MANAGEMENT'S DISCUSSION AND ANALYSIS
EARNINGS OVERVIEW
MILLIONS OF DOLLARS,
EXCEPT PER SHARE INFORMATION 1997 1996 1995
- --------------------------------------------------------------------------------
EARNINGS CONTRIBUTION
ON COMMON STOCK
Domestic Electric
Operations $165.5 $341.5 $276.4
Australian Electric
Operations 54.2 31.9 0.7
Unregulated Energy Trading (7.5) (0.1) --
Other Operations (9.6) 27.1 86.2
------------------------------------
Continuing Operations 202.6 400.4 363.3
Discontinued Operations 454.3 74.7 103.0
Extraordinary item (16.0) -- --
------------------------------------
$640.9 $475.1 $466.3
------------------------------------
------------------------------------
EARNINGS PER COMMON SHARE
-- BASIC AND DILUTIVE
Continuing Operations $ 0.68 $ 1.37 $ 1.28
Discontinued Operations 1.53 0.25 0.36
Extraordinary item (0.05) -- --
------------------------------------
$ 2.16 $ 1.62 $ 1.64
------------------------------------
------------------------------------
PAGE NO. 1997
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EFFECTS OF ADJUSTMENTS ON
EARNINGS PER COMMON SHARE
Earnings per common share
-- as reported $ 2.16
ADJUSTMENTS
Asset sales gains 26 (1.33)
Special charges 29 0.36
Extraordinary loss 25 0.05
Foreign currency option losses 26 0.22
Depreciation, uncollectible
provisions and SAP charges 29 0.07
Tariff H and other adjustments 32 (0.01)
-------------------
$ 1.52
-------------------
-------------------
The global energy business witnessed dramatic changes during 1997 and
competition now exists in many parts of the energy marketplace. Significant
events included passage of state regulatory legislation, continuation of
acquisitions, consolidations or partnering by energy companies both domestically
and internationally, and further reductions in electricity product margins. To
stay competitive, companies must reduce costs, improve customer service,
supplement energy sales with other needed products and services, enhance the
reliability of their system (generation, transmission and distribution), and
maintain a safe working environment. These factors had direct impacts on
PacifiCorp's 1997 results and may significantly impact its near-term
performance.
During 1997, PacifiCorp sharpened its focus on becoming a dominant global
energy provider by selling Pacific Telecom, Inc. ("PTI"), acquiring gas
marketing expertise with the purchase of TPC Corporation ("TPC") and making a
tender offer for The Energy Group PLC ("TEG"). Industry restructuring
continued with certain jurisdictions taking legislative actions approving
customer choice, which caused Domestic Electric Operations to write off
certain allocated generation regulatory assets. Special charges and other
unfavorable adjustments also significantly impacted Domestic Electric
Operations' costs in 1997. Management took steps to address increasing
operating cost issues and maintain the Company's position as a low-cost
energy producer.
Earnings on common stock for PacifiCorp and its subsidiaries (the "Company")
increased $166 million, or $0.54 per share, compared to 1996. The Company's $641
million of 1997 earnings included asset sale gains of $395 million, or $1.33 per
share, relating to sales of the Company's telecommunications subsidiary and
independent power business. Domestic Electric Operations recorded $106 million,
or $0.36 per share, of special charges relating to an accrual for a coal mine
closure, write off of deferred regulatory pension assets and impairment of
information technology systems. Additionally, the Company recorded other
adjustments that significantly impacted 1997 results, including losses on
foreign currency options, depreciation adjustments, process re-engineering
expenses and contract adjustments. Excluding the asset sale gains, special
charges and other adjustments discussed below, the Company's 1997 earnings on
common stock, on a comparable basis to 1996, would have been $451 million, or
$1.52 per share, a decrease of $24 million, or $0.10 per share from 1996.
Legislative actions in California and Montana during 1996 and 1997 mandated
customer choice of electricity supplier, moving away from cost-based
regulation to competitive market rates for the generation portion of the
electric business. As a result of these legislative actions, the Company
evaluated its generation regulatory assets and liabilities in California and
Montana based upon future regulated cash flows. As a result, the Company
recorded in 1997 an extraordinary charge of $16 million, or $0.05 per share,
for the write off of allocable generation regulatory assets in these states.
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PACIFICORP P.25
The Company also operates in five other states that are in various stages of
addressing deregulation of the electricity industry. At December 31, 1997,
the Company's total remaining regulatory assets for these five states was
$871 million, of which $382 million is applicable to generation. Potential
regulatory or legislative actions in these other states may result in
additional write offs and charges. See further discussion in INDUSTRY
CHANGES, COMPETITION AND DEREGULATION.
Domestic Electric Operations' contribution to earnings on common stock was
$165 million in 1997. After adding back to earnings $132 million of special
charges and other adjustments, the contribution was $297 million. This $45
million decrease from 1996 earnings was the result of several factors
including: higher depreciation; increased outside services costs; increased
employee expenses attributable to the expansion of the wholesale power
business; and price decreases in Utah. Purchased power expenses continued to
grow as increased demand in the wholesale trading and retail markets resulted
in the need to acquire power from external sources. This higher demand caused
a 99% increase in wholesale energy sales and a 117% increase in purchased
power volumes.
Australian Electric Operations' earnings contribution increased $22 million,
or 70%, due to higher volumes, renegotiations of Tariff H industrial
contracts, decreased maintenance costs and lower interest expense. Powercor
continued its growth as a marketing and distribution company in Australia
and, based on energy sales, currently serves 42% of Victoria's contestable
customers and 13% of the New South Wales contestable market, which opened in
October 1996.
Unregulated Energy Trading became a reportable segment in 1997 with the
significant expansion of electricity and gas marketing revenues. This segment
includes PacifiCorp Power Marketing, Inc. ("PPM"), engaged in wholesale
electricity trading in eastern United States markets, and TPC, a recently
acquired natural gas marketing and storage company. This new segment had
revenue of $1.7 billion in 1997 compared to $12 million in 1996. The gross
margin on sales was $19 million in 1997 compared to $4 million in 1996.
However, after start-up and administrative costs, it reported a net loss of
$8 million in 1997. Revenues, gross margin and net income in 1997 included
$19 million, $14 million and $3 million, respectively, relating to assets of
TPC that were sold in December 1997.
Other Operations reported net losses of $10 million in 1997, or $0.03 per
share, as compared to earnings of $27 million, or $0.09 per share, in 1996.
The 1997 results were impacted by an after-tax loss of $65 million associated
with closing foreign currency exchange positions and option premium costs
relating to the initial tender offer for TEG in June 1997. Additionally,
Other Operations included the $30 million gain on sale of Pacific Generation
Company ("PGC"), discussed below. The earnings of PacifiCorp Group Holdings
Company ("Holdings") and other unregulated businesses in 1997 were comparable
with the prior year.
1997 ASSET SALE GAINS
NET CASH PRETAX NET
MILLIONS OF DOLLARS FROM SALES(a) GAINS INCOME EPS
- -------------------------------------------------------------------------------
PTI sale $1,198 $671.0 $365.1 $1.23
PGC sale 96 56.5 30.0 0.10
--------------------------------------------------
$1,294 $727.5 $395.1 $1.33
--------------------------------------------------
--------------------------------------------------
(a) Cash from asset sales is net of income taxes.
On December 1, 1997, the Company completed the sale of PTI for $1.5 billion
in cash, plus the assumption of PTI's debt. The Company realized an after-tax
gain of $365 million, or $1.23 per share. For the eleven months of 1997, PTI
reported net income of $89 million, or $0.30 per share, compared to $75
million, or $0.25 per share, for all of 1996.
In November 1997, the Company completed the sale of its independent power
subsidiary, PGC, for approximately $150 million in cash, which resulted in a
gain of $30 million, or $0.10 per share. Excluding the loss on foreign
currency exchange positions and PGC's operating results and gain on sale, the
Company's other unregulated businesses and equity investments reported 1997
earnings of $15 million, compared to earnings of $19 million in 1996, a
decrease of $4 million.
- -------------------------------------------------------------------------------
P. 26 PACIFICORP
DOMESTIC ELECTRIC OPERATIONS
REVENUES
MILLIONS OF DOLLARS 1997 1996 1995
- -----------------------------------------------------
Wholesale trading(a) $1,428.0 $738.8 $520.0
Residential 814.0 801.4 739.7
Industrial 709.9 719.3 708.8
Commercial 640.9 623.3 576.9
Other 114.1 109.0 100.7
----------------------------
$3,706.9 $2,991.8 $2,646.1
----------------------------
----------------------------
ENERGY SALES
MILLIONS OF KWH 1997 1996 1995
- -----------------------------------------------------
Wholesale trading(a) 59,143 29,665 16,376
Residential 12,902 12,819 12,030
Industrial 20,674 20,332 19,748
Commercial 11,868 11,497 10,797
Other 705 640 592
-----------------------------
105,292 74,953 59,543
-----------------------------
-----------------------------
(a) Wholesale trading is part of Domestic Electric Operations' regulated
activities and is separate from the Unregulated Energy Trading segment
discussed hereafter.
Domestic Electric Operations' revenue increase of $715 million in 1997 was
caused primarily by a 99% increase in wholesale kilowatt hours sold ("kWh")
that added $689 million of revenues. Retail energy sales in 1997 were 2%
higher than in 1996. Although wholesale trading revenues have grown
substantially over the past few years, in 1997 the retail load still
represented 61% of total Domestic Electric Operations' revenues.
Wholesale trading revenues increased to a record $1.4 billion. Energy volumes
of short-term firm and spot market sales increased 28.5 million megawatt
hours ("mWh") and added $589 million of revenues and higher prices for these
sales added $80 million. Increased long-term firm contract volumes added $14
million to wholesale revenues. As a result of increased competition and
excess capacity, wholesale prices overall dropped 25% in the past three years
with a 21% drop in 1996 and a 4% decrease in 1997. The average price per mWh
for wholesale power in 1997 was $24, as compared to $25 in 1996 and $32 in
1995. This trend in lower average prices is due to a higher percentage of
wholesale sales being derived from shorter term contracts. The trend in lower
average prices is expected to continue.
AVERAGE ANNUAL REVENUE PER CUSTOMER
DOLLARS 1997 1996
- ---------------------------------
Residential $ 672 $ 679
Industrial 19,477 18,887
Commercial 3,818 3,810
Residential revenues were up $13 million, or 2%. Growth in the average number
of residential customers of 3% added $20 million to revenues. Price increases
in Oregon, effective July 1996, added $9 million in 1997, offset in part by
price decreases of $4 million in Utah that became effective April 1997 as
discussed below. Declines in customer usage, primarily attributable to
weather, reduced revenues $14 million in 1997 compared to 1996.
Industrial revenues decreased $9 million, or 1%. Total kWh sold was up 2% with
increased customer usage adding revenues of $6 million in Eastern Wyoming and $4
million in Oregon. However, these increases were more than offset by reduced
revenues of $8 million from lower usage by irrigation customers due to increased
rainfall and milder temperatures in 1997 and $6 million of billing adjustments
in the first quarter of 1997.
Commercial revenues increased $18 million, or 3%, primarily due to customer
growth. The Utah service area had 5% growth in the average number of customers
and $11 million in increased revenues, and Oregon reported 2% growth in
the average number of customers and $4 million in additional revenue. Utah price
decreases lowered revenue by $3 million. However, this decrease was offset by
higher Oregon prices that increased revenues by the same amount.
In early 1997, the Division of Public Utilities (the "DPU") and the Committee of
Consumer Services (the "CCS") in Utah filed a joint petition with the Utah
Public Service Commission (the "PSC") requesting the PSC to commence proceedings
to establish new rates for Utah customers. The DPU indicated that rates could be
reduced by approximately $54 million. Subsequently in March 1997, the Utah
Legislature passed a bill that created a legislative task force to study
electrical restructuring and customer choice issues in the State of Utah. The
bill precluded the PSC from holding hearings on rate changes and froze prices at
January 31, 1997 levels until May 1998, but allowed for retroactive price
changes. The Company agreed to an interim price decrease to Utah customers of
$12.4 million annually beginning on April 15, 1997.
During the freeze period, the PSC proceeded with hearings on the proper method
for cost allocation among PacifiCorp's seven jurisdictions that would be used in
the 1998 rate case. 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 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. The PSC held hearings in December
and an order is expected
- -------------------------------------------------------------------------------
PACIFICORP P. 27
OPERATING EXPENSES
MILLIONS OF DOLLARS 1997 1996 1995
- ---------------------------------------------------------------
Fuel $ 454.2 $ 443.0 $ 431.6
Purchased power 1,296.5 618.7 386.7
Other operations and
maintenance 470.0 444.2 442.1
Depreciation and
amortization 389.1 343.4 320.4
Other 325.4 272.7 264.4
Special charges 170.4 -- --
---------------------------------
$3,105.6 $2,122.0 $1,845.2
---------------------------------
Operating Expenses as a
% of Revenue (excluding
special charges) 79% 71% 70%
in early 1998. An allocation order by itself will not decrease revenues, but
will be incorporated into subsequent rate proceedings which are expected to
occur in mid-1998 and will be combined with other cost increases and
decreases to determine the overall impact to customer rates.
In December 1997, the California Public Utilities Commission issued an order
with respect to the Company's filing concerning transition to direct access
requirements enacted in that state. The order mandated a 10% rate reduction
effective January 1, 1998, which is expected to result in a $3.5 million
annual reduction in revenues.
1996 COMPARED TO 1995 -- Revenues rose 13%, or $346 million, primarily due to
an 81% increase in kWh sold in the wholesale market. Despite this volume
increase, the Company realized only a 42% increase in wholesale revenues in
1996 due to the impact of competition on market prices. Residential and
commercial revenues grew a combined 8% in 1996 as a result of increased
prices and volumes. Price increases of approximately 4% were approved in
Oregon and Wyoming customer jurisdictions in July 1996. In the last half of
1996, these increases contributed an additional $16 million of revenue.
Revenues increased an additional $86 million due to weather conditions that
increased energy requirements, 2% residential and 3% commercial customer
growth and increased customer usage.
OPERATING EXPENSES
Operating expenses increased $984 million, or 46%, largely as a result of a
significant increase in purchased power costs and special charges.
Fuel expenses in 1997 increased 3%, or $11 million, primarily due to increased
production from higher-cost plants in 1997 as compared to 1996.
In July 1996, the Company purchased a 50% ownership interest in the 474
megawatt ("MW") gas-fired, combined cycle, Hermiston Plant and agreed to take
100% of the energy produced under a long-term contract, if the Company
chooses to dispatch the power.
The Company made the investment in Hermiston primarily to meet growing retail
load requirements and to replace expiring long-term purchased power contracts
with estimated costs of $30 million. The investment decision was made during a
time when existing and projected market prices were significantly higher.
During 1997, the Hermiston Plant generated 1.9 million mWh. Assuming all of
the power generated by Hermiston was sold at an average short-term market
price of $22 per mWh, the investment in Hermiston would have resulted in a
pretax loss of $25 million, after considering the impacts of the terminated
long-term purchase power contracts. Further, in certain of the states in
which the Company operates, the costs in excess of market relating to
Hermiston are being recovered in rates. Domestic Electric Operations intends
to continue to seek recovery of this excess cost in other states in future
regulatory proceedings.
PURCHASED POWER
MILLIONS OF MWH 1997 1996 1995
- ------------------------------------------------
Short-term or spot market 45.6 16.9 5.0
Long-term contracts 9.4 8.5 6.0
In addition to base energy capacity from its thermal and hydroelectric
resources, the Company utilizes a mix of long-term, short-term and nonfirm power
purchases to meet its own retail load commitments and to make wholesale power
sales to other utilities.
Purchased power expense was more than double last year, due to growth in the
Company's wholesale trading business. Short-term firm and spot market purchases
were nearly three times the level of 1996 purchases, adding $570 million to
purchased power expense. Short-term firm and spot market purchase prices
averaged $19 per mWh in 1997 compared to $13 per mWh in 1996, a
46% increase, adding $76 million to purchased power expense.
Net power costs were $6.99 per mWh in 1997, compared to $7.20 per mWh in
1996, a 3% decrease. Net power costs represent the net cost to serve the
Company's retail customers on a mWh basis. This cost is measured by the sum
of fuel,
- -------------------------------------------------------------------------------
P. 28 PACIFICORP
- -------------------------------------------------------------------------------
purchased power and wheeling expense, less wholesale power and wheeling
revenues. The decrease in net power costs was attributable to increased hydro
generation which displaced higher cost resources and higher volumes from
short-term and spot market sales, offset in part by increased fuel costs.
Other operations and maintenance expense increased $26 million, or 6%, over
1996. The higher expenses included $11 million of increased plant maintenance
and tree trimming expense and a $10 million provision for uncollectible
accounts resulting from issues relating to new customer billing processes.
Depreciation and amortization expense increased $46 million, or 13%. At the
end of 1997, the Company completed a depreciation study of its fixed assets
and filed with the appropriate regulatory bodies for approval to increase its
annual depreciation rates. As a result of the study, depreciation expense
increased $17 million to reflect the higher depreciation rates. An additional
$26 million in depreciation was attributable to a $377 million increase in
average depreciable plant in service, including a full year of a new customer
service system and Hermiston Plant operations.
Other expenses increased $53 million, a 19% increase over 1996. This increase
was the result of higher employee related costs of $20 million, primarily
attributable to a significant increase in wholesale marketing activities, higher
outside services of $18 million and process re-engineering costs
of $10 million relating to the Company's new SAP enterprise-wide software
operating environment expected to be fully implemented in 1999.
Nonfuel operating costs, excluding special charges, increased 11% in 1997. To
stay competitive in this changing energy industry, the Company has announced
cost cutting initiatives, including an early retirement and severance program
and a reduction in the use of outside consultants. The early retirement and
severance program is intended to eliminate approximately 600 positions, or 7% of
the work force in the United States, in 1998 and reduce employee related costs.
