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SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
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FORM 10-K
(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, 1997
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.)
700 N.E. MULTNOMAH, PORTLAND, OREGON 97232-4116
(Address of principal executive offices) (Zip Code)
Registrant's telephone number, including area code: (503) 731-2000
Securities registered pursuant to Section 12(b) of the Act:
NAME OF EACH EXCHANGE
TITLE OF EACH CLASS ON WHICH REGISTERED
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Common Stock New York Stock Exchange
Pacific Stock Exchange
8 3/8% Quarterly Income Debt Securities (Junior New York Stock Exchange
Subordinated Deferrable Interest Debentures,
Series A)
8.55% Quarterly Income Debt Securities (Junior New York Stock Exchange
Subordinated Deferrable Interest Debentures,
Series B)
8 1/4% Cumulative Quarterly Income Preferred New York Stock Exchange
Securities, Series A, of PacifiCorp Capital I
7.70% Cumulative Quarterly Income Preferred New York Stock Exchange
Securities, Series B, of PacifiCorp Capital II
Securities registered pursuant to Section 12(g) of the Act:
TITLE OF EACH CLASS
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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. / /
On March 1, 1998, the aggregate market value of the shares of voting and
nonvoting common equity of the Registrant held by nonaffiliates was
approximately $7.4 billion.
As of March 1, 1998, there were 297,215,100 shares of the Registrant's
common stock outstanding.
DOCUMENTS INCORPORATED BY REFERENCE
Portions of the Annual Report to Shareholders of the Registrant for the year
ended December 31, 1997 are incorporated by reference in Parts I and II.
Portions of the proxy statement of the Registrant for the 1998 Annual
Meeting of Shareholders are incorporated by reference in Part III.
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TABLE OF CONTENTS
PAGE
NO.
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Definitions................................................................................................ 3
Part I
Item 1. Business.................................................................................... 4
The Organization.......................................................................... 4
Domestic Electric Operations.............................................................. 5
Australian Electric Operations............................................................ 14
Unregulated Energy Trading................................................................ 21
Other Operations.......................................................................... 21
Discontinued Operations................................................................... 22
Employees................................................................................. 22
Item 2. Properties.................................................................................. 22
Item 3. Legal Proceedings........................................................................... 25
Item 4. Submission of Matters to a Vote of Security Holders......................................... 26
Item 4A. Executive Officers of the Registrant........................................................ 26
Part II
Item 5. Market for Registrant's Common Equity and Related Stockholder Matters....................... 28
Item 6. Selected Financial Data..................................................................... 28
Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations....... 28
Item 7A. Quantitative and Qualitative Disclosures about Market Risk.................................. 28
Item 8. Financial Statements and Supplementary Data................................................. 28
Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure........ 28
Part III
Item 10. Directors and Executive Officers of the Registrant.......................................... 28
Item 11. Executive Compensation...................................................................... 29
Item 12. Security Ownership of Certain Beneficial Owners and Management.............................. 29
Item 13. Certain Relationships and Related Transactions.............................................. 29
Part IV
Item 14. Exhibits, Financial Statement Schedules and Reports on Form 8-K............................. 29
Signatures................................................................................................. 32
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
List of Subsidiaries
2
DEFINITIONS
When the following terms are used in the text they will have the meanings
indicated:
TERM MEANING
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BPA....................................... Bonneville Power Administration
Company................................... PacifiCorp, an Oregon corporation
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, formerly named PacifiCorp Holdings, Inc., 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
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, a 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
3
PART I
ITEM 1. BUSINESS
THE ORGANIZATION
The Company is a diversified energy company in the United States and
Australia. In the United States, the Company conducts a retail electric utility
business through Pacific Power and Utah Power, and engages in power production
and sales on a wholesale basis under the name PacifiCorp. The Company formed
Holdings in 1984 to hold the stock of the Company's principal subsidiaries and
to facilitate the conduct of businesses not regulated as domestic electric
utilities. Holdings owns 100% of Powercor, the largest of the five electric
distribution companies in Victoria, Australia, and a 19.9% interest in the 1,600
megawatt ("MW"), brown coal-fired thermal Hazelwood power station and adjacent
brown coal mine in Victoria. The Company's strategic business plan is to
strengthen the domestic and international scope and competitive position of its
electric utility operations and to develop and expand its nonregulated,
energy-related activities, including its energy marketing and trading
businesses. The Company's goal is to become a dominant supplier of energy on a
global basis.
The Company is also expanding its nonregulated businesses that are engaged
in wholesale marketing and aggregating of electricity, plant and fuels
management, utilities services and retail energy services. PPM has authorization
from the FERC to sell power outside of the western United States at market
prices. On April 15, 1997, Holdings acquired 100% of TPC, a natural gas
gathering, processing, storage and marketing company. In December 1997, TPC sold
its nonstrategic natural gas gathering and processing assets. See "UNREGULATED
ENERGY TRADING."
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 (primarily
aircraft) and is limiting its pursuit of tax-advantaged investment opportunities
to alternative fuels.
The Company sold PTI on December 1, 1997 and PGC on November 5, 1997. See
"DISCONTINUED OPERATIONS" and "OTHER OPERATIONS--Pacific Generation Company."
On June 13, 1997, PacifiCorp announced a cash tender offer for The Energy
Group PLC ("TEG"). TEG is a diversified international energy group with
operations in the United Kingdom ("UK"), the United States and Australia and
includes Eastern Group PLC, one of the leading integrated electricity and gas
groups in the UK and Peabody Holding Company, Inc., the world's largest private
producer of coal. The Company's initial offer lapsed on August 1, 1997 when it
was referred to the Monopolies and Mergers Commission by the President of the
Board of Trade in the UK. The proposed acquisition of TEG by PacifiCorp was
subsequently cleared by the President of the Board of Trade on December 19,
1997.
On February 3, 1998, PacifiCorp announced the terms of a renewed cash tender
offer for TEG of 765 pence for each ordinary share. On March 2, 1998, Texas
Utilities Company ("TU") announced an offer of 810 pence for each TEG share.
Following TU's announcement, PacifiCorp announced an increased cash offer of 820
pence for each TEG share. This increased offer values the transaction at $11.1
billion, including the purchase of 521 million shares and the assumption of $4.1
billion of TEG's debt. The acquisition was to be financed with cash raised
through sales of noncore assets of subsidiaries of Holdings and borrowings by
subsidiaries of Holdings. PacifiCorp's announcement of the increased offer
followed the acquisition on March 2, 1998 by a subsidiary of Holdings of
45,987,079 TEG shares at a price of 820 pence per share. These shares represent
approximately 8.8% of the outstanding share capital of TEG.
On March 3, 1998, TU announced that it was increasing its offer to 840 pence
for each TEG share. TU's offer is subject to clearance by the UK Secretary of
State for Trade and Industry and certain other regulatory bodies. TU has also
announced that it has acquired approximately 22% of the outstanding share
capital of TEG.
4
For the year ended December 31, 1997, 59% of PacifiCorp's revenues from
operations were derived from Domestic Electric Operations, Australian Electric
Operations contributed 11%, Unregulated Energy Trading contributed 28% and Other
Operations contributed 2%. Note 16 to the Company's Consolidated Financial
Statements, incorporated herein by reference 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; this
information is incorporated herein by this reference.
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; wholesale energy trading; unregulated energy trading;
environmental, regulatory and tax legislation, including industry restructure
and deregulation initiatives; technological developments in the electricity
industry; 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%
Cumulative Quarterly Income 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
PacifiCorp 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 1.4 million retail customers in service territories
aggregating about 153,000 square miles in portions of seven western states:
Utah, Oregon, Wyoming, Washington, Idaho, California and Montana. The 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 metals, mining companies and
agribusiness. Agricultural products include potatoes, hay, grain and livestock.
The geographical distribution of retail electric operating revenues for the
year ended December 31, 1997 was Utah, 36%; Oregon, 33%; Wyoming, 13%;
Washington, 9%; Idaho, 4%; California, 3%; and Montana, 2%.
