhanced supplemental retirement benefits. For purposes of the
plan, a termination of employment is "involuntary" if the participant is
discharged for reasons other than cause or resigns under certain circumstances
following a change-in-control. A resignation is treated as an involuntary
termination when any of the following occur:
(1) the executive's annualized base salary or target bonus opportunity is
decreased;
(2) the executive is reassigned to a position in an office located more than
100 miles from the executive's then-current office or 60 miles from the
executive's residence, whichever is greater;
(3) the executive's reporting level in PacifiCorp is changed and is lower
after the change than it was before;
(4) there is a material reduction in the scope of the executive's duties or
responsibilities; or
(5) there is a material reduction in the executive's authority.
Verl R. Topham, Senior Vice President and General Counsel, will retire as an
employee of PacifiCorp (but not as a director) as of May 1, 1999. PacifiCorp has
agreed to provide him with the equivalent of change of control benefits as set
forth above upon the date of the proposed merger ScottishPower. The
108
<PAGE>
change of control enhancements to the retirement benefits would apply to future
retirement benefits beginning the month following the date of the merger. The
other change of control benefits would be offset against any severance benefits
he has received before the date of the merger. It is currently anticipated that
three other PacifiCorp executives will be offered similar arrangements, although
PacifiCorp may determine that additional arrangements for a limited number of
other executives will be appropriate.
The following table shows the estimated annual retirement benefit payable
upon retirement at age 60 as of January 1, 1999. Amounts in the table reflect
payments from the retirement plans and the supplemental plan combined.
ESTIMATED ANNUAL PENSION AT RETIREMENT(1)
<TABLE>
<CAPTION>
YEARS OF SERVICE(2)
ANNUAL PAY AT ----------------------------------------------
RETIREMENT DATE 5 15 25 30
- --------------------------------------------- ---------- ---------- ---------- ----------
<S> <C> <C> <C> <C>
$ 200,000.................................... $ 43,333 $ 130,000 $ 130,000 $ 130,000
400,000.................................... 86,667 260,000 260,000 260,000
600,000.................................... 130,000 390,000 390,000 390,000
800,000.................................... 173,333 520,000 520,000 520,000
1,000,000................................... 216,667 650,000 650,000 650,000
</TABLE>
- ------------------------
(1) The benefits shown in this table assume that the individual will remain in
the employ of PacifiCorp until retirement at age 60, that the plans will
continue in their present form and that PacifiCorp achieves its performance
goals under the supplemental plan in all years. Amounts shown do not reflect
the Social Security offset.
(2) The number of credited years of service used to compute benefits under the
plans for Messrs. Buckman, O'Brien, Steinberg, Bohling and Topham are 4, 15,
20, 34 and 26, respectively. Mr. Buckman was not vested in any retirement
benefits at the time of separation of employment. Mr. McKennon is not a
participant in this plan.
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<PAGE>
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
The following table sets forth certain information as of April 28, 1999
regarding the beneficial ownership of PacifiCorp common stock by (1) each
director or nominee for director of PacifiCorp, (2) each of the executive
officers named in the Summary Compensation Table set forth under Item 11 above,
and (3) all executive officers and directors of PacifiCorp as a group. As of
April 28, 1999, each of the directors and executive officers identified below
and all executive officers and directors of PacifiCorp as a group owned less
than 0.3% of the PacifiCorp common stock outstanding. PacifiCorp knows of no
person who beneficially owns more than 5% of any class of PacifiCorp's stock.
BENEFICIAL OWNER
<TABLE>
<CAPTION>
NUMBER OF SHARES(1)
-------------------
<S> <C>
Directors
W. Charles Armstrong................................................... 3,887
Kathryn Braun Lewis.................................................... 4,260
C. Todd Conover........................................................ 13,249
Nolan E. Karras........................................................ 9,119
Keith R. McKennon...................................................... 46,804
Robert G. Miller....................................................... 4,286
Alan K. Simpson........................................................ 5,604
Verl R. Topham......................................................... 75,172
Nancy Wilgenbusch...................................................... 9,943
Peter I. Wold.......................................................... 11,567
Nondirector Executive Officers
John A. Bohling........................................................ 56,706
Paul G. Lorenzini...................................................... 31,202
Richard T. O'Brien..................................................... 55,095
Dennis P. Steinberg.................................................... 60,172
All executive officers and directors as a group (23 persons)............. 603,183
</TABLE>
- ------------------------
(1) Includes ownership of (a) shares held by family members even though
beneficial ownership of such shares may be disclaimed, (b) shares granted
and subject to vesting as to which the individual has voting but not
investment power under individual compensation arrangements or one or more
of the stock-based compensation plans of PacifiCorp and (c) shares held for
the account of such persons pursuant to the Compensation Reduction Plan.