Based upon the current acceptance rate of the voluntary program, the pretax cost
is estimated to be $104 million, which will be recorded in the first quarter of
1998. The current acceptance rate has exceeded the Company's original estimate.
SPECIAL CHARGES
NET
MILLIONS OF DOLLARS PRETAX INCOME EPS
- ------------------------------------------------------
Glenrock mine closure $ 64.4 $ 39.9 $0.14
Deferred regulatory
pension cost 86.9 53.9 0.18
Impairment charges
on IT systems 19.1 11.9 0.04
------------------------------
$170.4 $105.7 $0.36
------------------------------
------------------------------
In 1997, the Company recorded a series of special charges at Domestic
Electric Operations. Management concluded that the Glenrock mine was
uneconomic to continue to operate under current and expected market
conditions due to increased mining stripping ratios, coal quality and related
operating costs. Therefore, a $64 million accrual was recorded for costs
associated with the write down of asset values and the acceleration of
reclamation costs due to early closure of the mine. The Company also
determined that recovery of its regulatory assets applicable to deferred
pension costs, which related primarily to a deferred compensation plan and
early retirement incentive programs in 1987 and 1990, was not probable. As a
result, the Company recorded an $87 million charge for these deferred
regulatory pension assets since the Company does not intend to seek recovery
of these costs. However, the Company will seek recovery for its current and
future pension costs. In addition, the Company recorded a $19 million charge
for the impairment of certain information systems assets that are directly
impacted by the Company's decision to proceed with installation of SAP
enterprise-wide software.
1996 COMPARED TO 1995 -- Operating expenses grew 15% in 1996 primarily due to a
$232 million increase in purchased power costs. Depreciation and amortization
expenses were up 7%, which was attributable to a $410 million increase in
average depreciable plant, including the addition of the Hermiston Plant that
began operation in July 1996.
OTHER INCOME AND EXPENSE
Domestic Electric Operations' interest expense increased $27 million, or 9%,
to $319 million in 1997. This increase was attributable to higher average
debt balances as a result of the Hermiston Plant acquisition in July 1996 and
capital contributions to Holdings relating to the acquisition of TPC in April
1997. Other income increased $7 million in 1997 primarily as a result of
increased sales of emission allowances.
1996 COMPARED TO 1995 -- Interest expense declined $20 million, or 6%, in 1996.
Excluding $28 million of interest cost associated with a tax settlement in 1995,
interest expense increased $8 million, or 3%, due to higher debt levels during
1996. The settlement had no effect on consolidated net income, although it had
the effect of reducing Domestic Electric Operations' earnings by $32 million and
increasing Other Operations' earnings by $32 million in 1995. Other expenses
increased $27 million in 1996 as a result of distributions relating to preferred
securities of subsidiary trusts issued in 1996, reduced asset sale gains and
increased product and business development expense.
- -------------------------------------------------------------------------------
PACIFICORP P. 29
- -------------------------------------------------------------------------------
INDUSTRY CHANGES, COMPETITION AND DEREGULATION
INDUSTRY CHANGE -- The electric power industry continues to experience rapid
change. The key driver for this change is growing public and regulatory
support for replacing the traditional cost-of-service regulatory framework
with an open market competitive framework where the customers have a choice
of energy supplier.
Federal laws and regulations have already been amended to provide for open
access to transmission systems, and various states have adopted or are
considering new regulations to allow open access for all energy suppliers.
The question is no longer if there will be competition, but rather how and
when the competitive marketplace will develop.
COMPETITION -- The Company faces competition from many areas, including other
suppliers of electricity and alternative energy sources. In many cases,
customers have the option to switch energy sources for heating and air
conditioning. In addition, certain of the Company's industrial customers are
seeking choice of suppliers, options to build their own generation or
cogeneration, or the use of alternative energy sources such as natural gas.
When a competitive marketplace exists, customers will make their energy
purchasing decision based upon many factors, including price, service and
system reliability.
To meet these competitive challenges, Domestic Electric Operations is
participating in restructuring processes that will determine the shape of
future markets, and is pursuing strategies that capitalize on its competitive
position, including the development and delivery of innovative products and
services. In addition, the Company continues to negotiate long-term and
short-term contracts with its existing large volume industrial customers.
Although these new agreements have generally resulted in reduced margins, the
Company has been successful in retaining many of these customers and
extending contract lives.
DEREGULATION -- Domestic Electric Operations continues to develop its
competitive strategy as legislation, regulation and market opportunities
evolve. 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 move toward an open or competitive marketplace for electric power may result
in uneconomic "stranded costs" related to certain current investments, deferred
costs and contractual commitments incurred under regulation that may not be
recoverable in a competitive market. The calculation of stranded costs requires
certain complex and interrelated assumptions to be made, the most critical of
which is the expected market price of electricity. The Company and many industry
analysts believe that market forces will continue to drive retail energy prices
down as excess capacity of the existing generation resources persists. This
projected price decrease trend is consistent with other commodities and services
that have gone through deregulation. Contrary to historical price trends,
certain other parties believe prices will increase in the future resulting in a
stranded benefit to the Company. The key attributes that affect market price
include excess generation capacity, the marginal cost of the high-cost provider
that is required to meet market demand, the cost of adding new capacity and the
price of natural gas.
At December 31, 1997, the Company estimates its total stranded costs to range
from $1.4 billion to $2.8 billion. This estimate represents the net present
value of the difference between the revenues expected under competition and the
embedded cost of generating the electricity and providing the service and does
not necessarily measure any write off or impairment that would be required.
Regulated utilities have historically applied the accounting provisions of
Statement of Financial Accounting Standards ("SFAS") 71 which is based on the
premise that regulators will set rates that allow for the recovery of a
utility's costs, including cost of capital. Accounting under SFAS 71 is
appropriate as long as: rates are established by or subject to approval by
independent, third-party regulators; rates are designed to recover the
specific enterprise's cost-of-service; and in view of demand for service, it
is reasonable to assume that rates are set at levels that will recover costs
and can be collected from customers. In applying SFAS 71, the Company must
give consideration to changes in the level of demand or competition during
the cost recovery period. In accordance with SFAS 71, Domestic Electric
Operations capitalizes certain costs, called regulatory assets, in accordance
with regulatory authority whereby those costs will be expensed and recovered
in future periods.
The Emerging Issues Task Force of the Financial Accounting Standards Board (the
"EITF") concluded in 1997 that SFAS 71 should be discontinued when detailed
legislation or regulatory order regarding competition is issued. Additionally,
the EITF concluded that regulatory assets and liabilities applicable to
businesses being deregulated should be written off unless their recovery is
provided for through future regulated cash flows.
In 1996, legislation was passed in California restructuring its electric
utility industry. This restructuring is scheduled to begin on March 31, 1998,
at which time customers will be able to buy their electricity from sources
other than the local utility. The local utility will continue to provide
distribution services. Legislation was also passed in Montana in 1997, which
established a phased process to introduce price-based competition into the
supply of electricity in Montana. As a result
- -------------------------------------------------------------------------------
P. 30 PACIFICORP
of these legislative actions, prices for the supply of electric generation in
California and Montana are, or are expected to be, in transition from
cost-based regulated rates to rates determined by competitive market forces.
The Company has evaluated its regulatory assets and liabilities related to the
generation portion of its business allocable to the states of California and
Montana based upon future regulated cash flows. Accordingly, the Company ceased
the application of SFAS 71 to its generation business allocable to the states of
California and Montana in 1997. Domestic Electric Operations recorded an
extraordinary loss of $16 million for the write off of these regulatory assets
and liabilities.
The Company operates in five other states (Oregon, Utah, Wyoming, Washington and
Idaho) which are at various stages of addressing the issue of deregulating the
electricity industry. At December 31, 1997, $382 million of the Company's
$871 million total regulatory assets was applicable to the
generation assets allocable to these five states.
The Company intends to seek recovery of its stranded assets, including its
$382 million of generation regulatory assets, in Utah, Oregon, Wyoming,
Idaho, and Washington. However, due to the current lack of definitive
legislation, the Company cannot predict whether it will be successful.
Because of the potential regulatory and/or legislative actions in these other
state jurisdictions, the Company may have additional regulatory asset write
offs and charges for impairment of long-lived assets in future periods
relating to the generation portion of its business. Impairment would be
measured in accordance with SFAS 121, which requires the recognition of
impairment on long-lived assets when book values exceed expected future cash
flows. Integral parts of future cash flow estimates include estimated future
prices to be received, the expected future cash cost of operations, sales and
load growth forecasts and the nature of any legislative or regulatory cost
recovery mechanisms.
The Company believes that the regulatory initiatives that are underway in
each of the seven states in which it operates will eventually bring
competition for the electricity generation services. This change in the
regulatory structure may significantly affect the Company's future financial
condition and results of operations.
ENVIRONMENTAL ISSUES
All of the Company's coal burning plants burn low-sulfur coal. Major
construction expenditures have already been made at many of these plants to
reduce sulfur dioxide ("SO(2)") emissions, but additional expenditures are
expected to be required at the Centralia Plant in Washington in which the
Company has a 47.5% ownership interest. In late 1997, the Southwest Pollution
Control Authority ("SWAPCA") ordered the Centralia Plant to meet new SO(2),
nitrogen oxides ("NOx"), carbon dioxide and particulate matter 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 NOx burners at a projected cost of
$240 million.
In addition, the Company and the other joint owners of the Craig Generating
Station (the "Station") in Colorado are parties to a lawsuit brought by the
Sierra Club alleging violations of the Federal Clean Air Act at the Station,
which is operated by the Tri-State Generation and Transmission Association.
The Company has a 19.3% interest in Units 1 and 2 of the Station.
Actions under the Endangered Species Act with respect to certain salmon and
other endangered or threatened species could result in restrictions on the
Federal hydropower system and affect regional power supplies and costs. These
actions could also result in further restrictions on timber harvesting and
adversely affect electricity sales to Domestic Electric Operations' customers
in the wood products industry.
Domestic Electric Operations is currently in the process of relicensing 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 93%, of the Company's total hydroelectric capacity. In the new licenses,
the Federal Energy Regulatory Commission is expected to impose conditions
designed to address the impact of the projects on fish and other
environmental concerns. Domestic Electric Operations is unable to predict the
impact of imposition of such conditions, but capital expenditures and
operating costs are expected to increase in future periods and certain
projects may not be economical to operate.
Several federal and state environmental cleanup Superfund sites have been
identified where Domestic Electric Operations has been, or may be, designated as
a potentially responsible party. In such cases, Domestic Electric Operations
reviews the circumstances and, where possible, negotiates with other potentially
responsible parties to provide funds for clean-up and, if necessary, monitoring
activities.
All of the Company's mining operations are subject to reclamation and closure
requirements. The Company monitors these requirements and annually revises
its cost estimates to meet existing legal and regulatory requirements of the
various jurisdictions in which it operates. Compliance with these
requirements could result in higher expenditures for both capital
improvements and operating costs.
Future costs associated with the disposition of these matters are not
expected to be material to the Company's consolidated financial statements.
- -------------------------------------------------------------------------------
PACIFICORP P. 31
AUSTRALIAN ELECTRIC OPERATIONS
REVENUES
MILLIONS OF DOLLARS 1997 1996
- ----------------------------------------
Residential $239.2 $239.4
Commercial 207.9 165.5
Industrial 191.8 179.3
Other 77.3 74.6
------------------
$716.2 $658.8
------------------
------------------
ENERGY SALES
MILLIONS OF KWH 1997 1996
- ----------------------------------------
Residential 2,683 2,608
Commercial 3,082 1,926
Industrial 4,755 3,282
Other 524 494
-------------------
11,044 8,310
-------------------
-------------------
PacifiCorp completed its second successful year of operating Powercor since
acquiring the company in December 1995 from the State of Victoria and its
first full year of ownership of a 19.9% interest in the Hazelwood
Partnership, which owns a 1,600 MW, coal-fired thermal power plant and
adjacent coal mine. In 1997, Australian Electric Operations contributed
earnings of $54 million, compared to $32 million in 1996. Powercor's
expansion of market share in Victoria and the State of New South Wales drove
the growth in energy sales and revenues. However, lower market sales prices,
partially offset by lower purchased power expense, caused margins on energy
sold to decline.
CUSTOMERS AND COMPETITION -- POWERCOR
Powercor's principal businesses are to purchase electricity supply from a
state generation pool, sell electricity to franchise and contestable
customers inside and outside its franchise area and provide electricity
distribution services to customers within its regulated network distribution
service area. Franchise customers are those customers that cannot yet choose
an electricity supplier, while contestable customers have the opportunity to
choose suppliers.
Victoria and New South Wales are currently divided between franchised and
contestable customers. Customers in both states with annual loads of 750 mWh
or more are now contestable and the remaining customers will become
contestable over the next few years depending on their energy demand load,
with substantially all residential customers remaining franchise customers
until 2001. If a Powercor customer chooses a different retailer, Powercor
will continue to receive network distribution revenues associated with that
customer. At the end of 1997, Powercor had captured contestable market share
of 42% in Victoria and 13% in New South Wales, based on energy sold.
Additionally, Powercor was granted licenses to sell electricity to customers
in the States of Queensland and Australian Capital Territory in early 1998.
CURRENCY RISKS
Powercor's results of operations and financial position are translated from
Australian dollars into United States dollars for consolidation into the
Company's financial statements. Changes in the prevailing exchange rate may
have a material effect on the Company's consolidated financial statements.
The average currency exchange rate for converting Australian dollars to
United States dollars was 0.744 in 1997 compared to 0.783 in 1996, a 5%
decrease for the year. The effect of the exchange rate fluctuation lowered
reported revenues by $33 million and expenses by $31 million in 1997. The
currency exchange rate at February 28, 1998 was 0.68.
REVENUES -- POWERCOR
Powercor reported a $57 million increase in revenues, or 9%, over the prior
year. The increase was attributable to a 33% increase in energy sales
volumes. Powercor continued to increase market share in the contestable
market in Victoria and recorded a 1.5 million kWh increase, or $54 million of
higher revenues. In 1997, the first full year of competing in the contestable
market in New South Wales, Powercor added 1.4 million kWh and $46 million of
revenue.
Revenue from inside Powercor's Victorian franchise area decreased $47
million, or 8%, to $539 million. Lower average realized prices reduced
revenues by $39 million. Energy volumes decreased 108 million kWh, or $8
million, due to customers lost from the effect of contestability in
Powercor's franchise area. Over the last two years, Powercor has lost 185
customers as a result of contestability within its franchise area.
Other revenue included $11 million of accelerated amortization of deferred
credits associated with the election by certain industrial customers to move
from the specified fixed energy price rates under Tariff H to market-based
contracts. The deferred credits were recorded at the time of the Powercor
acquisition to reflect the anticipated losses associated with the
requirements to supply electricity to Tariff H customers. At the end of 1997,
Powercor had $4 million of deferred Tariff H credits remaining.
- -------------------------------------------------------------------------------
P. 32 PACIFICORP
OPERATING EXPENSES -- POWERCOR
MILLIONS OF DOLLARS 1997 1996
- -------------------------------------------------------
Purchased power $308.5 $305.1
Other operations and maintenance 134.0 112.3
Depreciation and amortization 67.1 71.6
Other 56.1 42.4
---------------------
$565.7 $531.4
---------------------
---------------------
Purchased power expense increased $4 million, or 1%, and represented 55% of
Powercor's total operating expenses in 1997. Volumes of purchased power
increased 2.7 million kWh, or 33%, adding $101 million to costs, offset in
part by lower pool power prices that reduced purchased power expense by $97
million. Purchased power prices averaged $28 per mWh in 1997, compared to $37
per mWh in 1996.
Other operations and maintenance expense increased $22 million, or 19%.
Increased sales to contestable customers outside Powercor's franchised area
resulted in higher network and grid fees of $52 million. This increase was
partially offset by higher network revenues of $15 million from customers
inside Powercor's franchise area that are serviced by other energy suppliers.
A decrease in maintenance expenses of $17 million was attributable to
increased productivity and cost reduction efforts.
Other expenses increased $14 million, or 32%, due to higher outside services of
$10 million and process re-engineering costs of $4 million relating to the new
SAP software implementation, completed in 1997.
HAZELWOOD
For 1997, the Company recorded an after-tax loss of $2 million on its 19.9%
ownership interest in the Hazelwood Power Station as compared to an after-tax
loss of $1 million in 1996. Hazelwood was purchased in September 1996.
REGULATION -- AUSTRALIA
Powercor is the largest of the five distribution businesses ("DBs") formed
when the Victorian State Government decided to privatize, and eventually
deregulate, its electricity industry. As the Victorian market becomes more
open to competition and additional customers can choose their energy
supplier, Powercor and the other DBs will continue to maintain a monopoly on
their individual network areas. These businesses derive much of their revenue
from the network fee that is paid for the use of the distribution system.
Powercor, like each of the other four DBs in the State of Victoria, has been
granted an exclusive license to sell electricity to franchise customers whose
facilities are in its distribution area and a nonexclusive state-wide license
to sell to contestable customers.
Hazelwood operates in an area where several large, coal-fired generating
facilities are located. It will continue to compete against these plants, as
well as others outside the geographic area.
Except for power generation and certain contestable accounts, the Australian
power industry continues to be a regulated business, albeit a structure that
is rapidly changing toward customer choice.
Regulation of the Victorian electricity industry is the responsibility of the
Office of the Regulator General (the "ORG"), an independent regulatory body.
The structure of prices within the Victorian electricity industry reflects
the establishment of maximum uniform tariffs that apply to noncontestable
customers and some contestable customers. Under applicable regulations,
Powercor is required to supply electricity to noncontestable customers at
prices that are no greater than the prices specified under the applicable
tariffs. The prices specified in the tariffs are all inclusive, including
grid charges and energy costs. In general, annual movements in the tariffs
for noncontestable customers are based on the Consumer Price Index, a measure
of price inflation.
Network tariffs include recovery of distribution use of system costs, use of
transmission system fees and connection charges. Network tariffs are intended
to cover the cost of providing, operating and maintaining the distribution
network, except to the extent relevant costs are recoverable through
connection charges or other excluded services, and the charges levied for
connection to and use of the transmission systems.