5
CUSTOMERS
Electric utility revenues and energy sales, by class of customer, for the
three years ended December 31, 1997 were as follows:
1997 1996 1995
----------------------- ---------------------- ---------
Operating Revenues (Dollars in millions):
Residential................................................. $ 814.0 22% $ 801.4 27% $ 739.7
Commercial.................................................. 640.9 18 623.3 21 576.9
Industrial.................................................. 709.9 20 719.3 25 708.8
Government, Municipal and Other............................. 31.7 1 32.5 1 29.7
---------- --- --------- --- ---------
Total Retail Sales........................................ 2,196.5 61 2,176.5 74 2,055.1
Wholesale Trading-Firm(1)................................... 1,289.3 35 635.4 22 487.7
Wholesale Trading-Nonfirm(1)................................ 138.7 4 103.4 4 32.3
---------- --- --------- --- ---------
Total Energy Sales........................................ 3,624.5 100% 2,915.3 100% 2,575.1
---------- --- --------- --- ---------
---------- --- --------- --- ---------
Other Revenues(2)........................................... 82.4 76.5 71.0
---------- --------- ---------
Total Operating Revenues.................................. $ 3,706.9 $ 2,991.8 $ 2,646.1
---------- --------- ---------
---------- --------- ---------
Kilowatt-hours Sold (kWh in millions):
Residential................................................. 12,902 12% 12,819 17% 12,030
Commercial.................................................. 11,868 11 11,497 15 10,797
Industrial.................................................. 20,674 20 20,332 27 19,748
Government, Municipal and Other............................. 705 1 640 1 592
---------- --- --------- --- ---------
Total Retail Sales........................................ 46,149 44 45,288 60 43,167
Wholesale Trading-Firm(1)................................... 51,857 49 23,189 31 13,946
Wholesale Trading-Nonfirm(1)................................ 7,286 7 6,476 9 2,430
---------- --- --------- --- ---------
Total kWh Sold............................................ 105,292 100% 74,953 100% 59,543
---------- --- --------- --- ---------
---------- --- --------- --- ---------
Operating Revenues (Dollars in millions):
Residential................................................. 29%
Commercial.................................................. 22
Industrial.................................................. 28
Government, Municipal and Other............................. 1
---
Total Retail Sales........................................ 80
Wholesale Trading-Firm(1)................................... 19
Wholesale Trading-Nonfirm(1)................................ 1
---
Total Energy Sales........................................ 100%
---
---
Other Revenues(2)...........................................
Total Operating Revenues..................................
Kilowatt-hours Sold (kWh in millions):
Residential................................................. 20%
Commercial.................................................. 18
Industrial.................................................. 33
Government, Municipal and Other............................. 1
---
Total Retail Sales........................................ 72
Wholesale Trading-Firm(1)................................... 24
Wholesale Trading-Nonfirm(1)................................ 4
---
Total kWh Sold............................................ 100%
---
---
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(1) Wholesale trading referred to here is part of Domestic Electric Operations'
regulated activities and is separate from the trading business discussed
under "UNREGULATED ENERGY TRADING" below.
(2) Includes miscellaneous revenues.
The Company's seven-state 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 1997, no single retail customer accounted for more than 1.9% of the
Company's retail utility revenues and the 20 largest retail customers accounted
for 14.7% of total retail electric revenues.
6
COMPETITION
During 1997, Domestic Electric Operations continued to operate as a
regulated monopoly within its seven-state franchise service territories.
Beginning in April 1998 for California and July 1998 for Montana, retail
electric energy sales will be subject to open market competition. The Company's
provision of distribution services will continue to be regulated while retail
sales of electricity will be unregulated in those states. Competition varies in
form and intensity, but is increasing over time, principally as a result of
industry restructuring and 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 alternative
energy sources, such as natural gas. These competitive pressures enable these
customers to negotiate lower prices through special tariffs.
Competition has already transformed the electric utility industry at the
wholesale level. The Energy Policy Act, passed in 1992, led to opening 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 charge their own
wholesale customers. As a result of increased competition and excess capacity,
wholesale prices have dropped significantly over the past three years.
In addition to these changes in the wholesale market, numerous states have
enacted legislation or initiated studies of retail competition or are
considering retail competition as part of industry restructuring. See
"Regulation." The Company is advocating federal legislation that would require
states to give all consumers choice in their energy provider by January 1, 2001.
The Company believes that federal legislation is necessary to address barriers
to entry and issues of jurisdiction, to preserve the proper role for the states
in implementing customer choice and to bring benefits to consumers as quickly as
possible.
The Company has also formulated strategies to meet these new challenges. The
Company is marketing power supply services to other utilities, 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 has 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 covered products and services in California
until certain organizational issues are resolved, but intends to remain active
in the wholesale business selling to utilities and marketers in California and
elsewhere.
During 1997, a subsidiary of the Company entered into alliances to bring
nonregulated energy services and products to customers. In May 1997, the Company
and ABB, Inc. formed EnergyPact, LLC. ABB, Inc. is an energy technology company
manufacturing and servicing fossil fuel and hydroelectric generating equipment
and transmission and distribution equipment. EnergyPact offers a menu of
comprehensive energy products and services, including upgrades to generation
plant equipment, plant management services, fuel procurement services, risk
management and energy trading.
In July 1997, a subsidiary of the Company and Northwest Natural Company
("Northwest Natural") announced the formation of an alliance to jointly offer
gas commodity and energy services throughout Oregon and Washington. They also
offer electricity in the areas of those two states where utilities offer pilot
programs that will allow commercial and industrial customers to choose their
electricity supplier. Northwest Natural is one of the largest purchasers of
natural gas in the Northwest and the largest transporter on the Northwest
Pipeline.
In January 1997, the Company and KN Energy, Inc. announced the formation of
a joint venture called "en-able." En-able offers utilities a single package of
energy, communications and "infotainment" home-oriented options under the name
"Simple Choice" for marketing to their customers.
In 1996, a consortium of utilities, including the Company, signed a
memorandum of understanding to create an independent grid operator ("IndeGO")
for the high-voltage transmission of electricity in
7
Washington, Oregon, Idaho, Montana, Nevada, Utah and Wyoming. In November 1997,
IndeGo's participants released a comprehensive proposal for the formation of
IndeGo that was to become the core of filings with FERC and state regulators.
After considering public comments and the views of the individual utilities that
have withdrawn their support for the proposal, seven of the investor-owned
utilities in the consortium, including the Company, concluded that it would not
be productive to devote further effort to IndeGo development at this time.
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
Northwest having low-cost hydroelectric generation and with utilities in
California and the Southwest having higher-cost, fossil-fuel generation. In
periods of favorable hydro 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 hydro conditions, the Company seeks to sell excess thermal
generation to utilities that are more dependent on hydroelectric generation than
the Company. During the winter, the Company has been able to purchase power from
Southwest utilities, either for its own peak requirements or for resale to other
Northwest utilities. During the summer, the Company has been able to sell excess
power to Southwest utilities to assist them in meeting their peak requirements.
See "Wholesale Trading and Purchased Power."
The Company owns or has interests in generating plants with an aggregate
nameplate rating of 8,699 MW and plant net capability of 8,282 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 1998 will be supplied by its hydroelectric plants and 55% by its thermal
plants. The balance of 40% is expected to be obtained under long-term purchase
contracts, interchange and other purchase arrangements. During 1997, the
Company's energy supply came from hydro 5%, thermal 45% and purchased power 50%.
Note 12 to the Company's Consolidated Financial Statements, incorporated by
reference under Item 8, contains additional details relating to the Company's
purchase of power under long-term arrangements.
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 2000 and continuing through 2011. The Company's current
annual payment under this agreement is $74 million. The agreement provides for
this amount 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.
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 1997, the Company
purchased an average of 114 MW from qualifying facilities, compared to an
average of 110 MW in 1996.
The Company plans and manages its capacity and energy resources based on
critical water conditions. Under critical or better water conditions in the
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 7,615 MW occurred on February 2,
1996.