See "Item 1. Business" for information concerning PacifiCorp's proposed
merger with Scottish Power plc.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
The information required by this item is set forth under "Director
Compensation and Certain Transactions" in Item 12 above.
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<PAGE>
PART IV
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K
(a) 1. The list of all financial statements filed as a part of this report is
included in ITEM 8.
2. Schedules:*
- ------------------------
* All schedules have been omitted because of the absence of the conditions
under which they are required or because the required information is
included elsewhere in the financial statements included under ITEM 8.
3. Exhibits:
<TABLE>
<C> <S>
*(2)a -- Agreement and Plan of Merger, dated as of December 6, 1998, by and among
Scottish Power plc, NA General Partnership, Scottish Power NA 1 Limited and
Scottish Power NA 2 Limited. (Incorporated by reference to Exhibit 1 to the
Form 6-K, dated December 11, 1998, filed by Scottish Power plc, File No.
1-14676).
(2)b -- Amended and Restated Agreement and Plan of Merger, dated as of December 6,
1998, as amended as of January 29, 1999 and February 9, 1999, and amended and
restated as of February 23, 1999, by and among New Scottish Power PLC,
Scottish Power plc, NA General Partnership and PacifiCorp.
*(2)c -- Stock Purchase Agreement, dated as of June 11, 1997, by and among PacifiCorp
Holdings, Inc., Pacific Telecom, Inc., Century Telephone Enterprises, Inc.
and Century Cellunet, Inc. (Incorporated by reference to Exhibit 2.1 of
Century Telephone Enterprises, Inc.'s Current Report on Form 8-K dated June
11, 1997, File No. 1-7784).
*(3)a -- Third Restated Articles of Incorporation of the Company (Exhibit (3)b, Form
10-K for the fiscal year ended December 31, 1996, File No. 1-5152).
(3)b -- Bylaws of the Company as amended November 18, 1998.
*(4)a -- Mortgage and Deed of Trust dated as of January 9, 1989, between the Company and
Morgan Guaranty Trust Company of New York (The Chase Manhattan Bank,
successor), Trustee, as supplemented and modified by twelve Supplemental
Indentures (Exhibit 4-E, Form 8-B, File No. 1-5152; Exhibit (4)(b), File No.
33-31861; Exhibit (4)(a), Form 8-K dated January 9, 1990, File No. 1-5152;
Exhibit 4(a), Form 8-K dated September 11, 1991, File No. 1-5152; Exhibit
4(a), Form 8-K dated January 7, 1992, File No. 1-5152; Exhibit 4(a), Form
10-Q for the quarter ended March 31, 1992, File No. 1-5152; and Exhibit 4(a),
Form 10-Q for the quarter ended September 30, 1992, File No. 1-5152; Exhibit
4(a), Form 8-K dated April 1, 1993, File No. 1-5152; Exhibit 4(a), Form 10-Q
for the quarter ended September 30, 1993, File No. 1-5152; Exhibit 4(a), Form
10-Q for the quarter ended June 30, 1994, File No. 1-5152; Exhibit (4)b, Form
10-K for the fiscal year ended December 31, 1994, File No. 1-5152; and
Exhibit (4)b, Form 10-K for the fiscal year ended December 31, 1995, File No.
1-5152; Exhibit (4)b, Form 10-K for the fiscal year ended December 31, 1996,
File No. 1-5152).
(4)b -- Thirteenth Supplemental Indenture, dated as of November 1, 1998.
</TABLE>
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<PAGE>
<TABLE>
<C> <S>
*(4)c -- Third Restated Articles of Incorporation and Bylaws. See (3)a and (3)b above.