The first major review of the regulatory arrangements and respective
transmission and distribution network charges will be carried out by the ORG,
with any changes to apply from January 1, 2001. Any subsequent price control
arrangements are required to be in effect for not less than five years.
- -------------------------------------------------------------------------------
PACIFICORP P. 33
UNREGULATED ENERGY TRADING(a)
REVENUES
MILLIONS OF DOLLARS 1997 1996
- -------------------------------------------------------
TPC $ 815.8 --
PPM 913.2 $11.7
-----------------------
$1,729.0 $11.7
-----------------------
-----------------------
EARNINGS CONTRIBUTION(b)
MILLIONS OF DOLLARS 1997 1996
- -------------------------------------------------------
TPC $(5.9) --
PPM (1.6) $(0.1)
-----------------------
$(7.5) $(0.1)
-----------------------
-----------------------
(a) Unregulated energy trading excludes Domestic Electric Operations' western
wholesale trading.
(b) Does not reflect interest expense allocable to investments in this business
segment.
The Unregulated Energy Trading segment which includes the natural gas and
wholesale electricity trading activities of TPC and PPM, respectively,
recorded $1.7 billion in revenues, a positive gross margin of $19 million and
a net loss of $8 million in 1997. TPC, purchased in April 1997, was
anticipated to be dilutive in its first year of operation. For the nine
months owned in 1997 it recorded $816 million of revenues, a gross margin of
$15 million and a net loss of $6 million. Revenues, gross margin and net
income in 1997 included $19 million, $14 million and $3 million,
respectively, relating to assets of TPC that were sold in December 1997. PPM
continued its expansion in the eastern United States unregulated electricity
trading markets with revenues of $913 million and a gross margin of $4
million on electricity sales of 35.8 million kWh. PPM recorded a net loss of
$2 million for 1997.
Because of the historical and planned increase in trading volumes, revenues
and associated working capital requirements, the Company's Board of Directors
has set global financial risk limits and net position limits applicable to
both regulated and unregulated energy trading. In addition, the Board has
delegated routine risk oversight to the Risk Management Oversight Committee
(the "RMOC"), which approves trading policies and procedures and portfolio
market risk. The Company also has an independent risk manager who monitors
market trading risk and reports such risks daily to the RMOC and other key
management.
- -------------------------------------------------------------------------------
P. 34 PACIFICORP
OTHER OPERATIONS
EARNINGS CONTRIBUTION
MILLIONS OF DOLLARS 1997 1996 1995
- -----------------------------------------------------------------
PFS $30.2 $34.1 $30.4
PGC 10.4 7.8 5.6
Tax settlement -- -- 32.2
Holdings and other (50.2) (14.8) 18.0
------------------------------
$(9.6) $27.1 $86.2
------------------------------
------------------------------
During 1997, Other Operations included the activities of Holdings, PacifiCorp
Financial Services ("PFS"), PGC and several start-up-phase energy ventures.
Holdings recorded an after-tax loss of $65 million, or $0.22 per share, in
1997 associated with closing foreign currency options and initial option
premium costs relating to the Company's tender offer for TEG, as discussed
below. Holdings also recorded an after-tax gain of $30 million, or $0.10 per
share, relating to the sale of PGC in November 1997. PGC had ownership
interests in numerous independent power production and cogeneration
businesses and for the ten months held in 1997, PGC reported net income of
$10 million, compared to $8 million for all of 1996.
PFS has tax-advantaged investments in affordable housing and leasing
operations that consist principally of aircraft leases. For 1997, PFS
reported net income of $30 million, a $4 million decrease from 1996. In
February 1998, PFS agreed to sell its investments in affordable housing for
approximately $81 million and assumption of debt of approximately $161
million. This sale transaction will not have a material impact on 1998
earnings.
Holdings and other reported 1997 interest expense of $46 million, a $13
million increase over 1996. This increase was attributable to higher average
debt balances due in large part to Holdings' investment in Hazelwood.
1996 COMPARED TO 1995 -- The $59 million decrease in earnings contribution of
Other Operations was primarily attributable to the 1995 tax settlement that had
the effect of reducing Domestic Electric Operations' earnings by $32 million and
increasing Other Operations' earnings by this same amount. The increase in
earnings from PFS and PGC were more than offset by a $33 million decrease in the
earnings of Holdings and other. This decrease was attributable to $14 million of
increased interest expense, as well as expenses incurred by several start-
up-phase investments in which investments in personnel and other resources were
made. The increased interest expense was attributable in part to Holdings'
investment in Powercor.
- -------------------------------------------------------------------------------
PACIFICORP P. 35
LIQUIDITY AND CAPITAL RESOURCES
CASH FLOW SUMMARY
FORECASTED(a) ACTUAL
MILLIONS OF DOLLARS/FOR THE YEAR 2000 1999 1998 1997 1996 1995
- -----------------------------------------------------------------------------------------------------------------------------
NET CASH FLOW FROM
CONTINUING OPERATIONS
Domestic Electric Operations $727 $718 $ 700
Australian Electric Operations 101 95 10
Unregulated Energy Trading (8) (2) --
Other Operations 4 75 59
----------------------------------
Total 824 886 769
Cash Dividends Paid 341 346 346
----------------------------------
NET $550-600 $525-575 $400-450 $483 $540 $ 423
- -------------------------------------------------------------------------------------------------------------------------
CONSTRUCTION
Domestic Electric Operations $ 465 $ 480 $ 505 $490 $442 $ 455
Australian Electric Operations 60 55 65 79 80 2
Unregulated Energy Trading -- -- -- 4 -- --
Other Operations -- -- -- 9 7 --
- -------------------------------------------------------------------------------------------------------------------------
Total 525 535 570 582 529 457
ACQUISITIONS AND INVESTMENTS
Domestic Electric Operations -- -- 45 -- 154 --
Australian Electric Operations -- 5 15 5 145 1,589
Unregulated Energy Trading -- -- 5 71 -- --
Other Operations 100 100 195(b) 131 49 44
- -------------------------------------------------------------------------------------------------------------------------
Total 100 105 260 207 348 1,633
- -------------------------------------------------------------------------------------------------------------------------
TOTAL CAPITAL SPENDING $ 625 $ 640 $ 830 $789 $877 $2,090
- -------------------------------------------------------------------------------------------------------------------------
MATURITIES OF LONG-TERM DEBT
Domestic Electric Operations $ 180 $ 299 $ 197 $208 $182 $ 51
Australian Electric Operations -- -- -- 3 42 --
Other Operations 1 1 169 10 19 29
- -------------------------------------------------------------------------------------------------------------------------
Total $ 181 $ 300 $ 366 $221 $243 $ 80
- -------------------------------------------------------------------------------------------------------------------------
Other Refinancings $699 $ 42 $ 125
- -------------------------------------------------------------------------------------------------------------------------
(a) Does not include forward-looking information with regard to the proposed
acquisition of TEG.
(b) Assumes international energy investments.
- -------------------------------------------------------------------------------
P. 36 PACIFICORP
- -------------------------------------------------------------------------------
OPERATING ACTIVITIES
Cash flows from continuing operations decreased $62 million from 1996 to 1997.
Cash expenditures relating to the proposed acquisition of TEG were the primary
cause of the $71 million decrease in operating cash flows from Other Operations.
INVESTING ACTIVITIES
During 1997, the Company generated $1.8 billion of cash from asset sales. Apart
from the asset sales, investing activities were comprised primarily of capital
spending to improve and expand existing operations and the acquisition of TPC.
In order to sharpen its focus in the energy sector and as part of the
financing of the proposed TEG acquisition, the Company sold PTI in December
1997 for $1.5 billion in cash plus the assumption of PTI's debt and, in
November 1997, PGC was sold for $150 million in cash, which included
settlement of intercompany account balances.
On April 15, 1997, the Company expanded into natural gas marketing by
acquiring all of the outstanding shares of common stock of TPC, a natural gas
gathering, processing, storage and marketing company based in Houston, Texas,
for approximately $265 million in cash and assumed debt of approximately $140
million. In December 1997, TPC sold its natural gas gathering and processing
systems for $195 million in cash before tax payments of $23 million. During
1997, the Company continued to invest in new, energy-related ventures and
expects to continue to do so during 1998.
Construction spending for production, transmission, distribution and other
purposes at Domestic Electric Operations increased from $442 million in 1996
to $490 million in 1997.
The Company believes that its existing and available capital resources are
sufficient to meet working capital, dividend and construction needs in 1998.
PLANNED EXPANSION
The Company continuously explores opportunities for growth in unregulated
domestic and international energy markets. The Company believes the experience
gained by focusing on the unregulated marketplace will facilitate the conversion
of the Company's Domestic Electric Operations to a market driven by customer
choice.
PROPOSED ACQUISITION
On June 13, 1997, PacifiCorp announced a cash tender offer for TEG. TEG is a
diversified international energy group with operations in the United Kingdom
(the "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 (the "MMC") 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
(see Notes 3 and 15) 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 approximately 46 million 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 15% of the outstanding share
capital of TEG.
The Company is required under the rules of the UK takeover code to
demonstrate that it has both adequate committed financing and the appropriate
amount of sterling to eliminate the risk of exchange rate changes between the
offer announcement date and the expected closing date. The Company met these
requirements with its acquisition finance facilities and cash resources and
by entering into foreign currency exchange contracts. Because the underlying
asset has not been acquired, these foreign currency exchange contracts do not
meet the criteria for hedge accounting and as a result are required to be
marked-to-market in each accounting period while outstanding.
The Company estimates that as of December 31, 1997, it had incurred
approximately $68 million of pretax costs relating to the TEG transaction for
bank commitment and facility fees, legal expenses and other related costs. As
a result of the TU offer, there is risk that a transaction with TEG will not
occur. If it becomes likely that the transaction will not occur or
significant uncertainty arises, the Company will write off these transaction
costs as a charge to income.
- -------------------------------------------------------------------------------
PACIFICORP P. 37
CAPITALIZATION
MILLIONS OF DOLLARS
EXCEPT PERCENTAGES 1997 1996
- --------------------------------------------------------------------------------
Long-term debt $4,239 43% $ 4,653 45%
Common equity 4,321 44 4,032 39
Short-term debt 555 5 903 9
Preferred stock 241 2 314 3
Preferred securities
of Trusts 340 4 210 2
Quarterly income
debt securities 176 2 176 2
-----------------------------------------------
Total
Capitalization $9,872 100% $10,288 100%
-----------------------------------------------
-----------------------------------------------
VARIABLE RATE LIABILITIES
MILLIONS OF DOLLARS 1997 1996
- -----------------------------------------------------
Domestic Electric Operations $ 760 $1,090
Australian Electric Operations 269 511
Holdings and other 26 202
-------------------
$1,055 $1,803
-------------------
-------------------
Percentage of Total Capitalization 11% 18%
The Company manages its capitalization and liquidity position in a
consolidated manner through policies established by senior management and
approved by the Finance Committee of the Board of Directors. These policies
have resulted from a review of historical and projected practices for
businesses and industries that have financial and operating characteristics
similar to PacifiCorp and its principal business operations.
The Company's policies attempt to balance the interests of its shareholders,
ratepayers and creditors. In addition, given the changes that are occurring
within the industry and market segments in which the Company operates, these
policies must remain sufficiently flexible to allow the Company to respond to
these developments.
On a consolidated basis, the Company attempts to maintain total debt at 48%
to 54% of capitalization. The debt to capitalization ratio was 50% at
December 31, 1997 after giving effect to before mentioned asset sales.
The Company continually evaluates the advantages of common stock issuances in
the context of its current capital structure, financing needs and market
price. Depending on this evaluation and events surrounding the TEG
acquisition, the Company may offer additional shares of common stock to the
public in 1998.
EQUITY AND DEBT TRANSACTIONS
In August 1997, a wholly owned subsidiary trust (the "Trust") issued, in a
public offering, 5.4 million of its 7.70% Preferred Securities, Series B, for
net proceeds of $135 million. The sole asset of the Trust is $139 million of
Series D Debentures issued by the Company to the Trust.
During 1997, the Company also issued 1.8 million shares of its common stock
under the dividend reinvestment and stock purchase plan, raising $37 million.
In March and September 1997, the Company redeemed all outstanding shares of
its $7.12 and $1.98 No Par Serial Preferred Stock, respectively. The
aggregate stated value of the shares redeemed was $72 million.
In July 1997, the Company issued $300 million of secured medium-term notes in
the form of First Mortgage and Collateral Trust Bonds as follows: $175
million of 6.75% notes due July 15, 2004 and $125 million of 7% notes due
July 15, 2009.
In early 1998, Australian Electric Operations issued $400 million of 6.15%
United States denominated notes due 2008. The funds were used to repay
Australian bank bill borrowings.
AVAILABLE CREDIT FACILITIES
At December 31, 1997, PacifiCorp had $700 million of committed bank revolving
credit agreements. Regulatory authorities limited PacifiCorp to $1 billion of
short-term debt, of which $303 million was outstanding at December 31, 1997.
At December 31, 1997, subsidiaries of PacifiCorp had $1 billion of committed
bank revolving credit agreements. The Company had $878 million of short-term
debt classified as long-term debt at December 31, 1997, as it had the intent
and ability to support short-term borrowings through the various revolving
credit facilities on a long-term basis. See Notes 6 and 7 to the Consolidated
Financial Statements for additional information.
LIMITATIONS
In addition to the Company's capital structure policies, its debt capacity is
also governed by its credit agreements. Based on the Company's most restrictive
credit agreements, management believes PacifiCorp and its subsidiaries could
have borrowed an additional $2.2 billion of debt at December 31, 1997.
PacifiCorp's principal debt limitation is a 60% debt to capitalization test
contained in its principal credit agreements. Considering such limitation, an
additional $560 million of debt was available to PacifiCorp at December 31,
1997.
- -------------------------------------------------------------------------------
P. 38 PACIFICORP
- -------------------------------------------------------------------------------
Under the Company's principal credit agreement, it is an event of default if
any person or group acquires 35% or more of the Company's common shares or
if, during any period of 14 consecutive months, individuals who were
directors of the Company on the first day of such period (and any new
directors whose election or nomination was approved by such individuals and
directors) cease to constitute a majority of the Board of Directors.
RISK MANAGEMENT
The risk management process established by the Company is designed to measure
both quantitative and qualitative risks in its businesses. Two senior risk
management committees have been established to review these risks on a
regular basis. The Company is exposed to market risk, including changes in
interest rates, currency exchange rates and certain commodity prices.
To manage the volatility relating to these exposures, the Company enters into
various derivative transactions pursuant to the Company's policies on hedging
practices. Derivative positions are monitored using techniques such as market
value, sensitivity analysis and a value at risk model.
The tests discussed below for exposure to interest rate and currency exchange
rate fluctuations are based on a Value at Risk ("VAR") approach using a
one-year horizon and a 95% confidence level and assuming a one-day holding
period in normal market conditions. The model assumes that financial returns
are log normally distributed. Estimates of volatility are drawn from actual
historical market volatility calculated over the past 250-day period. The
model includes all the Company's debt as well as all interest rate and
foreign exchange derivative contracts. The interest rate exposure is
primarily related to long-term debt with fixed interest rates. The VAR model
is a risk analysis tool which measures the potential losses in fair value,
earnings or cash flow from changes in market conditions and does not purport
to represent actual losses in fair value that may be incurred by the Company,
nor does it consider the potential effect of favorable changes in market
factors.
INTEREST RATE EXPOSURE
The Company uses interest rate swaps, forwards, futures and collars to adjust
the characteristics of its liability portfolio, allowing the Company to
establish a mix of fixed or variable interest rates on its outstanding debt.
Based on the Company's overall interest rate exposure, the estimated maximum
potential one-day loss in fair value as a result of a near-term change in
interest rates, within a 95% confidence level using historical interest rate
movements based on the VAR model, was $28 million at December 31, 1997. This
interest rate exposure is primarily related to long-term debt with fixed
interest rates.
CURRENCY RATE EXPOSURE
The Company utilizes foreign currency hedging activities to protect against
the volatility associated with its net investment in Australian Electric
Operations. Corporate policy prescribes the range of allowable foreign
currency hedging activity. Results of hedging activities relating to foreign
net asset exposure are reflected in the currency translation adjustments
section of shareholders' equity, offsetting a portion of the translation of
the net assets of Australian Electric Operations.
Gains and losses related to qualifying hedges of foreign currency firm
commitments (or anticipated transactions) are deferred on the balance sheet
and are included in the basis of the underlying transactions. To the extent
that a qualifying hedge is terminated or ceases to be effective as a hedge,
any deferred gains and losses up to that point continue to be deferred and
are included in the basis of the underlying transaction. To the extent that
anticipated transactions are no longer likely to occur, the related hedges
are closed with gains or losses charged to earnings on a current basis.
Based on the Company's overall currency rate exposure at December 31, 1997,
including derivative instruments, a near-term change in currency rates within
a 95% confidence level based on historical currency rate movements, would not
materially affect the consolidated financial position, results of operations,
or cash flows of the Company.
COMMODITY PRICE EXPOSURE
The price of electricity and natural gas commodities are subject to
fluctuations due to unpredictable factors, such as weather, which impacts
supply and demand. To reduce price risk caused by electricity and natural gas
market fluctuations, the Company generally follows a policy of hedging a
portion of its purchase and sales commitments. The instruments used are
principally readily marketable exchange traded futures contracts which are
designated as hedges. The Company has also utilized electricity forward
contacts (referred to as "contract for differences") to hedge exposure to
electricity price risk on anticipated transactions or firm commitments in its
Australian Electric Operations. Under these forward contracts, the Company
receives or makes payment based on a differential between a contracted price
and the actual spot market of electricity. Additionally, electricity futures
contracts are utilized to hedge Domestic Electric Operations' excess or
shortage of net electricity for future months. The changes in market value of
such contracts have a high correlation to the price changes of the hedged
commodity.