8
WHOLESALE TRADING AND PURCHASED POWER
Wholesale sales continue to contribute significantly to total revenues. The
Company's wholesale sales complement its retail business and enhance the
efficient use of its generating capacity. In 1997, wholesale trading revenues
increased 93% and energy volume sold increased 99% over the prior year,
accounting for 56% of total energy sales and 39% of total energy revenues.
In addition to its base of thermal and hydroelectric resources, 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 when
prices are favorable. Firm power purchases supplied 37% of the Company's total
energy requirements in 1997. Nonfirm purchases supplied 13% of total energy
requirements in 1997.
PROPOSED ASSET ADDITIONS
In accordance with the Company's long-range integrated resource planning
process, also referred to as "least-cost planning," the Company considers
various future demand and supply options for providing customers with reliable,
low-cost energy services. See "Projected Demand." In this connection, the
Company also seeks opportunities to acquire existing assets from other
utilities.
The Company plans to participate in a wind generation project in Wyoming. In
May 1996, Kenetech Windpower, the original contractor, filed for bankruptcy. Its
rights were assigned to SeaWest Energy in December 1996. The Company plans to
own about 32 MW of the project, which is expected to be completed within two
years.
PROJECTED DEMAND
Annual increases in retail kilowatt-hour sales for the Company have averaged
2.1% since 1992. Although the sale of the Sandpoint, Idaho properties and the
closure of oil and gas wells in Wyoming have negatively impacted retail sales,
the Company has benefited from improved economic conditions in portions of its
service territory and the Company's commitment to price stability. Price
reductions in many of the Company's service territories have helped sustain
sales volume growth.
For the period 1998 to 2001, the average annual growth in retail
kilowatt-hour sales in the Company's franchised service territory is estimated
to be about 2.5%. During this period, the Company may lose energy sales to other
suppliers in connection with direct access pilot studies. As the electric
industry deregulates, the Company expects to have opportunities to gain market
share in areas outside its franchised service territory. Actual results will be
determined by a variety of factors, including 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 conditions through 2002. Actions outlined in the integrated resource
plan include energy efficiency by customers (demand-side management), efficiency
improvements to existing generation, transmission and distribution systems, and
investments in cogeneration, single cycle and combined cycle combustion turbines
and in renewable resources. See "Proposed Asset Additions."
Demand-side management is an element of the Company's diversified portfolio
of resources identified in its integrated plan. The use of an energy service
charge concept in the Company's demand-side resource programs is intended to
allow these resources to be acquired at competitive costs. Under the energy
service charge program, the customers receiving the benefits of energy
efficiency measures are expected to pay most of the related costs. The Company
expended an aggregate of $6 million for demand-side resources in 1997, while
acquiring 17.3 average MW of energy efficiency.
9
ENVIRONMENT
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
opacity. In addition, regional 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.
Emission controls, low sulfur coal, plant operating practices and continuous
emissions monitoring all are utilized to enable coal-burning plants to comply
with opacity, visibility and other air quality require-
ments. All of the Company's coal-burning plants burn low sulfur coal and are
equipped with controls to limit emissions of particulate matter. The majority of
the Company's coal-burning plants representing the majority of its installed
capacity have been equipped with controls which limit the amount 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
requirements and expansion plans. In addition, the Company has taken advantage
of opportunities to sell surplus allowances to other entities. The Company
recorded sales of surplus SO(2) allowances of $21 million in 1997 and $6 million
in 1996. The Company did not sell any surplus NO(x) emissions credits in 1997.
The Company may have approximately 20,000 to 25,000 tons of surplus SO(2)
emission allowances available for sale each year until 2025. The Company has
more than 800 tons of surplus NO(x) emissions credits that originated from the
retirement of the Hale generating station and emission reductions at the Gadsby
thermal generating plant in the state of Utah.
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 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 any one of the Company's
coal-burning plants. During 1997, the EPA also proposed new regulations
addressing regional haze. These proposed regulations have the potential to
impose significant new control requirements on certain coal-burning plants that
are not otherwise subject to strict SO(2) emission limits.
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 Kyoto Protocol, if
ultimately ratified, has the potential to impose significant new control and
operational requirements on the Company's coal-burning plants. The Company
voluntarily joined with a group of 44 other investor-owned utilities to sign an
agreement with the U.S. Department of Energy addressing CO(2) emissions. Under
the agreement, the Company committed to reduce its overall CO(2) emission rate
by 10% between 1990 and 2000 and also agreed to spend $1 million on CO(2) offset
projects.
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
10
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 agency actions
regarding emissions and visibility issues. In February 1998, the Southwest Air
Pollution Control Authority ("SWAPCA") issued a revised order requiring the
plant to meet new SO(2), NO(x), particulate matter and carbon monoxide emission
limits. These new limits resulted from the application of the Reasonably
Available Control Technology process as mandated by SWAPCA and Washington state
air quality requirements. The new emission limits will require the 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. 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 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.
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. In California, the
Public Utilities Commission has issued an interim order requiring utilities to
implement no cost or low-cost mitigation steps in the design of the new
facilities. The Company expects that public concerns about EMF will continue to
be an issue in the siting and construction of power lines and substations in the
future. 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 and generally raise the price the Company must
pay to purchase wholesale power from hydroelectric facilities owned by others
and increase the costs of operating the Company's own hydroelectric resources.
ENVIRONMENTAL CLEANUPS. Under the federal Comprehensive Environmental
Response, Compensation and Liability Act and comparable 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
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, PCBs 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 statements.
WATER QUALITY. The federal Clean Water Act and individual state clean water
regulations require a permit for the discharge of pollutants, 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.
11
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. 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.
Prices charged to retail customers are subject to regulation in each of the
states the Company serves. Interstate sales of electricity at wholesale prices
and interstate wheeling rates are regulated by the FERC. Except in Montana,
where the commission is elected, commissioners are appointed by the individual
state's governor for varying terms. While regulation varies from state to state,
industry analysts consider 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 currently in the process of relicensing or preparing to
relicense 15 separate hydroelectric projects under the Federal Power Act. These
projects, some of which are grouped together under a single license, represent
995 MW, or about 93% of the Company's total hydroelectric capacity and about 11%
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 "Environment--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 relicenses for certain projects if the terms of
renewal would make the projects uneconomical to operate.
A summary of regulatory and legislative developments in the states where the
Company conducts its retail electric operations is set forth below.
UTAH. On February 12, 1997, the Division of Public Utilities ("DPU") and
Committee of Consumer Services ("CCS") in Utah filed a joint petition with the
Utah Public Service Commission ("PSC") requesting the PSC to commence
proceedings to establish new rates for Utah customers. The petitioners requested
an immediate hearing on a $12 million interim rate reduction and a subsequent
general rate case, which the petitioners alleged could result in rates being
reduced by as much as $54 million annually. On March 4, 1997, the Utah
Legislature passed a bill creating a legislative task force to study
restructuring issues, including stranded costs and the timing of customer
choice. The bill froze rates at January 31, 1997 levels until 60 days following
the conclusion of the 1998 legislative general session (approximately May 5,
1998). The PSC is precluded from holding any hearings on rate changes during the
freeze period. The Company reduced prices to Utah customers by $12 million
annually in April 1997.
The Task Force held public meetings from May through November of 1997 on
investor-owned utilities issues and addressed such topics as market power,
market pricing, stranded costs, public purpose programs, tax impacts from
restructuring and independent system operators for transmission systems. In
November 1997, the Task Force recommended that further study was needed and that
no legislation be proposed in the 1998 session for the deregulation of
investor-owned utilities. The Task Force also recommended that the price freeze
and rate case moratorium be allowed to expire.
During 1997, the PSC did proceed with hearings on the proper methodology to
be used in allocating costs among the Company's seven jurisdictions in an effort
to establish the costs attributable to Utah customers in the rate case when the
rate freeze was lifted. The DPU recommended an allocation method that would
reduce prices by $56 million over five years, of which $14 million was included
in its original estimate of $54 million. During these hearings, the CCS
recommended a method that would reduce prices
12
by $96 million, or $42 million more than the original DPU estimate. The Company
advocated a method that would result in a decrease of approximately $3 million
per year. An order from the PSC is expected in early 1998. An allocation order
by itself will not decrease revenues, but will be incorporated into subsequent
rate proceedings to determine the overall change in rates for Utah customers.