In reliance upon item 601(4)(iii) of Regulation S-K, various instruments
defining the rights of holders of long-term debt of the Registrant and its
subsidiaries are not being filed because the total amount authorized under
each such instrument does not exceed 10% of the total assets of the
Registrant and its subsidiaries on a consolidated basis. The Registrant
hereby agrees to furnish a copy of any such instrument to the Commission upon
request.
*+(10)a -- PacifiCorp Deferred Compensation Payment Plan, as amended (Exhibit 10-F, Form
10-K for fiscal year ended December 31, 1992, File No. 1-8749) (Exhibit
(10)b, Form 10-K for fiscal year ended December 31, 1994, File No. 1-5152).
+(10)b -- PacifiCorp Compensation Reduction Plan dated December 1, 1994, as amended.
*+(10)c -- PacifiCorp Executive Incentive Program (Exhibit (10)d, Form 10-K for the fiscal
year ended December 31, 1996, File No. 1-5152).
*+(10)d -- PacifiCorp Non-Employee Directors' Stock Compensation Plan dated August 1,
1985, as amended (Exhibit (10)f, Form 10-K for fiscal year ended December 31,
1994, File No. 1-5152).
+(10)e -- PacifiCorp Long Term Incentive Plan, 1993 Restatement, as amended.
*+(10)f -- Form of Restricted Stock Agreement under PacifiCorp Long-Term Incentive Plan,
1993 Restatement, as amended (Exhibit 10H, Form 10-K for the year ended
December 31, 1993, File No. 0-873).
+(10)g -- PacifiCorp Supplemental Executive Retirement Plan, as amended.
*+(10)h -- Incentive Compensation Agreement dated as of February 1, 1994 between
PacifiCorp and Frederick W. Buckman (Exhibit (10)k, Form 10-K for the fiscal
year ended December 31, 1993, File No. 1-5152).
*+(10)i -- Compensation Agreement dated as of February 9, 1994 between PacifiCorp and
Keith R. McKennon, as amended (Exhibit (10)m, Form 10-K for the fiscal year
ended December 31, 1993, File No. 1-5152).
*+(10)j -- Amendment No. 1 to Compensation Agreement between PacifiCorp and Keith R.
McKennon dated as of February 9, 1995 (Exhibit (10)r, Form 10-K for the
fiscal year ended December 31, 1994, File No. 1-5152).
+(10)k -- PacifiCorp Stock Incentive Plan dated August 14, 1996, as amended.
+(10)l -- Form of Restricted Stock Agreement under PacifiCorp Stock Incentive Plan, as
amended.
+(10)m -- PacifiCorp 1998 Restricted Stock Program.
+(10)n -- Form of Nonstatutory Stock Option Agreement under PacifiCorp Stock Incentive
Plan.
+(10)o -- PacifiCorp Executive Severance Plan, as amended.
+(10)p -- Severance Agreement between PacifiCorp and Frederick W. Buckman dated as of
September 18, 1998.
+(10)q -- Employment Agreement between PacifiCorp and Keith R. McKennon dated as of
December 4, 1998.
*(10)r -- Short-Term Surplus Firm Capacity Sale Agreement executed July 9, 1992 by the
United States of America Department of Energy acting by and through the
Bonneville Power Administration and Pacific Power & Light Company (Exhibit
(10)n, Form 10-K for the fiscal year ended December 31, 1992, File No.
1-5152).
</TABLE>
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<PAGE>
<TABLE>
<C> <S>
*(10)s -- Restated Surplus Firm Capacity Sale Agreement executed September 27, 1994 by
the United States of America Department of Energy acting by and through the
Bonneville Power Administration and Pacific Power & Light Company (Exhibit
(10)t, Form 10-K for the fiscal year ended December 31, 1994, File No.
1-5152).
(12)a -- Statements of Computation of Ratio of Earnings to Fixed Charges (See page S-1).
(12)b -- Statements of Computation of Ratio of Earnings to Combined Fixed Charges and
Preferred Stock Dividends (See page S-2).
(21) -- Subsidiaries (See page S-3).
(23) -- Consent of Deloitte & Touche LLP with respect to Annual Report on Form 10-K.
(24) -- Powers of Attorney.
(27) -- Financial Data Schedule (filed electronically only).