- -------------------------------------------------------------------------------
PACIFICORP P. 39
Gains and losses relating to qualifying hedges of firm commitments or
anticipated inventory transactions are deferred on the balance sheet and
included in the basis of the underlying transactions.
A sensitivity analysis has been prepared to estimate the Company's exposure
to market risk of its derivative position for both natural gas and
electricity. The Company's daily commodity derivative position consists of
exchange traded contracts and futures contracts that hedge portions of
commodity delivery requirements. The fair value of such positions are a
summation of the fair values calculated for each commodity derivative by
valuing each position at quoted futures prices or assumed forward prices.
Market risk is estimated as the potential loss in fair value, earnings or
cash flows resulting from a hypothetical 10% adverse change in such prices.
Based on the Company's derivative price exposure at December 31, 1997, a
near-term adverse change in commodity prices of 10% would have an impact on
results of operations and cash flows of approximately $39 million before
income taxes.
INFLATION
Due to the capital-intensive nature of the Company's core businesses,
inflation may have a significant impact on replacement of property,
acquisition and development activities and final mine reclamation costs. To
date, management does not believe that inflation has had a significant impact
on any of the Company's other businesses.
YEAR 2000
PacifiCorp has initiated an enterprise-wide program to assess and mitigate or
eliminate the business risk associated with year 2000 issues within
PacifiCorp's information technology and communication systems, as well as
similar risks related to transactions with other businesses. The systems that
could be affected by year 2000 issues have been identified and an
implementation plan has been developed. It is not certain whether the
Company's year 2000 project will be completed on a timely basis or what the
impact of third-party computer system failures might be. The Company
estimates that it will incur expenses of approximately $12 million to $20
million for management information technology systems over the next two years
on the year 2000 project. The Company has not yet determined the amount of
year 2000 project expenses it will incur related to its operations process
control systems.
NEW ACCOUNTING STANDARDS
In June 1997, the Financial Accounting Standards Board (the "FASB") issued SFAS
130, "Reporting Comprehensive Income," and SFAS 131, "Disclosures About Segments
of an Enterprise and Related Information." SFAS 130 establishes standards for
reporting and display of comprehensive income in financial statements. SFAS 131
requires that companies disclose segment data based on how management makes
decisions about allocating resources to segments and measuring performance. In
February 1998, the FASB issued SFAS 132, "Employers' Disclosures About Pensions
and Other Postretirement Benefits." These standards are effective for fiscal
years beginning after December 15, 1997. Adoption of these standards may result
in additional financial disclosure but will not have an effect on the Company's
financial position or results of operations.
FORWARD-LOOKING STATEMENTS
The information in the tables and text in this document includes certain
forward-looking statements that involve a number of risks and uncertainties that
may influence the financial performance and earnings of the Company. When used
in this "Management's Discussion and Analysis of Financial Condition and Results
of Operations," the words "estimates," "expects," "anticipates," "forecasts,"
"plans," "intends" and variations of such words and similar expressions are
intended to identify forward-looking statements that involve risks and
uncertainties. There can be no assurance the results predicted will be realized.
Actual results will vary from those represented by the forecasts, and those
variations may be material.
The following factors are among the factors that could cause actual results
to differ materially from the forward-looking statements: utility commission
practices; regional and international economic conditions; weather variations
affecting customer usage; competition in bulk power and natural gas markets
and hydroelectric and natural gas production; 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.
- -------------------------------------------------------------------------------
P. 40 PACIFICORP
REPORT OF MANAGEMENT
The management of PacifiCorp is responsible for preparing the accompanying
consolidated financial statements and for their integrity and objectivity.
The statements were prepared in accordance with generally accepted accounting
principles. The financial statements include amounts that are based on
management's best estimates and judgments. Management also prepared the other
information in the annual report and is responsible for its accuracy and
consistency with the financial statements.
The Company's financial statements were audited by Deloitte & Touche LLP
("Deloitte & Touche"), independent public accountants. Management made
available to Deloitte & Touche all the Company's financial records and
related data, as well as the minutes of shareholders' and directors' meetings.
Management of the Company established and maintains an internal control
structure that provides reasonable assurance as to the integrity and
reliability of the financial statements, the protection of assets from
unauthorized use or disposition and the prevention and detection of
materially fraudulent financial reporting. The Company maintains an internal
auditing program that independently assesses the effectiveness of the
internal control structure and recommends possible improvements. Deloitte &
Touche considered that internal control structure in connection with their
audit. Management reviews significant recommendations by the internal
auditors and Deloitte & Touche concerning the Company's internal control
structure and ensures appropriate cost-effective actions are taken.
The Company's "Guide to Business Conduct" is distributed to employees
throughout the Company to provide a basis for ethical standards and conduct.
The guide addresses, among other things, potential conflicts of interests and
compliance with laws, including those relating to financial disclosure and
the confidentiality of proprietary information. In early 1998, the Company
formed a Business Conduct Group in order to dedicate more resources to
business conduct issues, and to provide more consistent and thorough
communications and training in legal compliance and ethical conduct.
The Audit Committee of the Board of Directors is comprised solely of outside
directors. It meets at least quarterly with management, Deloitte & Touche,
internal auditors and counsel to review the work of each and ensure the
Committee's responsibilities are being properly discharged. Deloitte & Touche
and internal auditors have free access to the Committee, without management
present, to discuss, among other things, their audit work and their
evaluations of the adequacy of the internal control structure and the quality
of financial reporting.
/s/ Richard T. O'Brien
RICHARD T. O'BRIEN
Senior Vice President and Chief Financial Officer
INDEPENDENT AUDITORS' REPORT
TO THE SHAREHOLDERS AND
BOARD OF DIRECTORS OF PACIFICORP:
We have audited the accompanying consolidated balance sheets of PacifiCorp
and subsidiaries as of December 31, 1997 and 1996, and the related statements
of consolidated income and retained earnings and of consolidated cash flows
for each of the three years in the period ended December 31, 1997. These
financial statements are the responsibility of the Company's management. Our
responsibility is to express an opinion on these financial statements based
on our audits.
We conducted our audits in accordance with generally accepted auditing
standards. Those standards require that we plan and perform the audit to
obtain reasonable assurance about whether the financial statements are free
of material misstatement. An audit includes examining, on a test basis,
evidence supporting the amounts and disclosures in the financial statements.
An audit also includes assessing the accounting principles used and
significant estimates made by management, as well as evaluating the overall
financial statement presentation. We believe that our audits provide a
reasonable basis for our opinion.
In our opinion, such financial statements present fairly, in all material
respects, the consolidated financial position of PacifiCorp and subsidiaries
at December 31, 1997 and 1996, and the results of their operations and their
cash flows for each of three years in the period ended December 31, 1997, in
conformity with generally accepted accounting principles.
/s/ Deloitte & Touche LLP
DELOITTE & TOUCHE LLP
Portland, Oregon
February 3, 1998 (March 2, 1998 as to Note 2)
- -------------------------------------------------------------------------------
PACIFICORP P. 41
STATEMENTS OF CONSOLIDATED INCOME AND RETAINED EARNINGS
MILLIONS OF DOLLARS, EXCEPT PER SHARE AMOUNTS/FOR THE YEAR 1997 1996 1995
- -----------------------------------------------------------------------------------------------
REVENUES $6,278.0 $3,803.7 $2,806.8
-----------------------------------
EXPENSES
Operations and maintenance 4,394.0 1,949.3 1,291.6
Administrative and general 334.4 244.8 186.6
Depreciation and amortization 476.9 423.8 333.7
Taxes, other than income taxes 99.8 99.4 104.3
Special charges 170.4 -- --
-----------------------------------
Total 5,475.5 2,717.3 1,916.2
-----------------------------------
INCOME FROM OPERATIONS 802.5 1,086.4 890.6
-----------------------------------
INTEREST EXPENSE AND OTHER
Interest expense 439.5 415.0 336.4
Interest capitalized (12.5) (11.4) (14.9)
Minority interest and other 40.6 16.2 (24.7)
-----------------------------------
Total 467.6 419.8 296.8
-----------------------------------
Income from continuing operations
before income taxes 334.9 666.6 593.8
Income tax expense 109.5 236.4 191.8
-----------------------------------
INCOME FROM CONTINUING OPERATIONS
BEFORE EXTRAORDINARY ITEM 225.4 430.2 402.0
DISCONTINUED OPERATIONS (less applicable
income tax expense: 1997/$363.4,
1996/$47.5 and 1995/$47.0) 454.3 74.7 103.0
EXTRAORDINARY LOSS FROM REGULATORY
ASSET IMPAIRMENT (less applicable
income tax expense of $9.6) (16.0) -- --
-----------------------------------
NET INCOME 663.7 504.9 505.0
RETAINED EARNINGS, JANUARY 1 782.8 632.4 474.3
Cash dividends declared
Preferred stock (20.0) (29.1) (38.4)
Common stock per share of $1.08 (320.0) (317.9) (306.6)
Preferred stock retired (0.2) (7.5) (1.9)
-----------------------------------
RETAINED EARNINGS, DECEMBER 31 $1,106.3 $782.8 $ 632.4
-----------------------------------
EARNINGS ON COMMON STOCK $ 640.9 $475.1 $ 466.3
AVERAGE NUMBER OF COMMON SHARES
OUTSTANDING -- basic (Thousands) 296,094 292,424 284,272
EARNINGS PER COMMON SHARE
-- BASIC AND DILUTIVE
Continuing operations $0.68 $1.37 $ 1.28
Discontinued operations 1.53 0.25 0.36
Extraordinary item (0.05) -- --
-----------------------------------
Total $ 2.16 $ 1.62 $ 1.64
-----------------------------------
-----------------------------------
(See accompanying Notes to Consolidated Financial Statements)
- -------------------------------------------------------------------------------
P. 42 PACIFICORP
STATEMENTS OF CONSOLIDATED CASH FLOWS
MILLIONS OF DOLLARS/FOR THE YEAR 1997 1996 1995
- -----------------------------------------------------------------------------------------------
CASH FLOWS FROM OPERATING ACTIVITIES
Net Income $ 663.7 $ 504.9 $ 505.0
Adjustments to reconcile net income
to net cash provided by continuing
operations
Income from discontinued operations (89.2) (74.7) (103.0)
Gain on disposal of discontinued operations (365.1) -- --
Extraordinary loss from regulatory
asset impairment 16.0 -- --
Depreciation and amortization 492.2 440.5 372.2
Deferred income taxes and investment
tax credits -- net (81.6) 26.1 38.0
Special charges 170.4 -- --
Gain on sale of subsidiary (56.5) -- --
Other 19.0 (27.1) 12.0
Accounts receivable and prepayments (281.6) (158.5) (36.0)
Materials, supplies, fuel stock and inventory (3.4) 26.8 (11.2)
Accounts payable and accrued liabilities 340.1 148.1 (7.6)
---------------------------------------
Net cash provided by continuing operations 824.0 886.1 769.4
Net cash provided by (used in)
discontinued operations 10.1 39.6 (94.1)
---------------------------------------
Net Cash Provided by Operating Activities 834.1 925.7 675.3
---------------------------------------
CASH FLOWS FROM INVESTING ACTIVITIES
Construction (581.7) (528.4) (456.8)
Operating companies and assets acquired (135.0) (199.4) (1,633.7)
Investments in and advances to
affiliated companies -- net (72.3) (148.4) 0.3
Proceeds from sales of assets 1,666.3 49.3 137.9
Proceeds from sales of finance assets and
principal payments 103.2 55.8 36.6
Other (58.5) (10.5) (27.4)
---------------------------------------
Net Cash Provided by (Used in) Investing Activities 922.0 (781.6) (1,943.1)
---------------------------------------
CASH FLOWS FROM FINANCING ACTIVITIES
Changes in short-term debt (494.4) (247.6) 499.6
Proceeds from long-term debt 726.4 567.6 1,376.9
Proceeds from issuance of common stock 37.2 221.3 0.4
Proceeds from issuance of preferred securities
of Trust holding solely PacifiCorp debentures 130.6 209.6 --
Dividends paid (341.2) (346.4) (346.5)
Repayments of long-term debt (919.8) (284.5) (204.4)
Redemptions of capital stock (72.2) (221.6) (2.6)
Other (89.8) (49.9) (53.2)
---------------------------------------
Net Cash Provided by (Used in) Financing Activities (1,023.2) (151.5) 1,270.2
---------------------------------------
Increase/(Decrease) in Cash and Cash Equivalents 732.9 (7.4) 2.4
Cash and Cash Equivalents at Beginning of Year 8.4 15.8 13.4
---------------------------------------
Cash and Cash Equivalents at End of Year $ 741.3 $8.4 $15.8
---------------------------------------
---------------------------------------
(See accompanying Notes to Consolidated Financial Statements)
- -------------------------------------------------------------------------------
PACIFICORP P. 43
CONSOLIDATED BALANCE SHEETS
ASSETS
MILLIONS OF DOLLARS/DECEMBER 31 1997 1996
- -------------------------------------------------------------------------------
CURRENT ASSETS
Cash and cash equivalents $ 741.3 $ 8.4
Accounts receivable less allowance for doubtful
accounts: 1997/$18.8 and 1996/$8.5 919.5 620.9
Materials, supplies and fuel stock at average cost 194.3 181.3
Net assets of discontinued operations -- 779.5
Real estate investments held for sale 272.2 --
Other 55.0 71.8
------------------------
Total Current Assets 2,182.3 1,661.9
PROPERTY, PLANT AND EQUIPMENT
Domestic Electric Operations
Production 4,720.6 4,659.2
Transmission 2,087.8 2,069.2
Distribution 3,244.0 3,029.7
Other 1,784.8 1,687.9
Construction work in progress 257.4 252.8
------------------------
Total Domestic Electric Operations 12,094.6 11,698.8
Australian Electric Operations 1,161.2 1,361.9
Other Operations 56.9 68.8
Accumulated depreciation and amortization (4,242.4) (3,862.4)
------------------------
Total Property, Plant and Equipment -- Net 9,070.3 9,267.1
OTHER ASSETS
Investments in and advances to affiliated companies 281.6 253.9
Intangible assets -- net 524.9 480.7
Regulatory assets -- net 871.1 1,022.8
Finance note receivable 211.2 214.6
Finance assets -- net 349.8 425.6
Real estate investments -- 217.0
Deferred charges and other 389.0 268.7
------------------------
Total Other Assets 2,627.6 2,883.3
------------------------
TOTAL ASSETS $13,880.2 $13,812.3
------------------------
------------------------
(See accompanying Notes to Consolidated Financial Statements)
- -------------------------------------------------------------------------------
P. 44 PACIFICORP
LIABILITIES AND SHAREHOLDERS' EQUITY
MILLIONS OF DOLLARS/DECEMBER 31 1997 1996
- --------------------------------------------------------------------------------
CURRENT LIABILITIES
Long-term debt currently maturing $ 365.5 $ 219.8
Notes payable and commercial paper 189.2 683.5
Accounts payable 630.7 477.5
Taxes, interest and dividends payable 701.2 290.8
Customer deposits and other 218.9 83.7
------------------------
Total Current Liabilities 2,105.5 1,755.3
DEFERRED CREDITS
Income taxes 1,676.1 1,801.0
Investment tax credits 135.2 143.2
Other 646.2 727.9
------------------------
Total Deferred Credits 2,457.5 2,672.1
LONG-TERM DEBT 4,414.5 4,829.4
COMMITMENTS AND CONTINGENCIES
(See Note 12) -- --
GUARANTEED PREFERRED BENEFICIAL
INTERESTS IN COMPANY'S JUNIOR
SUBORDINATED DEBENTURES 340.4 209.7
PREFERRED STOCK SUBJECT TO
MANDATORY REDEMPTION 175.0 178.0
PREFERRED STOCK 66.4 135.5
COMMON EQUITY
Common shareholders' capital
shares authorized 750,000,000;
shares outstanding: 1997/296,908,110
and 1996/295,139,753 3,274.2 3,236.8
Retained earnings 1,106.3 782.8
Cumulative currency translation adjustment (59.6) 12.7
------------------------
Total Common Equity 4,320.9 4,032.3
------------------------
TOTAL LIABILITIES AND
SHAREHOLDERS' EQUITY $13,880.2 $13,812.3
------------------------
------------------------
(See accompanying Notes to Consolidated Financial Statements)
- -------------------------------------------------------------------------------
PACIFICORP P. 45
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 1997, 1996 AND 1995
NOTE 1
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
BASIS OF PRESENTATION The consolidated financial statements of PacifiCorp
(the "Company") include its integrated domestic electric utility operating
divisions of Pacific Power and Utah Power and its wholly owned and majority
owned subsidiaries. Major subsidiaries, all of which are wholly owned, are:
PacifiCorp Group Holdings Company, formerly PacifiCorp Holdings, Inc.
("Holdings"), which holds all of the Company's nonintegrated electric utility
investments, including Powercor Australia Limited ("Powercor"), an Australian
electricity distributor purchased December 12, 1995; PacifiCorp Financial
Services, Inc. ("PFS"), a financial services business; PacifiCorp Power
Marketing ("PPM"), engaged in wholesale electricity trading in the eastern
United States energy markets; and TPC Corporation ("TPC"), a natural gas
marketing and storage company, purchased April 15, 1997. Together these
businesses are referred to herein as the Companies. Significant intercompany
transactions and balances have been eliminated.
Investments in and advances to affiliated companies represent investments in
unconsolidated affiliated companies carried on the equity basis, which
approximate the Company's equity in their underlying net book value.
The Company sold its wholly owned telecommunications subsidiary, Pacific
Telecom, Inc. ("PTI"), on December 1, 1997. See Note 3. The Company sold
Pacific Generation Company ("PGC") on November 5, 1997, and the natural gas
gathering and processing assets of TPC on December 1, 1997. In addition, the
Company has signed letters of intent to sell the real estate assets held by
PFS. See Note 15.