OREGON. Major restructuring legislation in Oregon was discussed but not
enacted in 1997. No session will be held in 1998. The Oregon Public Utility
Commission ("OPUC") has initiated a generic stranded cost proceeding. The
initial phase of the proceeding is expected to result in an order on conceptual
stranded cost issues. A subsequent phase is likely to deal with technical
issues, such as those related to calculation of stranded costs.
In January 1998, the OPUC proposed modifications to the alternative form of
regulation ("AFOR") requested by the Company. The AFOR includes provisions
allowing rate changes for distribution costs based on changes in the producer
price index, less a productivity adjustment. The OPUC proposes to lower the
authorized earnings range for return on equity and increase the financial
penalties for the Company's failure to meet service quality standards. The
Company has filed an acceptance of the OPUC's proposal conditioned on changes to
some of the service quality measures and other terms of the proposal. The OPUC
has not responded to the Company's conditional acceptance.
In January 1998, the Company filed a proposal for a direct access pilot
program with the OPUC. The program will allow residential and small commercial
customers in Klamath County to select from a portfolio approach for pricing
options for electricity. The filing also includes direct access competitive
choice options for schools and large industrial customers throughout the state.
WYOMING. A committee of the Wyoming senate held hearings on a draft
electric restructuring bill. The committee heard public comment representing a
variety of interests, including investor owned utilities, cooperatives,
organized labor, large customers, small customers, municipalities, and the
Public Service Commission, and voted to reject the bill by a nine to five
margin. Discussions continue concerning future direction of restructuring
legislation in Wyoming.
WASHINGTON. Both unbundling and general restructuring legislation was
discussed during the 1997 legislative session in Washington but no legislation
was enacted. A shortened session is planned for 1998, and no major restructuring
legislation is anticipated. The Washington Utility and Transportation Commission
has initiated a proceeding to investigate methods for unbundling electric
utility costs. The proceeding is similar to the Idaho investigation discussed
below.
IDAHO. In 1997, Idaho industrial customers proposed a restructuring bill
which was not enacted. The Idaho Legislature did pass an unbundling bill which
required electric utilities in Idaho to make filings with the Idaho Public
Utility Commission ("IPUC") concerning costs of various services. The IPUC is
currently conducting unbundling cases for each of the three electric utilities
providing services in the state. The scope of this investigation is currently
limited to the separation of the cost components of the current bundled tariff
that customers pay. Stranded costs and other restructuring issues are not
currently being addressed.
CALIFORNIA. In 1996, the California Legislature enacted legislation which
required direct access by January 1, 1998. Direct access has been delayed, but
is expected to occur by the end of March 1998. Under the new law, utilities may
collect generation asset related stranded costs during the transition period
ending in 2001 and certain costs, such as costs of above market contracts with
qualified facilities ("QFs"), over the life of the contract. Utilities
requesting recovery of generation related stranded costs have been required to
reduce residential and small commercial rates by 10%. In December 1997, the
California Public Utilities Commission issued an order with respect to the
Company's proposed transition filing. The order mandates a 10% rate reduction
effective January 1, 1998, which would result in a $3.5 million annual reduction
in revenues. The Company has filed for a rehearing on this issue.
13
MONTANA. The Montana Legislature enacted a law mandating direct access for
large customers by July 1, 1998 and all customers by July 1, 2002. Stranded
costs relating to generation assets are limited to the level occurring during
the transition period, July 1, 1998 through June 30, 2002. The Company has
requested that regulatory assets and above market QF contracts be collected over
their normal lives. The Montana Public Service Commission is expected to issue
an order on the Company's proposal later in 1998.
CONSTRUCTION PROGRAM
The following table shows actual construction costs for 1997 and the
Company's estimated construction costs for 1998 through 2000, including costs of
acquiring demand-side resources. The estimates of construction costs for 1998
through 2000 are subject to continuing review and appropriate revision by the
Company. These estimates do not include expected expenditures for purchases of
generating assets. See "Proposed Asset Additions" for information concerning
proposed additions to the Company's generating assets.
ESTIMATED
-------------------------------
TYPE OF FACILITY ACTUAL 1997 1998 1999 2000
- -------------------------------------------------------------- ----------- --------- --------- ---------
(DOLLARS IN MILLIONS)
Production.................................................... $ 98 $ 130 $ 130 $ 130
Transmission.................................................. 42 35 35 35
Distribution.................................................. 231 160 160 160
Mining........................................................ 25 35 25 25
Other......................................................... 94 145 130 115
----- --------- --------- ---------
Total....................................................... $ 490 $ 505 $ 480 $ 465
----- --------- --------- ---------
----- --------- --------- ---------
AUSTRALIAN ELECTRIC OPERATIONS
POWERCOR
GENERAL
On December 12, 1995, Holdings completed the acquisition of Powercor from
the State of Victoria for approximately $1.6 billion in cash. The acquisition
was structured through a series of wholly owned United States and Australian
companies. Powercor is the largest electricity distribution company
("Distribution Company") in Victoria 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 550,000 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
and New South Wales. Powercor's distribution service area, the largest
distribution service area in Victoria, covers approximately 57,915 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 1996, Victoria accounted for approximately 25% of Australia's
total population, approximately 35% of Australia's manufacturing industry output
and approximately 26% 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
14
("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 1997, the Distribution Business
generated 89% 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 area in particular. The following
table sets forth the number of Powercor's distribution customers and volumes of
electricity distributed by Powercor at the dates and for the periods presented.
NUMBER OF DISTRIBUTION BUSINESS AT DECEMBER 31, AT DECEMBER 31,
CUSTOMERS CONNECTED 1996 1997
- ------------------------------------------------------------ --------------- ---------------
Residential................................................. 453,978 459,780
Commercial.................................................. 48,170 48,646
Industrial.................................................. 8,368 9,182
Other....................................................... 35,899 34,315
------- -------
Total....................................................... 546,415 551,923
------- -------
------- -------
YEAR ENDED YEAR ENDED
ELECTRICITY DISTRIBUTED BY THE DECEMBER 31, DECEMBER 31,
DISTRIBUTION BUSINESS (GWH) 1996 1997
- ----------------------------------------------------------------- --------------- ---------------
Residential...................................................... 2,608 2,679
Commercial....................................................... 1,411 1,550
Industrial....................................................... 2,995 3,273
Other............................................................ 510 537
----- -----
Total............................................................ 7,524 8,038
----- -----
----- -----
Under its distribution license, Powercor's revenues from the Distribution
Business consist of the following elements: (i) network tariffs, which include
distribution use-of-system costs, use of transmission system fees and connection
service charges; (ii) charges for connecting distribution customers to the
network, excluding the portion of connection costs recovered through network
tariffs; and (iii) fair and reasonable charges for other services. The level of
network tariffs is regulated under the Tariff Order (as defined below) through
December 31, 2000 pursuant to a price-cap regime that 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 forecasted
quantity of electricity to be delivered adjusted for inflation using a
consumer-price index formula and for under or over-recovery in previous
financial years. After December 31, 2000, the Tariff Order provides that the
Office of the Regulator General ("ORG") will regulate the level of network
tariffs in a manner that provides Powercor with incentives to increase the
volume of electricity distributed and to operate the distribution network
efficiently by making appropriate capital and maintenance expenditures.
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 their introduction. 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, 1997, Powercor had not lost any distribution
revenues to customers as a result of self-generation, co-generation or the
establishment of private distribution networks. Although Powercor believes that
it has effective strategies in place to minimize this type of loss of load,
there can be no
15
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
("VPX"), a corporate body established under Victoria's Electricity Industry Act
1993 ("Electricity Act"), and the company that owns and maintains the Grid,
Power Net Victoria ("PNV"), respectively, and constitute the VPX's and PNV'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 an
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 ORG's review of distribution tariffs charged
by Distribution Companies beginning in 2001, as described under "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.