</TABLE>
- ------------------------
* Incorporated herein by reference.
+ This exhibit constitutes a management contract or compensatory plan or
arrangement.
(b) Reports on Form 8-K.
On Form 8-K and Form 8-K/A Amendment No. 1 dated December 7, 1998, under
"Item 5. Other Events," the Company filed a news release concerning a merger
agreement between the Company, Scottish Power plc, NA General Partnership,
Scottish Power NA 1 Limited and Scottish Power NA 2 Limited.
On Form 8-K, dated February 16, 1999, under "Item 5. Other Events," the
Company filed a news release announcing an agreement to sell TPC Corporation.
(c) See (a) 3. above.
(d) See (a) 2. above.
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<PAGE>
SIGNATURES
PURSUANT TO THE REQUIREMENTS OF THE SECURITIES EXCHANGE ACT OF 1934, THE
REGISTRANT HAS DULY CAUSED THIS REPORT TO BE SIGNED ON ITS BEHALF BY THE
UNDERSIGNED THEREUNTO DULY AUTHORIZED.
PACIFICORP
By: /s/ ROBERT R. DALLEY
-----------------------------------------
Robert R. Dalley
CONTROLLER AND CHIEF ACCOUNTING OFFICER
Date: April 29, 1999
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<PAGE>
EXHIBIT (12)(a)
PACIFICORP
STATEMENTS OF COMPUTATION OF RATIO
OF EARNINGS TO FIXED CHARGES
<TABLE>
<CAPTION>
1994 1995 1996 1997 1998
--------- --------- --------- --------- ---------
(IN MILLIONS OF DOLLARS)
<S> <C> <C> <C> <C> <C>
Fixed Charges, as defined:*
Interest expense............................................. $ 302.0 $ 336.4 $ 415.0 $ 438.1 $ 371.7
Estimated interest portion of rentals charged to expense..... 5.6 4.5 4.1 6.6 5.7
Preferred dividends of wholly owned subsidiary............... -- -- 15.3 32.9 42.9
--------- --------- --------- --------- ---------
Total fixed charges...................................... $ 307.6 $ 340.9 $ 434.4 $ 477.6 $ 420.3
--------- --------- --------- --------- ---------
--------- --------- --------- --------- ---------
Earnings, as defined:*
Income from continuing operations............................ $ 397.5 $ 402.4 $ 430.3 $ 232.8 $ 169.7
Add (deduct):
Provision for income taxes................................. 209.0 192.1 236.5 111.8 59.1
Minority interest.......................................... 1.3 1.4 1.8 1.9 (0.7)
Undistributed income of less than 50% owned affiliates..... (14.7) (15.0) (18.2) (11.1) 10.3
Fixed charges as above..................................... 307.6 340.9 434.4 477.6 420.3
--------- --------- --------- --------- ---------
Total earnings........................................... $ 900.7 $ 921.8 $ 1,084.8 $ 813.0 $ 658.7
--------- --------- --------- --------- ---------
--------- --------- --------- --------- ---------
Ratio of Earnings to Fixed Charges............................. 2.9x 2.7x 2.5x 1.7x 1.6x
--------- --------- --------- --------- ---------
--------- --------- --------- --------- ---------
</TABLE>
- ------------------------
* "Fixed charges" represent consolidated interest charges, an estimated amount
representing the interest factor in rents and preferred dividend
requirements of majority-owned subsidiaries. "Earnings" represent the
aggregate of (a) income from continuing operations, (b) taxes based on
income from continuing operations, (c) minority interest in the income of
majority-owned subsidiaries that have fixed charges, (d) fixed charges and
(e) undistributed income of less than 50% owned affiliates without loan
guarantees.