USE OF ESTIMATES
The preparation of financial statements in conformity with generally accepted
accounting principles requires management to make estimates and assumptions
that affect the reported amounts of assets and liabilities and disclosure of
contingent assets and liabilities at the date of the financial statements.
Actual results could differ from those estimates.
REGULATION
Accounting for the majority of the domestic electric utility business
conforms with generally accepted accounting principles as applied to
regulated public utilities and as prescribed by agencies and the commissions
of the various locations in which the electric utility business operates. The
Company prepares its financial statements as they relate to Domestic Electric
Operations in accordance with Statement of Financial Accounting Standards
("SFAS") 71, "Accounting for the Effects of Certain Types of Regulation." See
Note 4.
ASSET IMPAIRMENTS
Long-lived assets and certain identifiable intangibles to be held and used by
the Company are reviewed for impairment when events or circumstances indicate
costs may not be recoverable. Impairment losses on long-lived assets are
recognized when book values exceed expected undiscounted future cash flows.
If impairment exists, the asset's book value will be written down to its fair
value.
CASH AND CASH EQUIVALENTS
For the purposes of these financial statements, the Company considers all
liquid investments with original maturities of three months or less to be
cash equivalents.
FOREIGN CURRENCY TRANSLATION
Financial statements for foreign subsidiaries are translated into United
States dollars at end of period exchange rates as to assets and liabilities
and weighted average exchange rates as to revenues and expenses. The
resulting exchange gains or losses are accumulated in the "cumulative
currency translation adjustment" account, a component of common equity. All
gains and losses resulting from foreign currency transactions are included in
the determination of income.
PROPERTY, PLANT AND EQUIPMENT
Property, plant and equipment are stated at original cost of contracted
services, direct labor and materials, interest capitalized during
construction and indirect charges for engineering, supervision and similar
overhead items. The cost of depreciable domestic electric utility properties
retired, including the cost of removal, less salvage, is charged to
accumulated depreciation.
DEPRECIATION AND AMORTIZATION
At December 31, 1997, the average depreciable lives of prop-erty, plant and
equipment by category were: Domestic Electric Operations -- Production, 35
years; Transmission, 42 years; Distribution, 31 years; Other, 16 years; and
Australian Electric Operations, 20 years.
Depreciation and amortization is generally computed by the straight-line
method in the following manner: As prescribed by the Company's various
regulatory jurisdictions for Domestic Electric Operations' regulated assets;
and over the estimated useful lives of the related assets for Domestic
Electric Operations' nonregulated generation resource assets and for other
nonregulated assets. Provisions for depreciation (excluding amortization of
capital leases) in the domestic electric and Australian electric businesses
were 3.4%, 3.2% and 3.0% of average depreciable assets in 1997, 1996 and
1995, respectively.
- -------------------------------------------------------------------------------
P. 46 PACIFICORP
MINE RECLAMATION AND CLOSURE COSTS
The Company expenses current mine reclamation costs and accrues for estimated
final mine reclamation and closure costs using the units-of-production method.
INVENTORY VALUATION
Inventories are generally valued at the lower of average cost or market.
INTANGIBLE ASSETS
Intangible assets consist of: license and other intangible costs relating to
Australian Electric Operations ($393 million and $26 million, respectively,
in 1997 and $460 million and $32 million, respectively, in 1996) and excess
cost over net assets of businesses acquired ($129 million in 1997). These
costs are offset by accumulated amortization ($23 million in 1997 and $11
million in 1996). Licenses and other intangible costs are generally being
amortized over 40 years and excess cost over net assets of businesses
acquired is being amortized over 30 years. Had Australian Electric
Operations' 1996 intangible asset amounts been converted to United States
dollars at 1997 rates, 1996 intangible assets-net would have been $73 million
lower than reported.
FINANCE ASSETS
Finance assets consist of finance receivables, leveraged leases and operating
leases and are not significant to the Company in terms of revenue, net income or
assets. The Company's leasing operations consist principally of leveraged
aircraft leases. Investments in finance assets are net of allowances for credit
losses and accumulated impairment charges of $47 million and $63 million at
December 31, 1997 and 1996, respectively.
DERIVATIVES
Gains and losses on hedges of existing assets and liabilities are included in
the carrying amounts of those assets or liabilities and are recognized in
income as part of the carrying amounts. Gains and losses related to hedges of
anticipated transactions and firm commitments are deferred on the balance
sheet and recognized in income when the transaction occurs. Nonhedged
derivative instruments are marked-to-market with gains or losses recognized
in the determination of net income.
INTEREST CAPITALIZED
Costs of debt and equity applicable to domestic electric utility properties are
capitalized during construction. The composite capitalization rates were 5.7%
for 1997, 5.6% for 1996 and 6.2% for 1995.
INCOME TAXES
The Company uses the liability method of accounting for deferred income
taxes. Deferred tax liabilities and assets reflect the expected future tax
consequences, based on enacted tax law, of temporary differences between the
tax bases of assets and liabilities and their financial reporting amounts.
Prior to 1980, Domestic Electric Operations did not provide deferred taxes on
many of the timing differences between book and tax depreciation. In prior
years, these benefits were flowed through to the utility customer as
prescribed by the Company's various regulatory jurisdictions. Deferred income
tax liabilities and regulatory assets have been established for those flow
through tax benefits. See Note 4.
Investment tax credits for regulated Domestic Electric Operations are
deferred and amortized to income over periods prescribed by the Company's
various regulatory jurisdictions.
Provisions for United States income taxes are made on the undistributed
earnings of the Company's international businesses.
REVENUE RECOGNITION
The Company accrues estimated unbilled revenues for electric services
provided after cycle billing to month-end.
UNREGULATED ENERGY TRADING ACTIVITIES
Revenues and purchased energy expense for the Company's unregulated energy
trading businesses are recorded upon delivery or settlement of natural gas
and electricity.
PREFERRED STOCK RETIRED
Amounts paid in excess of the net carrying value of preferred stock retired are
amortized in accordance with regulatory orders.
STOCK BASED COMPENSATION
The Company has elected to follow Accounting Principles Board Opinion No. 25,
"Accounting for Stock Issued to Employees" ("APB 25") and related
interpretations in accounting for its employee stock options. Under APB 25,
because the exercise price of employee stock options equals the market price of
the underlying stock on the date of grant, no compensation expense is recorded.
EARNINGS PER SHARE
The Company computes Earnings per Share ("EPS") based on SFAS 128, "Earnings per
Share," which was issued during 1997. Basic EPS is computed by dividing earnings
on common stock by the weighted average number of common shares outstanding.
Diluted EPS for the Company is computed by dividing earnings on common stock by
the weighted average number of common shares outstanding, including shares that
would be outstanding assuming the exercise of granted stock options. The
Company's basic and diluted EPS are the same for all periods presented herein.
RECLASSIFICATION
Certain amounts from prior years have been reclassified to conform with the 1997
method of presentation. These reclassifications had no effect on previously
reported consolidated net income.
- -------------------------------------------------------------------------------
PACIFICORP P. 47
NOTE 2
PROPOSED ACQUISITION
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 (the "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 (the
"MMC") 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
(see Notes 3 and 15) 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 approximately 46 million 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 15% of the outstanding share
capital of TEG.
Upon initiation of the original tender offer in June 1997, the Company also
entered into foreign currency exchange contracts. The financing facilities
associated with the June 1997 offer for TEG terminated upon referral to the
MMC and the Company initiated steps to unwind its foreign currency exchange
positions consistent with its policies on derivatives. As a result of the
termination of these positions and initial option costs, the Company realized
an after-tax loss of approximately $65 million, or $0.22 per share, in the
third quarter of 1997.
Additionally, the Company estimates that as of December 31, 1997, it had
incurred approximately $68 million of other pre-tax costs relating to the TEG
transaction for bank commitment and facility fees, legal expenses and other
related costs. There is risk that a transaction with TEG will not occur. If
it becomes likely that the transaction will not occur or significant
uncertainty arises, the Company will write off these transaction costs as a
charge to income.
NOTE 3
DISCONTINUED OPERATIONS
On December 1, 1997, Holdings completed the sale of PTI to Century Telephone
Enterprises, Inc. ("Century"). Pursuant to a stock purchase agreement dated
June 11, 1997, Century acquired all the stock of PTI for $1.5 billion in cash
plus the assumption of PTI's debt of $713 million. The sale resulted in a
gain of $365 million net of income taxes of $306 million, or $1.23 per share.
A portion of the proceeds from the sale of PTI were used to repay short-term
debt of Holdings. The remaining proceeds were invested in short-term money
market instruments and Holdings temporarily advanced excess funds to Domestic
Electric Operations for retirement of short-term debt.
Summarized operating results for PTI, excluding gain on sale, were as follows:
ELEVEN MONTHS FOR THE YEARS
ENDED NOVEMBER 30 ENDED DECEMBER 31
MILLIONS OF DOLLARS 1997 1996 1995
- -------------------------------------------------------------------------------
Revenues $522.4 $521.1 $640.1
----------------------------------------
Income before income taxes $146.8 $122.2 $150.0
Income taxes 57.6 47.5 47.0
----------------------------------------
Net income(a) $89.2 $74.7 $103.0
----------------------------------------
Earnings per share(a) $0.30 $0.25 $0.36
----------------------------------------
(a) Results in 1995 included $37 million, or $0.13 per share, relating to the
sale of PTI's long-distance telecommunications subsidiary.
Net assets of the discontinued operations of PTI consisted of the following:
MILLIONS OF DOLLARS/DECEMBER 31 1996
- ---------------------------------------------
Current assets $ 238.5
Noncurrent assets 1,463.4
Notes payable and commercial paper (18.0)
Long-term debt currently maturing (15.8)
Other current liabilities (136.1)
Long-term debt (527.9)
Noncurrent liabilities (207.4)
Minority interest (17.2)
---------
Net Assets of Discontinued
Operations $ 779.5
---------
- -------------------------------------------------------------------------------
P. 48 PACIFICORP
NOTE 4
ACCOUNTING FOR THE EFFECTS
OF REGULATION
Regulated utilities have historically applied the provisions of SFAS 71 which
is based on the premise that regulators will set rates that allow for the
recovery of a utility's costs, including cost of capital. Accounting under
SFAS 71 is appropriate as long as: rates are established by or subject to
approval by independent, third-party regulators; rates are designed to
recover the specific enterprise's cost-of-service; and in view of demand for
service, it is reasonable to assume that rates are set at levels that will
recover costs and can be collected from customers. In applying SFAS 71, the
Company must give consideration to changes in the level of demand or
competition during the cost recovery period. In accordance with SFAS 71,
Domestic Electric Operations capitalizes certain costs, regulatory assets, in
accordance with regulatory authority whereby those costs will be expensed and
recovered in future periods.
The Emerging Issues Task Force of the Financial Accounting Standards Board
(the "EITF") concluded in 1997 that SFAS 71 should be discontinued when
detailed legislation or regulatory order regarding competition is issued.
Additionally, the EITF concluded that regulatory assets and liabilities
applicable to businesses being deregulated should be written off unless their
recovery is provided for through future regulated cash flows.
In 1996, legislation was passed in California restructuring its electric
utility industry. The restructuring is scheduled to begin on March 31, 1998,
at which time customers will be able to buy their electricity from sources
other than the local utility. The local utility will continue to provide
distribution services. Legislation was also passed in Montana in 1997 which
established a phased process to introduce price-based competition into the
supply of electricity in Montana. As a result of these legislative actions,
prices for the supply of electric generation in California and Montana are,
or are expected to be, in transition from cost-based regulated rates to rates
determined by competitive market forces.
Regulatory assets-net included the following:
MILLIONS OF DOLLARS/DECEMBER 31 1997 1996
- ---------------------------------------------------------------
Deferred taxes - net(a) $650.1 $ 676.0
Deferred pension costs -- 102.9
Demand-side resource costs 108.3 118.8
Unamortized net loss on reacquired debt 60.6 68.4
Unrecovered Trojan Plant and regulatory
study costs 23.0 26.8
Various other costs 29.1 29.9
---------------------
Total $871.1 $1,022.8
---------------------
---------------------
(a) Excludes $135 million of investment tax credit regulatory liabilities.
The Company has evaluated its regulatory assets and liabilities related to
the generation portion of its business allocable to the states of California
and Montana based upon future regulated cash flows. Accordingly, the Company
ceased the application of SFAS 71 to its generation business allocable to the
states of California and Montana in 1997. Domestic Electric Operations
recorded an extraordinary loss of $16 million, or $0.05 per share, for the
write off of these regulatory assets and liabilities.
The Company operates in five other states (Oregon, Utah, Wyoming, Washington
and Idaho) which are at various stages of addressing the issue of
deregulating the electricity industry. At December 31, 1997, $382 million of
the $871 million total regulatory assets-net was applicable to the generation
assets allocable to these five states. Because of the potential regulatory
and/or legislative actions in these other state jurisdictions, the Company
may have additional regulatory asset write offs and charges for impairment of
long-lived assets in future periods relating to the generation portion of its
business.
Also in 1997, the Company evaluated all its regulatory assets and liabilities
applicable to deferred pension costs which relate primarily to a deferred
compensation plan and early retirement incentive programs in 1987 and 1990
and determined that recovery of these costs was not probable. As a result,
the Company recorded an $87 million write off of its deferred regulatory
pension asset, since the Company does not intend to seek recovery of these
costs. However, the Company will seek recovery for its current and future
pension costs.
In early 1997, the Division of Public Utilities (the "DPU") and the Committee
of Consumer Services (the "CCS") in Utah filed a joint petition with the Utah
Public Service Commission (the "PSC") requesting the PSC to commence
proceedings to establish new rates for Utah customers. The DPU indicated that
rates could be reduced by approximately $54 million. Subsequently in March
1997, the Utah Legislature passed a bill that created a legislative task
force to study electrical restructuring and customer choice issues in the
State of Utah. The bill precluded the PSC from holding hearings on rate
changes and froze prices at January 31, 1997 levels until May 1998, but
allowed for retroactive price changes. The Company agreed to an interim price
decrease to Utah customers of $12.4 million annually beginning on April 15,
1997.
During the freeze period, the PSC proceeded with hearings on the proper
method for cost allocation among PacifiCorp's seven jurisdictions that would
be used in the 1998 rate case. 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 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. The PSC
held hearings in December and an order is expected in early 1998. An
allocation order by itself will not decrease revenues, but will be
incorporated into subsequent rate proceedings which are expected to occur in
mid-1998 and will be combined with other cost increases and decreases to
determine the overall impact to customer rates.
- -------------------------------------------------------------------------------
PACIFICORP P. 49
NOTE 5
SPECIAL CHARGES
In December 1997, Domestic Electric Operations recorded in operating income
special charges of $170 million ($106 million after-tax, or $0.36 per share).
The pretax special charges included write off of $87 million of deferred
regulatory pension assets (see Note 4), a $19 million write off of certain
information system assets associated with the Company's decision to proceed
with an installation of SAP enterprise-wide software and $64 million of costs
associated with the write down of assets and acceleration of reclamation
costs due to the early closure of the Glenrock coal mine. The inability of
the mine to remain competitive has caused it to be uneconomic under current
and expected market conditions due to increased mining stripping ratios, coal
quality and related costs.
Also, in January 1998, the Company announced a plan to reduce its work force
in the United States by approximately 600 positions, or 7% of the work force
in the United States, in 1998. This reduction will be accomplished through a
combination of voluntary early retirement and special severance. Employees
are not required to finalize their acceptance of offers until March 31, 1998.
Based upon the current acceptance rate, the pretax costs are estimated to be
$104 million, which will be recorded in the first quarter of 1998. The
current acceptance rate has exceeded the Company's original estimate.
NOTE 6
SHORT-TERM DEBT AND BORROWING ARRANGEMENTS
The Companies' short-term debt and borrowing arrangements were as follows:
AVERAGE
INTEREST
MILLIONS OF DOLLARS/DECEMBER 31 BALANCE RATE(a)
- ----------------------------------------------------------------
1997
PacifiCorp $182.2 6.5%
Subsidiaries 7.0 5.4
1996
PacifiCorp $549.3 5.6%
Subsidiaries 134.2 5.6
(a) Computed by dividing the total interest on principal amounts outstanding at
the end of the period by the weighted daily principal amounts outstanding.
At December 31, 1997, PacifiCorp's commercial paper and bank line borrowings
were supported by revolving credit agreements totaling $700 million. At
December 31, 1997, subsidiaries had committed bank revolving credit
agreements totaling $1 billion.
The Companies have the intent and ability to support short-term borrowings
through various revolving credit agreements on a long-term basis. At December
31, 1997, PacifiCorp had $121 million and subsidiaries had $757 million of
short-term debt classified as long-term.
- -------------------------------------------------------------------------------
P. 50 PACIFICORP
NOTE 7
LONG-TERM DEBT
The Company's long-term debt was as follows:
MILLIONS OF DOLLARS/DECEMBER 31 1997 1996
- ---------------------------------------------------------------------
PACIFICORP
First mortgage and collateral trust bonds
Maturing 1998 through 2002/5.9%-9.5% $ 882.2 $1,074.5
Maturing 2003 through 2007/6.1%-9% 756.1 587.2
Maturing 2008 through 2012/7%-9.2% 267.6 144.9
Maturing 2013 through 2017/7.3%-8.8% 164.9 167.6
Maturing 2018 through 2022/8.1%-8.5% 175.0 175.0
Maturing 2023 through 2026/6.7%-8.6% 286.5 286.5
Guaranty of pollution control revenue bonds
5.6%-5.7% due 2021 through 2023(a) 71.2 71.2
Variable rate due 2013 through 2024(a)(b) 216.5 216.5
Variable rate due 2005 through 2030(b) 450.7 450.7
Funds held by trustees (9.1) (12.1)
8.4%-8.6% Junior subordinated debentures
due 2025 through 2035 175.8 175.8
Commercial paper(b)(d) 120.6 123.4
Other 25.1 28.2
-----------------------
Total 3,583.1 3,489.4
Less current maturities 194.9 203.8
-----------------------
Total 3,388.2 3,285.6
-----------------------
SUBSIDIARIES
6.8%-12% Notes due through 2020 266.1 268.8
Australian bank bill borrowings(c)(d) 756.6 922.3
Commercial paper and committed bank lines -- 160.0
Variable rate notes due through 2000(b) 12.1 35.8
4.5%-11% Nonrecourse debt due through 2031 160.7 170.8
Other 1.4 2.1
-----------------------
Total 1,196.9 1,559.8
Less current maturities 170.6 16.0
-----------------------
Total 1,026.3 1,543.8
-----------------------
Total $4,414.5 $4,829.4
-----------------------
-----------------------
(a) Secured by pledged first mortgage and collateral trust bonds
generally at the same interest rates, maturity dates and redemption
provisions as the secured pollution control revenue bonds.