Powercor has an exclusive license to sell electricity to customers with a
demand of 750 megawatt-hours ("mWh") per year or less. Powercor has nonexclusive
licenses to sell electricity to customers with usage in excess of 750 mWh per
year or more in its distribution service area and elsewhere in Victoria, New
South Wales and Queensland. Customers with usage of 750 mWh per year or less
will incrementally become contestable over the period ending December 31, 2000
in Victoria and Queensland and over the period ended June 30, 1999 in New South
Wales depending on their energy usage. In 1997, the Supply Business generated 4%
of the Company's operating income.
The customer metered sites energy usage and percentages of Powercor's
revenues from the Supply Business for franchise customers in Powercor's
distribution service area and for contestable customers in Victoria and New
South Wales for the year ended December 31, 1997 are set forth below:
CUSTOMER SITES ENERGY USAGE REVENUES
-------------------- -------------------- -------------
CUSTOMER SEGMENT NO. % GWH % %
- ----------------------------------------------- --------- --------- --------- --- -------------
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
--------- --------- --------- --- ---
--------- --------- --------- --- ---
16
The customer metered sites, energy usage and percentages of Powercor's
revenues from the Supply Business for residential, commercial, industrial and
other customers for the years ended December 31, 1996 and 1997 are set forth
below:
CUSTOMER SITES(1) ENERGY USAGE(2) REVENUES(2)
-------------------- -------------------- -------------
CUSTOMER CLASS NO. % GWH % %
- ------------------------------------------- --------- --------- --------- --------- -------------
Residential Customers
December 31, 1996........................ 453,978 83.0 2,608 31.4 38.1
December 31, 1997........................ 459,780 82.8 2,683 24.3 35.0
Commercial Customers
December 31, 1996........................ 48,598 8.9 1,926 23.2 26.3
December 31, 1997........................ 49,821 9.0 3,082 27.9 30.4
Industrial Customers
December 31, 1996........................ 8,422 1.5 3,282 39.5 28.5
December 31, 1997........................ 9,440 1.7 4,755 43.1 28.1
Other Customers(3)
December 31, 1996........................ 35,816 6.6 494 5.9 7.1
December 31, 1997........................ 35,849 6.5 524 4.7 6.5
Total Customers
December 31, 1996........................ 546,814 100.0 8,310 100.0 100.0
December 31, 1997........................ 554,890 100.0 11,044 100.0 100.0
- ------------------------
(1) Connection as of the date shown.
(2) For the year ended at the date shown.
(3) Other customers include farm customers and public lighting and traction
customers.
Powercor's residential customers accounted for 83% of the total customer
sites at December 31, 1997 and 35% of total electricity revenue. Commercial and
industrial customers accounted for 30% and 28%, respectively, of revenues in
1997. Electricity 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 2% of Powercor's
total revenues in 1997.
Powercor purchases all of its power for sale to franchise customers, other
than co-generation output, through the competitive wholesale market for
electricity in Victoria ("Pool"). There are two major components of the
wholesale electricity market: (i) the competitive energy market, centered
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 from July 1, 1995 to 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.
17
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. In July 1994, 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 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 in its
distribution service area in Victoria and licenses to supply electricity to all
customers in its distribution service area and elsewhere in Victoria, New South
Wales and Queensland. See "Supply Business." The Hazelwood Partnership has a
license to generate and sell electricity into the wholesale market in Victoria
and New South Wales. See "Hazelwood" below.
THE TARIFF ORDER. Pursuant to the Electricity Act, the Victorian
Electricity Supply Industry Tariff Order (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 PNV's
connection service charges, (ii) connection charges for connecting customers to
the network, taking into account that a 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 (x) provide each Distribution Company with incentives to operate
efficiently, (y) ensure a fair sharing of benefits achieved through efficiency
between customers
18
and Distribution Companies and (z) ensure appropriate incentives for capital
expenditures and maintenance of the distribution networks.
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 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 described in the table below.
LARGE/MEDIUM MEDIUM/SMALL RESIDENTIAL/RURAL
YEAR COMMENCING BUSINESSES BUSINESSES CUSTOMERS
- ------------------------------------------------------------- ----------------- ----------------- -----------------
July 1, 1997................................................. CPI CPI minus 5% CPI minus 1%
July 1, 1998................................................. CPI CPI minus 1% CPI minus 1%
July 1, 1999................................................. CPI CPI minus 1% CPI minus 1%
July 1, 2000................................................. CPI CPI minus 1% CPI minus 1%
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.
The retail contestability timetables for Victoria, New South Wales and
Queensland are outlined below.
SITE THRESHOLD VICTORIA NEW SOUTH WALES QUEENSLAND
- --------------------------------------------- ---------------------- ---------------------- -----------------
In excess of 750 MWh/yr...................... Already contestable Already contestable --
In excess of 160 Mwh/yr...................... July 1, 1998 July 1, 1998 January 1, 1999
160 Mwh/yr or less........................... January 1, 2001 July 1, 1999 January 1, 2001
PROPERTIES
Powercor's electrical distribution network comprises: (i) 66 kilovolts
("kV") and 22 kV subtransmission lines and underground subtransmission cables
that transport wholesale energy from 11 terminal stations owned by Power Net
Victoria and controlled, under lease, by VPX; (ii) 51 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 V and below) suitable for connection to the
majority of the customers. In addition, Powercor leases its principal executive
offices at Level 3, 177 Southbank Boulevard Southbank in Victoria under a
five-year lease with an option to renew for another five years.
ENVIRONMENTAL ISSUES
The nature of Powercor's operations exposes it to risks of varying degrees
associated with bushfires and other environmental issues.
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.
19
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
In September 1996, the Hazelwood Power Partnership (the "Hazelwood
Partnership") purchased 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 an affiliate of
National Power Corporation PLC ("National Power") (71.94%), Hazelwood Pacific
Pty Ltd, an indirect subsidiary of Holdings (19.9%, the maximum allowable under
current Victorian law) ("Hazelwood Pacific"), 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. With its 19.9% interest in the Hazelwood Partnership (the "Hazelwood
Investment"), Australian Electric Operations has a partial strategic hedge in
the event that electricity prices rise in the national market.
The Hazelwood Partnership financed the acquisition of the Hazelwood Plant
and the Hazelwood Mine with approximately $858 million in equity contributions
from its partners (including a $157 million contribution for Hazelwood Pacific).
Through the year 2000 the investment is expected to contribute only modestly to
the Company's net income. Through March 2000, Hazelwood Pacific estimates that
its contribution to the capital expenditure commitments of the Hazelwood Plant
will range between $6 million and $15 million per annum. The investment is
accounted for on an equity basis.
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.
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. Six of the Hazelwood Plant's eight generating units underwent major
refurbishment or plant life extension projects between 1983 and 1993. Unit 8
returned to service on December 5, 1997 and Unit 7 was returned to service in
January 1998. 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.
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, which licenses are generally
issued to the Hazelwood Partnership in the ordinary course and are terminable
upon the breach or violation thereof.
20
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 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 that would permit it to increase such emissions by up to 8% over 1990
emissions levels by 2012. 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.
UNREGULATED ENERGY TRADING
The Company's Unregulated Energy Trading business became a reportable
segment in 1997 with the significant expansion of electric power and natural gas
marketing revenues. The segment includes PPM, a wholesale power trading company
currently focusing in the Eastern United States, and TPC, a natural gas
marketing and storage company acquired by Holdings in April 1997. PPM's initial
market has been wholesale entities but it intends to expand into the contestable
retail sector as deregulation occurs.
The TPC acquisition adds natural gas trading to Holdings' growing energy
marketing business in the Eastern United States. Along with its natural gas
trading business, TPC integrates its natural gas storage facilities in certain
arrangements with natural gas distribution companies. In November 1997, TPC sold
its nonstrategic natural gas, gathering and processing systems because they were
believed not to be essential to the further growth of its energy marketing and
trading business. TPC's gas marketing and Market Hub Partners salt-dome storage
operations, headquartered in Houston, have been retained.
OTHER OPERATIONS
PACIFICORP FINANCIAL SERVICES
PFS is a holding company with two principal business segments, Financial
Services and Tax-Advantaged Investments. PFS presently expects to retain only
its tax-advantaged investments in leveraged lease assets (primarily aircraft).