S-1
<PAGE>
EXHIBIT (12)(b)
PACIFICORP
STATEMENTS OF COMPUTATION OF RATIO
OF EARNINGS TO COMBINED FIXED CHARGES AND PREFERRED STOCK DIVIDENDS
<TABLE>
<CAPTION>
1994 1995 1996 1997 1998
--------- --------- --------- --------- ---------
(IN MILLIONS OF DOLLARS)
<S> <C> <C> <C> <C> <C>
Fixed Charges, as defined:*
Interest expense............................................. $ 302.0 $ 336.4 $ 415.0 $ 438.1 $ 371.7
Estimated interest portion of rentals charged to expense..... 5.6 4.5 4.1 6.6 5.7
Preferred dividends of wholly owned subsidiary............... -- -- 15.3 32.9 42.9
--------- --------- --------- --------- ---------
Total fixed charges...................................... $ 307.6 $ 340.9 $ 434.4 $ 477.6 $ 420.3
Preferred Stock Dividends, as defined:*...................... 60.8 57.2 46.2 33.8 29.5
--------- --------- --------- --------- ---------
Total fixed charges and preferred dividends.............. $ 368.4 $ 398.1 $ 480.6 $ 511.4 $ 449.8
--------- --------- --------- --------- ---------
--------- --------- --------- --------- ---------
Earnings, as defined:*
Income from continuing operations............................ $ 397.5 $ 402.4 $ 430.3 $ 232.8 $ 169.7
Add (deduct):
Provision for income taxes................................. 209.0 192.1 236.5 111.8 59.1
Minority interest.......................................... 1.3 1.4 1.8 1.9 (0.7)
Undistributed income of less than 50% owned affiliates..... (14.7) (15.0) (18.2) (11.1) 10.3
Fixed charges as above..................................... 307.6 340.9 434.4 477.6 420.3
--------- --------- --------- --------- ---------
Total earnings........................................... $ 900.7 $ 921.8 $ 1,084.8 $ 813.0 $ 658.7
--------- --------- --------- --------- ---------
--------- --------- --------- --------- ---------
Ratio of Earnings to Combined Fixed
Charges and Preferred Stock Dividends........................ 2.4x 2.3x 2.3x 1.6x 1.5x
--------- --------- --------- --------- ---------
--------- --------- --------- --------- ---------
</TABLE>
- ------------------------
* "Fixed charges" represent consolidated interest charges, an estimated amount
representing the interest factor in rents and preferred dividend
requirements of majority-owned subsidiaries. "Preferred Stock Dividends"
represent preferred dividend requirements multiplied by the ratio which pre-
tax income from continuing operations bears to income from continuing
operations. "Earnings" represent the aggregate of (a) income from continuing
operations, (b) taxes based on income from continuing operations, (c)
minority interest in the income of majority-owned subsidiaries that have
fixed charges, (d) fixed charges and (e) undistributed income of less than
50% owned affiliates without loan guarantees.
S-2
<PAGE>
EXHIBIT (21)
SUBSIDIARIES OF THE COMPANY
PacifiCorp Group Holdings Company, a wholly-owned subsidiary of the Company
and a Delaware corporation, has the following subsidiaries:
<TABLE>
<CAPTION>
APPROXIMATE STATE OR
PERCENTAGE JURISDICTION OF
OF VOTING INCORPORATION OR
NAME OF SUBSIDIARY SECURITIES OWNED ORGANIZATION
- -------------------------------------------------- -------------------- ------------------
<S> <C> <C>
PacifiCorp Financial Services, Inc................ 100% Oregon
Pacific Harbor Capital, Inc..................... 100% Delaware
PacifiCorp International Group Holdings Company... 100% Oregon
Pan Pacific Global Corporation.................. 100% Oregon
PacifiCorp Australia LLC.................... 80%* Oregon
PacifiCorp Australia Holdings Pty. Ltd.... 100% Australia
Powercor Australia Limited............ 100% Australia
Eastern Investment Company...................... 100% Oregon
</TABLE>
- ------------------------
* Remaining 20% owned by Eastern Investment Company.
S-3
<PAGE>
EXHIBIT 23
INDEPENDENT AUDITORS' CONSENT
PacifiCorp:
We consent to the incorporation by reference in Registration Statement Nos.
33-51277, 33-54169, 33-57043, 33-58461, 333-10885, and 333-45851, all on Form
S-8, Registration Statement Nos. 33-62095 and 333-09115 on Form S-3, and
Registration Statement No. 33-36239 on Form S-4, of our report dated March 5,
1999, appearing in the Annual Report on Form 10-K/A Amendment No. 1 of
PacifiCorp and subsidiaries for the year ended December 31, 1998.
DELOITTE & TOUCHE LLP
Portland, Oregon
April 29, 1999