(b) Interest rates fluctuate based on various rates, primarily on
certificate of deposit rates, interbank borrowing rates, prime rates or
other short-term market rates.
(c) Interest rates fluctuate based on Australian Bank Bill Acceptance
Rates. A revolving loan agreement requires that at least 50% of the
borrowings must be hedged against variations in interest rates.
Approximately $494 million was hedged at December 31, 1997 at an average
rate of 7.6% and for an average life of 2.6 years.
(d) The Companies have the ability to support short-term borrowings and
current debt being refinanced on a long-term basis through revolving
lines of credit and, therefore, based upon management's intent, have
classified $878 million of short-term debt as long-term debt. In early
1998, Australian Electric Operations issued $400 million of 6.15% Notes
due 2008. At the same time, in order to mitigate foreign currency
exchange risk, Australian Electric Operations entered into a series of
cross currency swaps in the same amount and for the same duration as the
underlying United States denominated notes. The funds were used to repay
Australian bank bill borrowings.
- -------------------------------------------------------------------------------
PACIFICORP P. 51
Approximately $7 billion of the assets of the Companies secure long-term
debt. First mortgage and collateral trust bonds of the Company may be issued
in amounts limited by Domestic Electric Operations' property, earnings and
other provisions of the mortgage indenture.
The junior subordinated debentures are unsecured obligations of the Company
and are subordinated to the Company's first mortgage and collateral trust
bonds, pollution control revenue bonds, commercial paper, bank debt and any
future senior indebtedness.
Nonrecourse notes are secured by assignment of related real estate assets.
The noteholders have no additional recourse to the Company. These long-term
nonrecourse notes are classified short-term due to a pending sale of the real
estate assets.
The annual maturities of long-term debt and redeemable preferred stock
outstanding are $366 million, $300 million, $181 million, $386 million and
$902 million in 1998 through 2002, respectively.
The Company made interest payments, net of capitalized interest, of $416
million, $456 million and $367 million in 1997, 1996 and 1995, respectively.
NOTE 8
GUARANTEED PREFERRED
BENEFICIAL INTERESTS IN
COMPANY'S JUNIOR
SUBORDINATED DEBENTURES
Wholly owned subsidiary trusts of the Company (the "Trusts") have issued, in
public offerings, redeemable preferred securities ("Preferred Securities")
representing preferred undivided beneficial interests in the assets of the
Trusts, with liquidation amounts of $25 per Preferred Security. The sole
assets of the Trusts are Junior Subordinated Deferrable Interest Debentures
of the Company that bear interest at the same rates as the Preferred
Securities, and certain rights under related guarantees by the Company.
Preferred Securities outstanding at December 31 were as follows:
THOUSANDS OF PREFERRED SECURITIES/MILLIONS OF DOLLARS 1997 1996
- --------------------------------------------------------------------------------
8,680 8.25% Cumulative Quarterly
Income Preferred Securities,
Series A, with Trust assets of
$224 million $209.7 $209.7
5,400 7.70% Trust Preferred
Securities, Series B, with
Trust assets of $139 million 130.7 --
----------------
TOTAL $340.4 $209.7
----------------
----------------
NOTE 9
COMMON AND PREFERRED STOCK
COMMON
SHARES SHARES SHARE-
COMMON PREFERRED HOLDERS'
THOUSANDS OF SHARES/MILLIONS OF DOLLARS STOCK STOCK CAPITAL
- -------------------------------------------------------------------------------
AT JANUARY 1, 1995 284,251 10,532 $3,010.6
Sales through Employees'
Stock Plans 26 -- 0.4
Junior subordinated
debentures exchanged
for preferred stock(a) -- (2,233) 1.9
------------------------------------
AT DECEMBER 31, 1995 284,277 8,299 3,012.9
Sales to public 8,790 -- 177.8
Sales through Dividend
Reinvestment and
Stock Purchase Plan 2,073 -- 43.2
Redemptions and repurchases -- (2,342) 2.9
------------------------------------
AT DECEMBER 31, 1996 295,140 5,957 3,236.8
Sales through Dividend
Reinvestment and
Stock Purchase Plan 1,768 -- 37.4
Redemptions and repurchases -- (2,797) --
------------------------------------
AT DECEMBER 31, 1997 296,908 3,160 $3,274.2
------------------------------------
(a) Noncash financing activities in 1995 included the exchange of 8.55%
Series Junior Subordinated Debentures due 2025 for 2,233,037 shares of
$1.98 No Par Serial Preferred Stock with a value of $56 million.
At December 31, 1997, there were 27,126,352 authorized but unissued shares of
common stock reserved for issuance under the Dividend Reinvestment and Stock
Purchase Plan and the Employee Savings and Stock Ownership Plans and for
sales to the public. Eligible employees under the employee plans may direct
their pretax elective contributions into the purchase of the Company's common
stock. The Company makes matching contributions, equal to a percentage of
employee contributions, which are invested in the Company's common stock.
Employee contributions eligible for matching contributions are limited to 6%
of compensation. In early 1998, the Company registered 11,500,000 shares of
its common stock with the Securities and Exchange Commission for issuance
under the PacifiCorp Stock Incentive Plan.
Generally, preferred stock is redeemable at stipulated prices plus accrued
dividends, subject to certain restrictions. Upon involuntary liquidation, all
preferred stock is entitled to stated value or a specified preference amount
per share plus accrued dividends.
- -------------------------------------------------------------------------------
P. 52 PACIFICORP
PREFERRED STOCK OUTSTANDING
THOUSANDS OF SHARES/MILLIONS OF DOLLARS/DECEMBER 31 1997 1996
SERIES SHARES AMOUNT SHARES AMOUNT
- --------------------------------------------------------------------------------------------------
SUBJECT TO MANDATORY REDEMPTION
No Par Serial Preferred, $100 stated value,
16,000 Shares authorized
$7.12 -- $ -- 30 $ 3.0
7.70 1,000 100.0 1,000 100.0
7.48 750 75.0 750 75.0
--------------------------------------------
Total 1,750 $175.0 1,780 $178.0
--------------------------------------------
NOT SUBJECT TO MANDATORY REDEMPTION
No Par Serial Preferred, $25 stated value
$1.16 193 $4.8 193 $ 4.8
1.18 420 10.5 420 10.5
1.28 381 9.5 381 9.5
1.98, Series 1992 -- -- 2,767 69.1
Serial Preferred, $100 stated value,
3,500 Shares authorized
4.52% 2 0.2 2 0.2
4.56 85 8.5 85 8.5
4.72 70 7.0 70 7.0
5.00 42 4.2 42 4.2
5.40 66 6.6 66 6.6
6.00 6 0.6 6 0.6
7.00 18 1.8 18 1.8
5% Preferred, $100 stated value,
127 Shares authorized and
outstanding 127 12.7 127 12.7
--------------------------------------------
Total 1,410 $66.4 4,177 $135.5
--------------------------------------------
--------------------------------------------
Mandatory redemption requirements at stated value plus accrued dividends on
No Par Serial Preferred Stock are as follows: the $7.70 series is redeemable
in its entirety on August 15, 2001; and 37,500 shares of the $7.48 series are
redeemable on each June 15 from 2002 through 2006, with all shares
outstanding on June 15, 2007 redeemable on that date. If the Company is in
default in its obligation to make any future redemptions on the $7.48 series,
it may not pay cash dividends on common stock.
- -------------------------------------------------------------------------------
PACIFICORP P. 53
NOTE 10
FINANCIAL INSTRUMENTS AND
RISK MANAGEMENT
The Company seeks to reduce net income and cash flow exposure to changing
interest and currency exchange rates and commodity price risks through the
use of derivative financial instruments. The Company's participation in
derivative transactions involves instruments that have a close correlation
with its portfolio of assets or liabilities, thereby managing its risk. The
majority of derivatives have been designed for hedging purposes and are not
held or issued for speculative purposes.
NOTIONAL AMOUNTS AND CREDIT EXPOSURE OF DERIVATIVES -- The notional amounts
of derivatives summarized below do not represent amounts exchanged and,
therefore, are not a measure of the exposure of the Company through its use
of derivatives. The amounts exchanged are calculated on the basis of the
notional amounts and other terms of the derivatives, which relate to interest
rates, exchange rates or other indexes.
The Company is exposed to credit-related losses in the event of
nonperformance by counterparties to financial instruments, but it does not
expect any counterparties to fail to meet their obligations given their high
credit rating requirements. The Company's credit policy provides that
counterparties satisfy established credit ratings. The credit exposure of
interest rate, foreign exchange and forward contracts is represented by the
fair value of contracts with a positive fair value at the reporting date.
INTEREST RATE RISK MANAGEMENT -- The Company enters into
various types of interest rate contracts in managing its interest rate risk, as
indicated in the following table:
NOTIONAL AMOUNT
MILLIONS OF DOLLARS/DECEMBER 31 1997 1996
- ----------------------------------------------------
Interest rate swaps $707.5 $846.4
Interest rate collars purchased 42.3 52.0
Interest rate futures and forwards -- 60.0
The Company uses interest rate swaps, collars, futures and forwards to adjust
the characteristics of its liability portfolio, allowing the Company to
establish a mix of fixed or variable interest rates on its outstanding debt.
Additionally, under terms of the variable rate Australian bank bill
borrowings, Australian Electric Operations is required to obtain a fixed
interest rate, via financial derivatives, on at least 50% of the principal
out-standing. The futures and forwards, when used, are accounted for as
hedges of the Australian bank bill borrowings. Interest rate collar
agreements entitle the Company to receive from the counterparties the
amounts, if any, by which the Australian bank bill borrowings interest
payments exceed 8.75% and the Company would pay the counterparties if
interest payments fall below 6.5%-6.8%.
Under the various swap agreements, the Company agrees with other parties to
exchange, at specified intervals, the difference between fixed-rate and
variable-rate interest amounts calculated by reference to an agreed notional
principal amount. The following table indicates the weighted-average interest
rates of the swaps. Average variable rates are based on rates implied in the
yield curve at December 31; these may change significantly, affecting future
cash flows. Swap contracts are principally between one and fifteen years in
duration.
DECEMBER 31 1997 1996
- ----------------------------------------------------
PAY-FIXED SWAPS
Average pay rate 7.7% 7.7%
Average receive rate 6.5 5.6
FOREIGN EXCHANGE RISK MANAGEMENT -- At December 31, 1997, Holdings held three
combined interest rate and currency swaps that terminate in 2002, with an
aggregate notional amount of $268 million to hedge a portion of the exposure
to fluctuations in the Australian dollar relating to its investment in
Powercor. The interest rate portions of these three swaps were effectively
offset in 1997 by the purchase of an overlay swap transaction with
approximately the same terms. The net amounts of these swaps have not had a
significant impact on net income.
At December 31, 1997, Hazelwood Australia, Inc. ("HAI"), a subsidiary of
Holdings, held a foreign currency forward with a notional amount of $146
million to hedge a portion of its exposure to fluctuations in the Australian
dollar relating to its investment in the Hazelwood power station and adjacent
coal mine. This position was closed in January 1998 and HAI received $24
million in cash.
COMMODITY RISK MANAGEMENT -- The Company has utilized electricity forward
contracts (referred to as "contracts for differences") to hedge exposure to
electricity price risk on anticipated transactions or firm commitments in its
Australian Electric Operations. Under these forward contracts, the Company
receives or makes payment based on a differential between a contracted price
and the actual spot market of electricity. Additionally, electricity futures
contracts are utilized to hedge Domestic Electric Operations' excess or
shortage of net electricity for future months.
At December 31, 1997, Australian Electric Operations had 211 forward
contracts with electricity generation companies on notional quantities
amounting to approximately 35.6 million megawatt hours ("mWh") through the
year 2007. The average fixed price to be paid by Australian Electric
Operations was $19.07 per mWh compared to the average price of similar
contracts at December 31, 1997 of $18.66. It is not practicable to determine
the fair value of the forward contracts held by Australian Electric
Operations because of the limited number of transactions and the inactive
trading in the electricity spot market.
- -------------------------------------------------------------------------------
P. 54 PACIFICORP
At December 31, 1997, Domestic Electric Operations and TPC had open NYMEX
futures contracts as follows:
1997 1996
ELECTRICITY GAS ELECTRICITY
- --------------------------------------------------- -----------
OPEN CONTRACTS
(number)
Purchase 489 303 67
Sell 110 1,399 --
NOTIONAL QUANTITIES
(mWh/MMBtu)
Purchase 359,900 3,030,000 49,300
Sell 81,000 13,990,000 --
FAIR MARKET VALUE
(millions of dollars)
Purchase $(0.7) $(1.1) $0.2
Sell 0.1 (0.5) --
TRADING ACTIVITIES -- PPM began trading wholesale power in the eastern United
States energy markets during 1996. Such transactions involve delivery of
electricity, which is accounted for as revenue or purchased power expense. At
December 31, 1997, PPM had open purchase positions for approximately $866
million, or 33 million mWh, and open sell positions for approximately $848
million, or 32 million mWh. At December 31, 1997, TPC had open purchase
positions involving the delivery of natural gas for approximately $35
million, or 19,000 millions of cubic feet ("MMcf"). In addition, TPC had open
sell positions for approximately $17 million or 7,000 MMcf. The fair market
values of these open positions at December 31, 1997 for PPM and TPC were $(1)
million and $6 million, respectively.
NOTE 11
FAIR VALUE OF FINANCIAL INSTRUMENTS
DECEMBER 31, 1997 DECEMBER 31, 1996
---------------------------------------------------
CARRYING FAIR CARRYING FAIR
AMOUNT VALUE AMOUNT VALUE
- -------------------------------------------------------------------------------
Long-term debt $4,755.3 $4,907.2 $5,026.3 $5,100.8
Preferred Securities 340.4 355.4 209.7 210.9
Preferred stock
subject to
mandatory
redemption 175.0 194.1 178.0 195.8
Derivatives relating to
Currency 45.3 45.3 (21.5) (21.5)
Interest (9.4) (54.3) (10.8) (52.5)
The carrying value of cash and cash equivalents, receivables, payables,
accrued liabilities and short-term borrowings approximates fair value because
of the short-term maturity of these instruments. The fair value of the
finance note receivable approximates its carrying value at December 31, 1997.
The fair value of the Company's long-term debt has been estimated by
discounting projected future cash flows, using the current rate at which
similar loans would be made to borrowers with similar credit ratings and for
the same maturities. Current maturities of long-term debt were included. The
fair value of the Preferred Securities was based on closing market prices and
the fair value of redeemable preferred stock was based on bid prices from an
investment bank.
The fair value of interest rate derivatives and currency swaps is the
estimated amount the Company would receive (pay) to terminate the agreements,
taking into account current interest and currency exchange rates and the
current creditworthiness of the agreement counterparties.
NOTE 12
COMMITMENTS AND CONTINGENCIES
The Company is subject to numerous environmental laws including: the Federal
Clean Air Act, as enforced by the Envi-ronmental Protection Agency and
various state agencies; the 1990 Clean Air Act Amendments; the Endangered
Species Act as it relates to certain potentially endangered species of
salmon; the Comprehensive Environmental Response, Compensation and Liability
Act, relating to environmental cleanups; along with the Federal Resource
Conservation and Recovery Act and the Clean Water Act relating to water
quality. These laws could potentially impact future operations. For those
contingencies identified at December 31, 1997, principally the Superfund
sites where the Company has been or may be designated as a potentially
responsible party and Clean Air Act matters, future costs associated with the
disposition of these matters are not expected to be material to the Company's
consolidated financial statements.
The Company's mining operations are subject to reclamation and closure
requirements. The Company monitors these requirements and periodically
revises its cost estimates to meet existing legal and regulatory requirements
of the various jurisdictions in which it operates. Costs for reclamation are
accrued using the units-of-production method such that estimated final mine
reclamation and closure costs are fully accrued at completion of mining
activities, except where the Company has decided to close a mine. When a mine
is closed, the Company records the estimated cost to complete the mine
closure. This is consistent with industry practices, and the Company believes
that it has adequately provided for its reclamation obligations.
- -------------------------------------------------------------------------------
PACIFICORP P. 55
The Company and its subsidiaries are parties to various legal claims, actions
and complaints, certain of which involve material amounts. Although the
Company is unable to predict with certainty whether or not it will ultimately
be successful in these legal proceedings or, if not, what the impact might
be, management currently believes that disposition of these matters will not
have a materially adverse effect on the Company's consolidated financial
statements.
CONSTRUCTION AND OTHER -- Construction and acquisitions are estimated at $830
million for 1998, excluding amounts relating to the proposed acquisition of TEG.
As a part of these programs, substantial commitments have been made.
LEASES -- The Companies have certain properties under leases with various
expiration dates and renewal options. Rentals on lease renewals are subject
to negotiation. Certain leases provide for options to purchase at fair market
value. The Companies are also committed to pay all taxes, expenses of
operation (other than depreciation) and maintenance applicable to the leased
property.
Net rent expense for the years ended December 31, 1997, 1996 and 1995 was $20
million, $12 million and $13 million, respectively.
Future minimum lease payments under noncancelable operating leases are $8
million, $6 million, $5 million, $5 million and $3 million for 1998 through
2002, respectively.