FINANCIAL SERVICES
PFS made its last investment in aircraft or loans relating to aircraft in
1992. At December 31, 1997, approximately 90% of aircraft in PFS's portfolio
investment were Stage III noise compliant. At December 31, 1997, PFS's Aviation
Finance portfolio had total leveraged lease and other financial assets of $323
million (32 aircraft), representing approximately 46% of PFS's consolidated
assets.
Other financial services activities include centralized credit
administration and asset management and tax-advantaged investments in affordable
housing. Although no longer originating new business, PFS continues to manage
its remaining lending portfolio and other assets. At December 31, 1997, these
assets totaled $376 million, or approximately 54% of PFS's consolidated assets.
In February 1998, PFS agreed to sell substantially all its real estate assets.
TAX-ADVANTAGED INVESTMENTS
PFS has entered into a letter of intent with Covol Technologies, Inc.
("Covol") for construction of a plant in the Birmingham, Alabama area to produce
a synthetic coal fuel qualifying for tax credits under Section 29 of the
Internal Revenue Code ("IRC"). PFS will fund the construction costs and a
subsidiary of PFS will purchase the plant upon completion. Another PFS
subsidiary, PacifiCorp Syn Fuel ("Syn Fuel"), has entered into a licensing
agreement with Covol for up to three additional plants. Syn Fuel is pursuing
development of these plants and has entered into construction contracts for
these facilities.
21
PFS's participation in the alternative fuels tax credit market is limited by
the IRC requirement that qualified facilities must be built in accordance with
binding construction contracts entered into on or before December 31, 1996, and
in service by June 30, 1998.
INTERNATIONAL OPERATIONS
Through its subsidiaries, Holdings is engaged in the acquisition or
development of electrical power projects or systems internationally. Through its
subsidiary PacifiCorp Philippines Development Corporation, Holdings has a 33%
interest in the 75 MW Bakun hydroelectric project. Construction of the project
began in 1997, and the project is expected to be in commercial operation in
2000. Holdings is participating in consortia negotiating with the Turkish
government for operating rights for power projects tendered in 1997 by the
government.
PACIFIC GENERATION COMPANY
PGC acquired, developed and operated independent power production and
cogeneration facilities, principally in the United States. On November 5, 1997,
Holdings completed the sale of PGC's assets for $151 million in cash.
DISCONTINUED OPERATIONS
PTI provided local telephone service and access to the long distance network
in Alaska, seven other western states and three midwestern states. PTI also
operated and managed cellular mobile telephone services in six states and was
involved in the operation and maintenance of and sale of capacity in a submarine
fiber optic cable between the United States and Japan. In December 1997,
Holdings completed the sale of its ownership interest in PTI for $1.5 billion in
cash. This business has been reported as a discontinued operation.
EMPLOYEES
PacifiCorp and its subsidiaries had 10,087 employees on December 31, 1997.
Of these employees, 8,732 were employed by PacifiCorp and its mining affiliates,
1,122 were employed by Powercor and 233 were employed by PPM, TPC, PFS and other
subsidiaries.
Approximately 61% 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 of America and the United Mine
Workers of America. Approximately 74% of Powercor's employees are represented by
various unions in Australia, including the Australia Services Union and the
Electrical Trades Union.
In the Company's judgment, employee relations are satisfactory.
ITEM 2. PROPERTIES
The Company owns 52 hydroelectric generating plants and has an interest in
one additional plant, with an aggregate nameplate rating of 1,078.1 MW and plant
net capability of 1,138.6 MW. It also owns or has interests in 17
thermal-electric generating plants with an aggregate nameplate rating of 7,620.5
MW
22
and plant capability of 7,143.6 MW. The following table summarizes the Company's
existing generating facilities:
PLANT NET
INSTALLATION NAMEPLATE CAPABILITY
LOCATION ENERGY SOURCE DATES RATING (MW) (MW)
-------------------- ---------------- ----------- ------------ -----------
HYDROELECTRIC PLANTS
Swift....................................... Cougar, Washington Lewis River 1958 240.0 265.6
Merwin...................................... Ariel, Washington Lewis River 1931-1958 136.0 144.0
Yale........................................ Amboy, Washington Lewis River 1953 134.0 134.0
Five North Umpqua Plants.................... Toketee Falls, N. Umpqua River 1950-1956 133.5 138.5
Oregon
John C. Boyle............................... Keno, Oregon Klamath River 1958 80.0 90.0
Copco Nos. 1 and 2 Plants................... Hornbrook, Klamath River 1918-1925 47.0 54.5
California
Clearwater Nos. 1 and 2 Plants.............. Toketee Falls, Clearwater River 1953 41.0 41.0
Oregon
Grace....................................... Grace, Idaho Bear River 1914-1923 33.0 33.0
Prospect No. 2.............................. Prospect, Oregon Rogue River 1928 32.0 34.0
Cutler...................................... Collinston, Utah Bear River 1927 30.0 29.1
Oneida...................................... Preston, Idaho Bear River 1915-1920 30.0 28.0
Iron Gate................................... Hornbrook, Klamath River 1962 18.0 20.0
California
Soda........................................ Soda Springs, Idaho Bear River 1924 14.0 14.0
Fish Creek.................................. Toketee Falls, Fish Creek 1952 11.0 12.0
Oregon
33 Minor Hydroelectric Plants............... Various Various 1896-1990 98.6* 100.9*
------------ -----------
Subtotal (53 Hydroelectric Plants)........ 1,078.1 1,138.6
THERMAL ELECTRIC PLANTS
Jim Bridger................................. Rock Springs, Coal-Fired 1974-1979 1,495.0* 1,386.7*
Wyoming
Huntington.................................. Huntington, Utah Coal-Fired 1974-1977 892.8 845.0
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, Coal-Fired 1972 693.5* 636.5*
Washington
Hunter 1 and 2.............................. Castle Dale, Utah Coal-Fired 1978-1980 687.7* 639.4*
Hunter 3.................................... Castle Dale, Utah Coal-Fired 1983 446.4 395.0
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
Little Mountain............................. Ogden, Utah Gas Turbine 1971 16.0 14.0
Hermiston................................... Hermiston, Oregon Combined Cycle 1996 234.0* 234.0*
James River................................. Camas, Washington Black Liquor 1996 52.2 53.0
------------ -----------
Subtotal (17 Thermal Electric Plants)..... 7,620.5 7,143.6
------------ -----------
Total Hydro and Thermal Generating
Facilities (70)......................... 8,698.6 8,282.2
------------ -----------
------------ -----------
- ------------------------------
*Jointly owned plants; amount shown represents the Company's share only.
NOTE: Hydroelectric project locations are stated by locality and river
watershed.
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
23
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 others.
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, 1997. 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 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 1997, for their current
economically useful lives. The sulfur content of the reserves ranges from 0.43%
to 0.84% and the BTU value per pound of the reserves ranges from 7,600 to
11,400. 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.
RECOVERABLE TONS (IN
LOCATION PLANT SERVED MILLIONS)
- --------------------------------------------------------------- -------------------------- -----------------------
Centralia, Washington.......................................... Centralia 46(1)
Craig, Colorado................................................ Craig 70(2)
Glenrock, Wyoming.............................................. Dave Johnston 7(1)(5)
Emery County, Utah............................................. Huntington and Hunter 87(1)(3)
Rock Springs, Wyoming.......................................... Jim Bridger 125(4)
- ------------------------
(1) These reserves are mined by subsidiaries of the Company.
(2) These 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 reserves are in underground mines.
(4) These 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 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 1997, the Company
expended $3 million of reclamation costs and accrued $38 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, 1997, the Company's pro rata portion of these reclamation funds
totaled $43 million and the Company had an accrued reclamation liability of $159
million at December 31, 1997.
For a description of Powercor's properties, see "Item 1.
Business--Australian Electric Operations-- Properties" above.
24
ITEM 3. LEGAL PROCEEDINGS
The Company and its subsidiaries are parties to various legal claims,
actions and complaints, certain of which are 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
statements.