JOINTLY OWNED PLANTS -- At December 31, 1997, Domestic Electric Operations'
participation in jointly owned plants was
as follows:
ELECTRIC PLANT CONSTRUCTION
OPERATIONS' IN ACCUMULATED WORK IN
MILLIONS OF DOLLARS SHARE SERVICE DEPRECIATION PROGRESS
- ------------------------------------------------------------------------------------
Centralia 47.5% $181.5 $111.1 $ 0.5
Jim Bridger
Units
1, 2, 3 and 4 66.7 796.1 320.3 4.5
Trojan(a) 2.5 -- -- --
Colstrip
Units 3 and 4 10.0 205.2 68.0 --
Hunter Unit 1 93.8 260.9 107.1 1.4
Hunter Unit 2 60.3 188.6 71.2 10.3
Wyodak 80.0 304.9 102.9 0.4
Craig Station
Units 1 and 2 19.3 150.6(b) 59.4 1.1
Hayden Station
Unit 1 24.5 18.6(b) 12.0 6.0
Hayden Station
Unit 2 12.6 15.6(b) 8.8 3.4
Hermiston(c) 50.0 156.7 10.9 --
(a) Plant, inventory, fuel and decommissioning costs totaling $23 million
relating to the Trojan Plant were included in regulatory assets-net at
December 31, 1997.
(b) Excludes unallocated acquisition adjustments of $114 million at December
31, 1997.
(c) Additionally, the Company has contracted to purchase the remaining 50% of
the output of the plant.
Under the joint agreements, each participating utility is responsible for
financing its share of construction, operating and leasing costs. Domestic
Electric Operations' portion is recorded in its applicable operations,
maintenance and tax accounts.
LONG-TERM WHOLESALE SALES AND PURCHASED POWER CONTRACTS -- Domestic Electric
Operations manages its energy resource requirements by integrating long-term
firm, short-term and spot market purchases with its own generating resources to
economically dispatch the system and meet commitments for wholesale sales and
retail load growth. The long-term wholesale sales commitments include contracts
with minimum sales requirements of $485 million in 1998, $450 million in 1999,
$415 million in 2000, $316 million in 2001 and $308 million in 2002. As part of
its energy resource portfolio, Domestic Electric Operations acquires a portion
of its power through long-term purchases and/or exchange agreements which
require minimum fixed payments of $320 million in 1998, $316 million in 1999,
$314 million in 2000, $290 million in 2001
and $299 million in 2002. The purchase contracts include agreements with the
Bonneville Power Administration, the Hermiston Plant and a number of
cogenerating facilities.
Excluded from the minimum fixed annual payments above are commitments to
purchase power from several hydroelectric projects under long-term
arrangements with public utility districts. These purchases are made on a
"cost-of-service" basis for a stated percentage of project output and for a
like percentage of project annual costs (operating expenses and debt
service). These costs are included in operations expense. Domestic Electric
Operations is required to pay its portion of the debt service, whether or not
any power is produced. The arrangements provide for nonwithdrawable power and
the majority also provide for additional power, withdrawable by the districts
upon one to five years' notice. For 1997, such purchases approximated 3% of
energy requirements.
At December 31, 1997, Domestic Electric Operations' share of long-term
arrangements with public utility districts was as follows:
GENERATING YEAR CONTRACT CAPACITY PERCENTAGE ANNUAL
FACILITY EXPIRES (kW) OF OUTPUT COSTS(a)
- --------------------------------------------------------------------------------
Wanapum 2009 155,444 18.7% $ 4.4
Priest Rapids 2005 109,602 13.9 3.5
Rocky Reach 2011 64,297 5.3 2.9
Wells 2018 59,617 7.7 2.0
-------------------------------------------------
Total 388,960 $12.8
-------------------------------------------------
-------------------------------------------------
(a) Annual costs, in millions of dollars, include debt service of $7 million.
The Company has a 4% interest in the Intermountain Power Project (the
"Project"), located in central Utah. The Company and the city of Los Angeles
have agreed that the City will purchase capacity and energy from Company
plants equal to the Company's 4% entitlement of the Project at a price
equivalent to 4% of the expenses and debt service of the Project.
- -------------------------------------------------------------------------------
P. 56 PACIFICORP
FUEL CONTRACTS -- Domestic Electric Operations has take or pay coal and natural
gas contracts which require minimum fixed payments of $83 million for 1998 and
1999, $90 million for 2000, $62 million for 2001 and $64 million for 2002.
NOTE 13
INCOME TAXES
The Company's combined federal and state effective income tax rate from
continuing operations was 33% in 1997, 35% in 1996 and 32% in 1995. The
difference between taxes calculated as if the statutory federal tax rate of 35%
was applied to income from continuing operations before income taxes and the
recorded tax expense is reconciled as follows:
MILLIONS OF DOLLARS/FOR THE YEAR 1997 1996 1995
- -------------------------------------------------------------------------------
Computed Federal
Income Taxes $117.2 $233.3 $207.8
------------------------------------
Increase (Reduction) in
Tax Resulting from
Depreciation differences 14.2 12.8 9.7
Investment tax credits (8.5) (9.3) (9.2)
Audit settlement -- 0.5 (16.8)
Affordable housing credits (13.4) (10.6) (8.4)
Other items capitalized
and miscellaneous
differences (9.4) (8.4) (7.7)
------------------------------------
Total (17.1) (15.0) (32.4)
------------------------------------
Federal Income Tax 100.1 218.3 175.4
State Income Tax,
Net of Federal Income Tax
Benefit 9.4 18.1 16.4
------------------------------------
Total Income Tax Expense $109.5 $236.4 $191.8
------------------------------------
------------------------------------
The provision for income taxes is summarized as follows:
MILLIONS OF DOLLARS/FOR THE YEAR 1997 1996 1995
- -------------------------------------------------------------------------------
CURRENT
Federal $173.9 $186.3 $135.8
State 17.2 24.0 16.9
Foreign -- -- 1.1
------------------------------------
Total 191.1 210.3 153.8
------------------------------------
DEFERRED
Federal (70.2) 22.4 37.2
State (2.9) 4.9 9.0
Foreign -- 8.1 1.0
------------------------------------
Total (73.1) 35.4 47.2
------------------------------------
INVESTMENT TAX CREDITS (8.5) (9.3) (9.2)
------------------------------------
Total Income Tax Expense $109.5 $236.4 $191.8
------------------------------------
------------------------------------
The tax effects of significant items comprising the Company's net deferred
tax liability were as follows:
MILLIONS OF DOLLARS/DECEMBER 31 1997 1996
- -----------------------------------------------------------------
DEFERRED TAX LIABILITIES
Property, plant and equipment $1,195.0 $1,177.1
Regulatory assets 704.1 733.1
Other deferred liabilities 84.3 77.9
DEFERRED TAX ASSETS
Regulatory liabilities (54.0) (57.1)
Book reserves not deductible for tax (61.3) (55.0)
Foreign net operating loss (47.5) (28.3)
Foreign currency adjustment (46.4) 8.0
Pension accrual (39.9) (8.1)
Other deferred assets (58.2) (46.6)
------------------------
Net Deferred Tax Liability $1,676.1 $1,801.0
------------------------
------------------------
The Company's 1991, 1992 and 1993 federal income tax returns are currently
under examination by the Internal Revenue Service (the "IRS"). The Company
has received an examination report for 1989 and 1990 proposing adjustments
that would increase current income taxes payable by $14 million. The Company
filed a protest of certain proposed adjustments on July 30, 1996 and is
currently holding discussions with the Appeals Division of the IRS.
The Company made income tax payments of $134 million, $208 million and $186
million in 1997, 1996 and 1995, respectively.
NOTE 14
EMPLOYMENT BENEFIT PLANS
RETIREMENT PLANS -- The Companies have pension plans covering substantially all
of their employees. Benefits under the plan in the United States are based on
the employee's years of service and average monthly pay in the 60 consecutive
months of highest pay out of the last 120 months, with adjustments to reflect
benefits estimated to be received from Social Security. Pension costs are funded
annually by no more than the maximum amount of pension expense which can be
deducted for federal income tax purposes. Unfunded prior service costs are
amortized over the remaining service period of employees expected
to receive benefits. At December 31, 1997, plan assets were
primarily invested in common stocks, bonds and United States government
obligations.
- -------------------------------------------------------------------------------
PACIFICORP P. 57
All permanent employees of Powercor engaged prior to October 4, 1994 are
members of Division B or C of the Superannuation Fund (the "Fund") which
provides defined benefits in the form of pensions (Division B) or lump sums
(Division C). Both defined benefit Funds are closed to new members. Members
who choose to contribute do so at rates of 3% or 6% of eligible salaries.
Powercor employees engaged after October 4, 1994 are members of Division D of
the Fund, which is a defined contribution fund in which members may
contribute up to 20% of eligible salaries. At December 31, 1997, Powercor was
no longer making contributions to Division B and C funds due to surplus
amounts in these funds. During 1997, Powercor contributed to the Division D
Fund at rates ranging from 6%-10% of eligible salaries.
Net pension cost is summarized as follows:
MILLIONS OF DOLLARS/FOR THE YEAR 1997 1996 1995
- -------------------------------------------------------------------------------
Service cost -- benefits earned $27.2 $31.4 $20.7
Interest cost on projected
benefit obligation 81.6 78.3 69.3
Actual gain on plan assets (76.5) (66.3) (120.9)
Net amortization and
deferral 9.2 8.9 81.5
Regulatory deferral
(see Note 4) -- 14.2 29.4
------------------------------------
Net Pension Cost $41.5 $66.5 $80.0
------------------------------------
------------------------------------
The funded status, net pension liability and significant assumptions are as
follows:
MILLIONS OF DOLLARS/DECEMBER 31 1997 1996
- ----------------------------------------------------------------
Actuarial present value of
benefit obligations
Vested benefit obligation $993.5 $913.7
-----------------------
Accumulated benefit obligation 1,052.4 987.6
-----------------------
Projected benefit obligation 1,216.2 1,114.3
Plan assets at fair value 1,003.5 871.0
-----------------------
Projected benefit obligation
in excess of plan assets 212.7 243.3
Unrecognized prior service cost (15.2) (13.7)
Unrecognized net loss (4.9) (86.7)
Unrecognized net obligation (80.0) (10.2)
Minimum liability adjustment 5.5 2.9
-----------------------
Net Pension Liability $118.1 $135.6
-----------------------
-----------------------
Discount rate 6.25%-7% 7.25%-7.5%
Expected long-term rate
of return on assets 7.5%-9.25% 8.5%-9%
Rate of increase in
compensation levels 4%-5% 4.5%-6%
OTHER POSTRETIREMENT BENEFITS -- Domestic Electric Operations provides health
care and life insurance benefits through various plans for eligible retirees
on a basis substantially similar to those who are active employees. The cost
of postretirement benefits is accrued over the active service period of
employees. The transition obligation represents the unrecognized prior
service cost and is being amortized over a period of 20 years. For those
employees retired at January 1, 1993, the Company funds postretirement
benefit expense on a pay-as-you-go basis and has an unfunded accrued
liability of $58 million at December 31, 1997. For those employees retiring
after January 1, 1993, the Company funds postretirement benefit expense
through a combination of funding vehicles. The Company funded $16 million and
$28 million of postretirement benefit expense during 1997 and 1996,
respectively. These funds are invested in common stocks, bonds and United
States government obligations.
The net periodic postretirement benefit cost is summarized as follows:
MILLIONS OF DOLLARS/FOR THE YEAR 1997 1996 1995
- -------------------------------------------------------------------------------
Service cost -- benefits earned $7.2 $6.9 $6.2
Interest cost on accumulated
postretirement
benefit obligation 21.8 21.8 26.7
Amortization of
transition obligation 11.9 12.6 14.0
Regulatory deferral 6.4 3.4 (4.5)
Net asset gain during the period
deferred for future recognition 18.9 3.5 2.6
Actual gain on plan assets (31.5) (12.6) (8.8)
-------------------------------------
Net Periodic Postretirement
Benefit Cost $34.7 $35.6 $36.2
-------------------------------------
-------------------------------------
The accumulated postretirement benefit obligation ("APBO") was as follows:
MILLIONS OF DOLLARS/DECEMBER 31 1997 1996
- -----------------------------------------------------------------
Retirees and dependents $172.2 $168.0
Fully eligible active plan
participants 12.0 10.1
Other active plan participants 143.2 131.0
---------------------
APBO 327.4 309.1
Plan assets at fair value 179.8 135.1
---------------------
APBO in excess of plan assets 147.6 174.0
Unrecognized transition obligation (209.3) (223.2)
Unrecognized net gain 64.3 51.2
---------------------
Accrued Postretirement
Benefit Obligation $2.6 $2.0
---------------------
---------------------
Discount rate 7% 7.5%
Estimated long-term rate of
return on assets 9.3% 9%
Initial health care cost trend
rate -- under 65 8.3% 8.8%
Initial health care cost trend
rate -- over 65 8.3% 8.4%
Ultimate health care cost trend rate 4.5% 4.5%
- -------------------------------------------------------------------------------
P. 58 PACIFICORP
The assumed health care cost trend rate gradually decreases over eight years.
The health care cost trend rate assumption has a significant effect on the
amounts reported. Increasing the assumed health care cost trend rate by one
percentage point would have increased the APBO as of December 31, 1997 by $29
million, and the annual net periodic postretirement benefit costs by $3 million.
POSTEMPLOYMENT BENEFITS -- Domestic Electric Operations provides certain
postemployment benefits to former employees and their dependents during the
period following employment but before retirement. The costs of these
benefits are accrued as they are incurred. Benefits include salary
continuation, severance benefits, disability benefits and continuation of
health care benefits for terminated and disabled employees and workers
compensation benefits. Accrued costs for postemployment benefits were $13
million and $5 million in 1997 and 1996, respectively.
PENDING EARLY RETIREMENT OFFER -- The Company has offered enhanced early
retirement to approximately 1,200 employees who have until March 31, 1998 to
accept the offer. The cost of the enhancement will have an impact on the funding
status of the retirement and other postretirement benefit plans. However, the
Company intends to fund a substantial portion of the increase in the accumulated
benefit obligation.
STOCK INCENTIVE PLAN -- During 1997, the Company formalized
a Stock Incentive Plan (the "Plan") under which selected employees, officers and
directors and selected nonemployee agents, consultants, advisors and independent
contractors may be granted options to purchase the Company's common stock.
Options generally become exercisable in three equal installments on each of the
first through third anniversaries of the grant date and have a maximum term of
ten years. During 1997, options were granted to 193 officers and employees.
Under the Plan options for 1,322,500 shares were granted on June 3, 1997 and
options for 193,500 shares were granted on August 12, 1997 at exercise prices of
$19.75 and $21.25, respectively. The weighted average estimated fair value of
options granted was $2.78 per share. These options to purchase the Company's
common stock were issued at 100% of market price on the dates the options were
granted. None of the options were exercisable as of December 31, 1997. During
1997, options for 19,000 shares relating to the June 3, 1997 grant were
forfeited. As permitted by SFAS 123, the Company has elected to account for the
Plan under APB 25. Accordingly, no compensation expense has been recognized for
the Plan. Had compensation cost for the Plan been determined based on the fair
value at the grant date consistent with SFAS 123, there would have been no
impact on the Company's net income and earnings per common share.
The fair value of each option grant was estimated on the date of grant using
the Black-Scholes option-pricing model with the following assumptions used:
dividend yield of 5.5%, risk-free interest rate of 6.8%, expected life of the
options of ten years and volatility of 15%.
NOTE 15
ACQUISITIONS AND DISPOSITIONS
On April 15, 1997, Holdings, through a subsidiary, acquired all of the
outstanding shares of common stock of TPC, a natural gas gathering,
processing, storage and marketing company based in Houston, Texas, for
approximately $265 million in cash and assumed debt of approximately $140
million. Following completion of a tender offer, TPC became a wholly owned
subsidiary of Holdings through a cash merger at the same price. During May
1997, TPC retired $131 million of its outstanding long-term debt. This
transaction was funded with capital contributions from PacifiCorp.
On December 1, 1997, TPC sold all of the capital stock of three subsidiaries
that hold its natural gas gathering and processing systems for $195 million
in cash, before tax payments of $23 million. No gain or loss was recognized
on the sale.
On November 5, 1997, Holdings completed the sale of PGC for approximately
$150 million in cash. An after-tax gain on the sale of $30 million, or $0.10
per share, was recognized in the fourth quarter of 1997.
In September 1996, a consortium, known as the Hazelwood Power Partnership,
purchased a 1,600 megawatt, coal-fired generating station and associated coal
mine in Victoria, Australia for approximately $1.9 billion. The consortium
financed the acquisition of the Hazelwood Plant and mine with approximately
$858 million in equity contributions from the partners and $1 billion of
nonrecourse borrowings at the partnership level. Holdings, which has a 19.9%
interest in the partnership, financed its $145 million portion of the equity
investment and the associated $12 million advance with long-term borrowings
in the United States.
On December 12, 1995, Holdings purchased Powercor, an electricity distributor
in Australia, for approximately $1.6 billion in cash. Powercor is the largest
electricity distribution company in the State of Victoria. The acquisition
was accounted for as a purchase and the results of operations of Powercor
have been included in the consolidated financial statements since December
12, 1995.
In February 1998, PFS agreed to sell its investments in affordable housing
for cash proceeds of approximately $81 million and assumption of debt of
approximately $161 million. This sale transaction will not have a material
impact on 1998 earnings.