On March 1, 1996, a purported class action was filed against PacifiCorp
alleging negligence, nuisance and trespass by PacifiCorp as a result of the
operation of three dams on the Lewis River in the State of Washington during the
floods of February 1996 (LARRY AND BARBARA RAINEY, ET AL. V. PACIFICORP, Case
No. 96-2-00977-0, Superior Court of Washington for Clark County). Plaintiffs
request an unspecified amount of damages on behalf of the alleged class,
estimated by plaintiffs to have over 500 members, for injury to their property,
diminution of value of the related real estate and improvements, and
consequential damages in the form of lost income to businesses operating in the
flooded areas. The complaint also seeks injunctive relief compelling PacifiCorp
to establish additional warning systems downstream from the dams. PacifiCorp
believes that it operated the dams in an appropriate manner. Plaintiff's motion
for class certification was denied by the court on July 1, 1997.
On March 15, 1996, Utah Associated Municipal Power Systems ("UAMPS") filed
an action against PacifiCorp asserting 10 different causes of action, all
relating to the ownership interest of UAMPS in the Hunter Steam Electric
Generating Unit No. II ("Hunter II") in Emery County, Utah, which is operated by
PacifiCorp. (UTAH ASSOCIATED MUNICIPAL POWER SYSTEMS V. PACIFICORP, Civil No.
2:96CV 0240B, U.S. District Court for the District of Utah, Central Division).
The complaint alleges, among other things, an illegal tying arrangement in the
supply of coal by PacifiCorp to Hunter II, violations of various federal and
state antitrust laws, breach of contract and breach of a duty of good faith and
fair dealing. The complaint seeks damages in excess of $1,000,000 with respect
to each of several of the causes of action and certain declaratory rulings.
On April 2, 1996, the Utah Municipal Power Agency and Provo City, Utah
served an action against PacifiCorp asserting 13 different causes of action, all
relating to the plaintiffs' ownership interest in the Hunter Steam Electric
Generating Unit I ("Hunter I") in Emery County, Utah, which is operated by
PacifiCorp. (UTAH MUNICIPAL POWER AGENCY AND PROVO CITY, UTAH V. PACIFICORP,
Civil No. 2:96CV 0290C, US District Court for the District of Utah, Central
Division). The complaint alleged, among other things, an illegal tying
arrangement in the supply of coal by PacifiCorp to Hunter I, violations of
various federal and state antitrust laws, breach of contract, breach of
fiduciary duties and breach of a duty of good faith and fair dealing. The
complaint sought damages in amounts to be proven at trial, trebled in the case
of the antitrust claims, and certain declaratory rulings. In late 1997, the
Company settled the case.
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 percent
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
25
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. 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.
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. Officers are normally
elected annually.
FREDERICK W. BUCKMAN, BORN MARCH 9, 1946, PRESIDENT AND CHIEF EXECUTIVE
OFFICER OF THE COMPANY
Mr. Buckman was elected President and Chief Executive Officer of the Company
effective February 1, 1994 and became a director of the Company and Holdings in
February 1994. He formerly served as President and Chief Executive Officer of
Consumers Power Company, Jackson, Michigan, from 1992 to 1994.
WILLIAM C. BRAUER, BORN JANUARY 11, 1939, SENIOR VICE PRESIDENT OF THE
COMPANY
Mr. Brauer was elected Senior Vice President of the Company in May 1996. He
served as Vice President from 1992 to 1996 and as Senior Vice President of
Electric Operations from 1991 to 1992.
JOHN A. BOHLING, BORN JUNE 23, 1943, SENIOR VICE PRESIDENT OF THE COMPANY
Mr. Bohling was elected Senior Vice President of the Company in February
1993. He served as Executive Vice President of Pacific Power from September 1991
to February 1993 and as Senior Vice President of Utah Power from February 1990
to September 1991.
SHELLEY R. FAIGLE, BORN JUNE 8, 1951, SENIOR VICE PRESIDENT OF THE COMPANY
Ms. Faigle was elected Senior Vice President of the Company in November
1993. She served as Vice President from February 1992 to November 1993 and as
Vice President of Pacific Power from 1989 to February 1992.
PAUL G. LORENZINI, BORN APRIL 16, 1942, SENIOR VICE PRESIDENT OF THE COMPANY
Mr. Lorenzini was elected Senior Vice President of the Company in May 1994.
He served as President of Pacific Power from January 1992 to May 1994 and as
Executive Vice President from January 1989 to January 1992.
RICHARD T. O'BRIEN, BORN MARCH 20, 1954, SENIOR VICE PRESIDENT AND CHIEF
FINANCIAL OFFICER OF THE COMPANY AND PRESIDENT AND CHIEF EXECUTIVE OFFICER
OF HOLDINGS
Mr. O'Brien was elected President and Chief Executive Officer of Holdings in
January 1998 and Senior Vice President and Chief Financial Officer of the
Company in August 1995. He served as 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. He served as Senior Vice President, Treasurer and
Chief Financial Officer of NERCO, Inc., a former subsidiary of the Company,
during 1992 and 1993 and Vice President and Treasurer of NERCO from 1989 to
1992.
26
DANIEL L. SPALDING, BORN DECEMBER 23, 1953, CHAIRMAN AND CHIEF EXECUTIVE
OFFICER OF POWERCOR, SENIOR VICE PRESIDENT OF THE COMPANY
Mr. Spalding was elected Chairman and Chief Executive Officer of Powercor in
December 1995 and was elected Senior Vice President of the Company in February
1992. He served as Vice President from October 1987 to February 1992.
DENNIS P. STEINBERG, BORN DECEMBER 5, 1946, SENIOR VICE PRESIDENT OF THE
COMPANY
Mr. Steinberg was elected Senior Vice President of the Company in August
1994. He served as Vice President of the Company from February 1992 to August
1994 and as Vice President of Electric Operations from August 1990 to February
1992.
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.
JAMES H. HUESGEN, BORN DECEMBER 26, 1949, VICE PRESIDENT AND CONTROLLER OF
THE COMPANY AND CONTROLLER OF HOLDINGS
Mr. Huesgen was elected Controller of Holdings in January 1998 and Vice
President and Controller of the Company in November 1997. He served as Executive
Vice President and Chief Financial Officer of Pacific Telecom, Inc. from
February 1989 to November 1997.
SALLY A. NOFZIGER, BORN JULY 5, 1936, VICE PRESIDENT AND CORPORATE SECRETARY
OF THE COMPANY, SECRETARY OF HOLDINGS AND PACIFICORP FINANCIAL SERVICES,
INC.
Mrs. Nofziger was elected Vice President of the Company in 1989 and has been
Corporate Secretary since 1983.
WILLIAM E. PERESSINI, BORN MAY 23, 1956, VICE PRESIDENT AND TREASURER OF THE
COMPANY AND TREASURER OF HOLDINGS
Mr. Peressini was elected Vice President and Treasurer of the Company in May
1996. He had served as Treasurer since January 1994. He has been Treasurer of
Holdings since February 1994 and of Pacific Telecom, Inc. from August 1996 to
December 1997. He served as Executive Vice President of PacifiCorp Financial
Services, Inc. from January 1992 to January 1994 and as Senior Vice President
and Chief Financial Officer of that company from 1989 to January 1992.
DONALD A. BLOODWORTH, BORN MAY 9, 1956, VICE PRESIDENT OF THE COMPANY
Mr. Bloodworth was elected Vice President of the Company in November 1997.
He was employed by AirTouch Cellular from April 1997 to November 1997. He served
as Controller of the Company from August 1996 until April 1997. He formerly
served as Vice President of Revenue Requirements and Controller for Pacific
Telecom, Inc. from May 1993 until August 1996. He was Vice President and
Treasurer for PacifiCorp Holdings, Inc. and PacifiCorp Financial Services during
1992 and 1993.
THOMAS J. IMESON, BORN MARCH 20, 1950, VICE PRESIDENT OF THE COMPANY
Mr. Imeson was elected Vice President of the Company in February 1992. He
had served as Vice President of Electric Operations from 1990 to February 1992.
27
MICHAEL J. PITTMAN, BORN MARCH 25, 1953, VICE PRESIDENT OF THE COMPANY
Mr. Pittman was elected Vice President of the Company in May 1993. He served
as Assistant Vice President from 1990 to 1993.
PART II
ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS
(a). The information required by this item is included under "Quarterly
Financial Data" on page 65 of the Company's Annual Report to Shareholders and is
incorporated herein by this reference.
(b). Not applicable.
ITEM 6. SELECTED FINANCIAL DATA
The information required by this item is included under Note 16 "Selected
Financial and Segment Information" on page 60 of the Company's Annual Report to
Shareholders and is incorporated herein by this reference.
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATIONS
The information required by this item is included under "Management's
Discussion and Analysis" on pages 25 through 40 of the Company's Annual Report
to Shareholders and is incorporated herein by this reference.
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
The information required by this item is included under "Risk Management,"
"Interest Rate Exposure," "Currency Rate Exposure" and "Commodity Price
Exposure" on pages 39 and 40 of the Company's Annual Report to Shareholders and
is incorporated herein by this reference.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
The information required by this item is incorporated by this reference from
the Company's Annual Report to Shareholders or filed with this Report as listed
in Item 14 hereof.
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 information required by this item with respect to the Company's
directors is incorporated herein by this reference to "Election of Directors" in
the Proxy Statement for the 1998 Annual Meeting of Shareholders. The information
required by this item with respect to the Company's executive officers is set
forth in Part I of this report under Item 4A. The information required by this
item with respect to compliance with Section 16(a) of the Securities Exchange
Act of 1934 is incorporated herein by this reference to "Section 16(a)
Beneficial Ownership Reporting Compliance" in the Proxy Statement for the 1998
Annual Meeting of Shareholders.
28
ITEM 11. EXECUTIVE COMPENSATION
The information required by this item is incorporated herein by this
reference to "Executive Compensation" in the Proxy Statement for the 1998 Annual
Meeting of Shareholders.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
The information required by this item is incorporated herein by this
reference to "Security Ownership of Certain Beneficial Owners and Management" in
the Proxy Statement for the 1998 Annual Meeting of Shareholders.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
The information required by this item is incorporated herein by this
reference to "Director Compensation and Certain Transactions" in the Proxy
Statement for the 1998 Annual Meeting of Shareholders.
PART IV
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K
PAGE REFERENCES
---------------
(a) 1. Index to Consolidated Financial Statements:*
Independent Auditors' Report.............................................................. 41
Statements of consolidated income and retained earnings for each of the three years ended
December 31, 1997....................................................................... 42
Statements of consolidated cash flows for each of the three years ended December 31,
1997.................................................................................... 43
Consolidated balance sheets at December 31, 1997 and 1996................................. 44
Notes to consolidated financial statements................................................ 46
2. Schedules:**
- ------------------------
* Page references are to the incorporated portion of the Annual Report to
Shareholders of the Registrant for the year ended December 31, 1997.
**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 incorporated by reference herein.
3. Exhibits:
*(2) -- 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 restated and amended May 10, 1995) (Exhibit (3)b, Form
10-K for the fiscal year ended December 31, 1995, File No. 1-5152).
29
*(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 -- 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 (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 (Exhibit
(10)b, Form 10-K for fiscal year ended December 31, 1994, File No. 1-5152).
*+(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 (Exhibit 10G, Form 10-K for
the year ended December 31, 1993, File No. 0-873).
*+(10)f -- Form of Restricted Stock Agreement under PacifiCorp Long Term Incentive Plan, 1993
Restatement (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 (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 (Exhibit (10)n,
Form 10-K for the fiscal year ended December 31, 1996, File No. 1-5152).
30
*+(10)l -- Form of Restricted Stock Agreement under PacifiCorp Stock Incentive Plan Exhibit
(10)o, Form 10-K for the fiscal year ended December 31, 1996, File No. 1-5152).
*+(10)m -- PacifiCorp Executive Severance Plan (Exhibit (10)p, Form 10-K for the fiscal year
ended December 31, 1996, File No. 1-5152).
*(10)n -- 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).
*(10)o -- 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).
(13) -- Portions of Annual Report to Shareholders of the Registrant for the year ended
December 31, 1997 incorporated by reference herein.
(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).
- ------------------------
* 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 dated December 1, 1997, under "Item 2. Acquisition or
Disposition of Assets," the Company announced the completion of the PTI sale to
Century Telephone Enterprises, Inc.
On Form 8-K dated December 19, 1997, under "Item 5. Other Events," the
Company filed a news release reporting the unconditional approval from the U.K.
Government that allowed it to make a new bid for The Energy Group.
On Form 8-K dated January 12, 1998, under "Item 5. Other Events," the
Company filed a news release announcing a work force reduction, Glenrock mine
closure and other charges.
On Form 8-K dated January 27, 1998, under "Item 5. Other Events," the
Company filed a news release reporting its 1997 financial results.
On Form 8-K dated February 3, 1998, under "Item 5. Other Events," the
Company filed both a news release and joint announcement relating to its offer
to purchase all outstanding shares of The Energy Group.
On Form 8-K dated March 3, 1998, under "Item 5. Other Events," the Company
filed news releases: (a) reporting the proposed cash offer by a subsidiary of
the Company of 820 pence per share for all outstanding shares of The Energy
Group ("TEG") and (b) an increased offer of 840 pence per share for all
outstanding shares of TEG by Texas Utilities Company. The Company also filed the
audited, 1997 consolidated financial statements and related footnotes of
PacifiCorp and its subsidiaries.
(c) See (a) 3. above.
(d) See (a) 2. above.
31
SIGNATURES
PURSUANT TO THE REQUIREMENTS OF SECTION 13 OR 15(D) OF THE SECURITIES
EXCHANGE ACT OF 1934, THE REGISTRANT HAS DULY CAUSED THIS REPORT TO BE SIGNED ON
ITS BEHALF BY THE UNDERSIGNED THEREUNTO DULY AUTHORIZED.
PACIFICORP
BY /s/ FREDERICK W. BUCKMAN
------------------------------------------
Frederick W. Buckman
(PRESIDENT)
Date: March 23, 1998
PURSUANT TO THE REQUIREMENTS OF THE SECURITIES EXCHANGE ACT OF 1934, THIS
REPORT HAS BEEN SIGNED BELOW BY THE FOLLOWING PERSONS ON BEHALF OF THE
REGISTRANT AND IN THE CAPACITIES AND ON THE DATES INDICATED.
SIGNATURE TITLE DATE
- ---------------------------- ---------------------------- -------------------
/s/ FREDERICK W. BUCKMAN
- ---------------------------- President, Chief Executive
Frederick W. Buckman Officer and Director March 23, 1998
(PRESIDENT)
/s/ RICHARD T. O'BRIEN Senior Vice President (Chief
- ---------------------------- Financial Officer and
Richard T. O'Brien Principal Accounting March 23, 1998
(SENIOR VICE PRESIDENT) Officer)
*W. CHARLES ARMSTRONG
- ----------------------------
W. Charles Armstrong
*KATHRYN A. BRAUN
- ----------------------------
Kathryn A. Braun
Director March 23, 1998
*C. TODD CONOVER
- ----------------------------
C. Todd Conover
*NOLAN E. KARRAS
- ----------------------------
Nolan E. Karras
32
SIGNATURE TITLE DATE
- ---------------------------- ---------------------------- -------------------
*KEITH R. MCKENNON
- ----------------------------
Keith R. McKennon
(CHAIRMAN)
*ROBERT G. MILLER
- ----------------------------
Robert G. Miller
*ALAN K. SIMPSON
- ----------------------------
Alan K. Simpson
Director March 23, 1998
*VERL R. TOPHAM
- ----------------------------
Verl R. Topham
*DON M. WHEELER
- ----------------------------
Don M. Wheeler
*NANCY WILGENBUSCH
- ----------------------------
Nancy Wilgenbusch
*PETER I. WOLD
- ----------------------------
Peter I. Wold
*By /s/ NANCY WILGENBUSCH
-------------------------
Nancy Wilgenbusch
(ATTORNEY-IN-FACT)
33