- -------------------------------------------------------------------------------
PACIFICORP P. 59
NOTE 16
SELECTED FINANCIAL AND SEGMENT INFORMATION
MILLIONS OF DOLLARS, EXCEPT PER SHARE INFORMATION/FOR THE YEAR 1997 1996 1995 1994 1993
REVENUES
Domestic Electric Operations $3,706.9 $2,991.8 $2,646.1 $2,686.2 $2,560.8
Australian Electric Operations 716.2 658.8 25.9 -- --
Unregulated Energy Trading(a) 1,729.0 11.7 -- -- --
Other Operations(b) 125.9 141.4 134.8 153.7 196.4
----------------------------------------------------------
Total $6,278.0 $3,803.7 $2,806.8 $2,839.9 $2,757.2
- ----------------------------------------------------------------------------------------------------------------------------------
INCOME (LOSS) FROM OPERATIONS
Domestic Electric Operations $ 601.3 $ 869.8 $ 800.9 $ 819.3 $ 784.3
Australian Electric Operations 150.5 127.4 5.5 -- --
Unregulated Energy Trading(a) (8.2) 0.1 -- -- --
Other Operations(b) 58.9 89.1 84.2 38.3 44.1
----------------------------------------------------------
Total $ 802.5 $1,086.4 $ 890.6 $ 857.6 $ 828.4
- ----------------------------------------------------------------------------------------------------------------------------------
NET INCOME $ 663.7 $ 504.9 $ 505.0 $ 468.0 $ 479.1
- ----------------------------------------------------------------------------------------------------------------------------------
EARNINGS CONTRIBUTION (LOSS) ON COMMON STOCK
Continuing operations
Domestic Electric Operations $ 165.5 $ 341.5 $ 276.4 $ 339.8 $ 322.3
Australian Electric Operations 54.2 31.9 0.7 -- --
Unregulated Energy Trading(a) (7.5) (0.1) -- -- --
Other Operations(b) (9.6) 27.1 86.2 18.0 10.2
----------------------------------------------------------
Total 202.6 400.4 363.3 357.8 332.5
Discontinued operations(c) 454.3 74.7 103.0 70.5 103.3
Extraordinary item(d) (16.0) -- -- -- --
Cumulative effect of change in
accounting for income taxes -- -- -- -- 4.0
----------------------------------------------------------
Total $ 640.9 $ 475.1 $ 466.3 $ 428.3 $ 439.8
- ----------------------------------------------------------------------------------------------------------------------------------
EARNINGS (LOSS) PER SHARE -- BASIC AND DILUTIVE
Continuing operations
Domestic Electric Operations $ 0.56 $ 1.17 $ 0.97 $ 1.20 $ 1.17
Australian Electric Operations 0.18 0.11 -- -- --
Unregulated Energy Trading(a) (0.03) -- -- -- --
Other Operations(b) (0.03) 0.09 0.31 0.06 0.04
----------------------------------------------------------
Total 0.68 1.37 1.28 1.26 1.21
Discontinued operations(c) 1.53 0.25 0.36 0.25 0.38
Extraordinary item(d) (0.05) -- -- -- --
Cumulative effect of change in
accounting for income taxes -- -- -- -- 0.01
----------------------------------------------------------
Total $ 2.16 $ 1.62 $ 1.64 $ 1.51 $ 1.60
- ----------------------------------------------------------------------------------------------------------------------------------
CASH DIVIDENDS DECLARED PER COMMON SHARE $ 1.08 $ 1.08 $ 1.08 $ 1.08 $ 1.08
- ----------------------------------------------------------------------------------------------------------------------------------
MARKET PRICE PER COMMON SHARE(e) $27 5/16 $20 1/2 $21 1/8 $18 1/8 $19 1/4
- ----------------------------------------------------------------------------------------------------------------------------------
CAPITALIZATION
Short-term debt $ 555 $ 903 $ 1,132 $ 513 $ 668
Long-term debt 4,415 4,829 4,509 3,391 3,497
Preferred securities of Trust 340 210 -- -- --
Redeemable preferred stock 175 178 219 219 219
Preferred stock 66 136 312 367 367
Common equity 4,321 4,032 3,633 3,460 3,263
----------------------------------------------------------
Total $ 9,872 $10,288 $ 9,805 $ 7,950 $ 8,014
- ----------------------------------------------------------------------------------------------------------------------------------
TOTAL ASSETS $ 13,880 $13,812 $ 13,167 $ 11,000 $11,053
- ----------------------------------------------------------------------------------------------------------------------------------
TOTAL EMPLOYEES(e) 10,087 10,118 10,418 10,083 10,630
- ----------------------------------------------------------------------------------------------------------------------------------
(a) Unregulated Energy Trading includes the natural gas and wholesale
electricity trading activities of TPC and PPM, respectively.
(b) Other Operations includes the operations of PFS and PGC, as well as the
activities of Holdings, including financing costs. (c) Discontinued
operations includes the Company's interest in PTI for all periods presented
and TRT Communications, Inc. for 1993. (d) Extraordinary item includes a
regulatory asset impairment pertaining to generation resources that are
allocable to operations in California and Montana. (e) Unaudited.
- -------------------------------------------------------------------------------
P. 60 PACIFICORP
DOMESTIC ELECTRIC OPERATIONS
5-YEAR
1997 TO 1996 COMPOUND
MILLIONS OF DOLLARS, EXCEPT PERCENTAGE ANNUAL
AS NOTED/FOR THE YEAR 1997 1996 1995 1994 1993 COMPARISON GROWTH
REVENUES
Residential $ 814.0 $ 801.4 $ 739.7 $ 746.0 $ 738.8 2% 3%
Commercial 640.9 623.3 576.9 571.7 546.1 3 4
Industrial 709.9 719.3 708.8 742.3 708.0 (1) --
Other 31.7 32.5 29.7 30.7 29.8 (2) 1
----------------------------------------------------------------------------------
Retail sales 2,196.5 2,176.5 2,055.1 2,090.7 2,022.7 1 2
----------------------------------------------------------------------------------
Wholesale -- firm 1,289.3 635.4 487.7 456.2 422.5 103 29
Wholesale -- nonfirm 138.7 103.4 32.3 76.5 77.3 34 14
----------------------------------------------------------------------------------
Wholesale trading sales 1,428.0 738.8 520.0 532.7 499.8 93 27
----------------------------------------------------------------------------------
Other 82.4 76.5 71.0 62.8 38.3 8 21
----------------------------------------------------------------------------------
Total 3,706.9 2,991.8 2,646.1 2,686.2 2,560.8 24 9
----------------------------------------------------------------------------------
EXPENSES
Fuel 454.2 443.0 431.6 483.0 447.4 3 --
Purchased power 1,296.5 618.7 386.7 394.5 369.0 110 33
Other operations 292.0 276.9 273.7 263.8 265.0 5 2
Maintenance 178.0 167.3 168.4 174.5 172.2 6 1
Administrative and
general 227.8 176.3 160.5 142.7 138.2 29 10
Depreciation and
amortization 389.1 343.4 320.4 301.6 280.5 13 6
Taxes, other than
income taxes 97.6 96.4 103.9 106.8 104.2 1 (2)
Special charges 170.4 -- -- -- -- * *
----------------------------------------------------------------------------------
Total 3,105.6 2,122.0 1,845.2 1,866.9 1,776.5 46 12
----------------------------------------------------------------------------------
INCOME FROM OPERATIONS 601.3 869.8 800.9 819.3 784.3 (31) (2)
Interest expense 319.0 291.8 311.9 264.3 270.4 9 3
Interest capitalized (12.2) (11.4) (14.9) (14.5) (13.9) 7 (6)
Other (income) expense -- net (5.8) 1.2 (25.3) (30.2) (13.1) * *
Income tax expense 112.0 216.9 214.1 220.2 179.3 (48) (7)
----------------------------------------------------------------------------------
NET INCOME 188.3 371.3 315.1 379.5 361.6 (49) (5)
PREFERRED DIVIDEND
REQUIREMENT 22.8 29.8 38.7 39.7 39.3 (23) (9)
----------------------------------------------------------------------------------
EARNINGS CONTRIBUTION(a) $ 165.5 $ 341.5 $ 276.4 $ 339.8 $ 322.3 (52) (4)
----------------------------------------------------------------------------------
IDENTIFIABLE ASSETS $ 9,863 $ 9,864 $ 9,599 $ 9,372 $ 9,055 -- 4
CAPITAL SPENDING $ 490 $ 596 $ 455 $ 638 $ 637 (18) (11)
* Not a meaningful number.
(a) Does not reflect elimination of interest on intercompany borrowing
arrangements and includes income taxes on a separate-company basis.
- -------------------------------------------------------------------------------
PACIFICORP P. 61
DOMESTIC ELECTRIC OPERATIONS STATISTICS
5-YEAR
1997 TO 1996 COMPOUND
MILLIONS OF DOLLARS, EXCEPT PERCENTAGE ANNUAL
AS NOTED/FOR THE YEAR 1997 1996 1995 1994 1993 COMPARISON GROWTH
ENERGY SALES
(Millions of kWh)
Residential 12,902 12,819 12,030 12,127 12,055 1% 3%
Commercial 11,868 11,497 10,797 10,645 10,085 3 4
Industrial 20,674 20,332 19,748 20,306 19,671 2 1
Other 705 640 592 623 602 10 3
-----------------------------------------------------------------------------------
Retail sales 46,149 45,288 43,167 43,701 42,413 2 2
-----------------------------------------------------------------------------------
Wholesale -- firm 51,857 23,189 13,946 12,418 11,919 124 38
Wholesale -- nonfirm 7,286 6,476 2,430 3,207 3,030 13 20
-----------------------------------------------------------------------------------
Wholesale sales 59,143 29,665 16,376 15,625 14,949 99 35
-----------------------------------------------------------------------------------
Total 105,292 74,953 59,543 59,326 57,362 40 14
-----------------------------------------------------------------------------------
ENERGY SOURCE (%)
Coal 43 60 74 79 77 (28) (12)
Hydroelectric 5 7 7 5 6 (29) 5
Other 2 1 2 2 1 100 --
Purchase and
exchange contracts 50 32 17 14 16 56 31
-----------------------------------------------------------------------------------
NUMBER OF RETAIL CUSTOMERS
(Thousands)
Residential 1,228 1,194 1,167 1,147 1,126 3 2
Commercial 170 167 160 158 154 2 2
Industrial 36 37 35 34 33 (3) 3
Other 4 4 4 3 4 -- 6
-----------------------------------------------------------------------------------
Total 1,438 1,402 1,366 1,342 1,317 3 2
-----------------------------------------------------------------------------------
RESIDENTIAL CUSTOMERS
Average annual usage (kWh) 10,644 10,866 10,395 10,646 10,811 (2) 1
Average annual revenue
per customer (Dollars) 672 679 639 655 663 (1) 1
Revenue per kWh (Cents) 6.3 6.3 6.1 6.1 6.1 -- --
MILES OF LINE
Transmission 15,000 14,900 14,900 14,900 14,900 1 --
Distribution
-- overhead 45,000 45,000 44,900 44,800 44,700 -- --
-- underground 10,000 9,600 9,100 8,800 8,200 4 5
SYSTEM PEAK DEMAND
(Megawatts)
Net system load(b)
-- summer 7,110 7,257 6,855 7,151 6,554 (2) 1
-- winter 7,403 7,615 7,030 7,174 7,268 (3) 1
Total firm load
-- summer(c) 10,871 10,572 8,899 8,830 8,390 3 5
-- winter 10,830 10,775 8,904 8,903 8,838 1 5
SYSTEM CAPABILITY
(Megawatts)(d)
-- summer 12,343 12,115 10,224 10,020 9,757 2 5
-- winter 12,618 12,160 10,994 10,391 9,916 4 5
(a) Unaudited.
(b) Excludes off-system sales.
(c) Includes firm off-system sales.
(d) Generating capability and firm purchases at time of firm peak.
- -------------------------------------------------------------------------------
P. 62 PACIFICORP
1997 TO 1996
MILLIONS OF DOLLARS, EXCEPT AS NOTED/ PERCENTAGE
FOR THE YEAR 1997 1996 1995 COMPARISON
POWERCOR EARNINGS CONTRIBUTION(a)
REVENUES
Residential $239.2 $239.4 $ 10.5 --%
Commercial 207.9 165.5 5.9 26
Industrial 191.8 179.3 6.4 7
Other 44.4 44.4 2.6 --
-------------------------------------------
Energy sales 683.3 628.6 25.4 9
Other 32.9 30.2 0.5 9
-------------------------------------------
Total 716.2 658.8 25.9 9
-------------------------------------------
EXPENSES
Purchased power 308.5 305.1 11.0 1
Other operations 100.7 62.3 2.5 62
Maintenance 33.3 50.0 0.3 (33)
Administrative and general 54.9 40.7 3.4 35
Depreciation and amortization 67.1 71.6 3.1 (6)
Taxes, other than income taxes 1.2 1.7 0.1 (29)
-------------------------------------------
Total 565.7 531.4 20.4 6
-------------------------------------------
INCOME FROM OPERATIONS 150.5 127.4 5.5 18
Interest expense 63.5 75.2 3.8 (16)
Other (income) expense -- net (1.8) 0.4 0.5 *
Income tax expense 32.9 19.1 0.5 72
-------------------------------------------
POWERCOR EARNINGS CONTRIBUTION $ 55.9 $ 32.7 $ 0.7 71
-------------------------------------------
HAZELWOOD EARNINGS CONTRIBUTION(a) $ (1.7) $ (0.8) $ -- (113)
-------------------------------------------
IDENTIFIABLE ASSETS $1,786 $2,065 $1,751 (14)
CAPITAL SPENDING $84 $ 225 $1,591 (63)
ENERGY SALES (Millions of kWh)(b)
Residential 2,683 2,608 112 3
Commercial 3,082 1,926 66 60
Industrial 4,755 3,282 152 45
Other 524 494 32 6
-------------------------------------------
Total 11,044 8,310 362 33
-------------------------------------------
NUMBER OF CUSTOMERS(b)(c)
Residential 459,780 453,978 448,623 1
Commercial
Franchise 48,438 47,918 47,358 1
Contestable 1,383 680 17 103
Industrial
Franchise 8,899 8,005 8,422 11
Contestable 541 417 5 30
Other
Franchise 35,842 35,808 35,700 --
Contestable 7 8 -- (13)
-------------------------------------------
Total 554,890 546,814 540,125 1
-------------------------------------------
* Not a meaningful number.
(a) Results of operations are included since dates of acquisition, December
12, 1995 for Powercor and September 13, 1996 for Hazelwood.
(b) Unaudited.
(c) Aggregate number of customers in Powercor's distribution service area,
together with contestable customers located outside of Powercor's
distribution service area.
- -------------------------------------------------------------------------------
PACIFICORP P. 63
UNREGULATED ENERGY TRADING
Unregulated Energy Trading includes the natural gas and wholesale electricity
trading activities of TPC and PPM, respectively. TPC was purchased on April
15, 1997. Natural gas revenues, gross margin and net income for 1997 include
$19 million, $14 million, and $3 million, respectively, relating to the
natural gas gathering and processing operations of TPC that were sold in
December 1997.
MILLIONS OF DOLLARS/FOR THE YEAR 1997 1996
- -------------------------------------------------------------------
REVENUES
Natural gas $815.8 $--
Electricity 913.2 11.7
-------------------
Total 1,729.0 11.7
-------------------
COST OF SALES
Natural gas 801.0 --
Purchased electric power 909.3 8.0
-------------------
GROSS MARGIN 18.7 3.7
Depreciation and amortization 10.7 --
Administrative and other 16.2 3.6
-------------------
INCOME (LOSS) FROM OPERATIONS
Natural gas (5.8) --
Electricity (2.4) 0.1
-------------------
Total (8.2) 0.1
-------------------
INTEREST EXPENSE 2.8 0.2
-------------------
NET LOSS
Natural gas (5.9) --
Electricity (1.6) (0.1)
-------------------
Total $ (7.5) $ (0.1)
-------------------
ENERGY SALES(a)
Natural gas (MMcf)(b) 283,000 --
Electricity (millions of kWh) 35,800 497
IDENTIFIABLE ASSETS $ 478 $7
CAPITAL SPENDING $75 $--
(a) Unaudited. (b) Excludes volumes relating to natural gas gathering and
processing activities.
OTHER OPERATIONS
Other Operations include the operations of PFS, PGC and several
start-up-phase ventures, as well as the activities of Holdings, including
financing costs. PGC assets were sold on November 5, 1997 and in February
1998 a definitive agreement was reached to sell the real estate assets of PFS.
MILLIONS OF DOLLARS/FOR THE YEAR 1997 1996 1995 1994 1993
- ---------------------------------------------------------------------------------------------------------
EARNINGS CONTRIBUTION
PFS $30.2 $34.1 $30.4 $3.0 $(3.1)
PGC 10.4 7.8 5.6 8.5 6.5
Tax settlement -- -- 32.2 -- --
Holdings and other (50.2) (14.8) 18.0 6.5 6.8
---------------------------------------------------------
Total $(9.6) $27.1 $86.2 $18.0 $10.2
---------------------------------------------------------
IDENTIFIABLE ASSETS
PFS 692 708 697 731 1,116
PGC -- 123 116 113 122
Holdings and other(a) 1,061 276 253 252 251
---------------------------------------------------------
Total $1,753 $1,107 $1,066 $1,096 $1,489
---------------------------------------------------------
CAPITAL SPENDING $140 $ 56 $ 44 $ 13 $ 44
(a) During 1997, the Company generated $1.8 billion of cash, excluding $370
million of current income tax liabilities, from sales of assets with carrying
values of $822 million. See Notes 3 and 15.
- -------------------------------------------------------------------------------
P. 64 PACIFICORP
SUPPLEMENTAL INFORMATION
QUARTERLY FINANCIAL DATA (UNAUDITED)
MILLIONS OF DOLLARS/EXCEPT PER SHARE MARCH JUNE SEPTEMBER DECEMBER
AMOUNTS/QUARTER ENDED 31 30 30 31
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1997
Revenues $1,041.8 $1,220.1 $2,010.6 $2,005.5
Income from operations 261.4 221.9 281.1 38.1
Income from continuing operations 102.7 75.7 46.9 0.1
Discontinued operations 18.3 19.1 27.1 389.8
Extraordinary item -- -- -- (16.0)
Net income 121.0 94.8 74.0 373.9
Earnings on common stock 114.9 88.7 68.2 369.1
Earnings per common share:
Continuing operations 0.32 0.24 0.14 (0.02)
Discontinued operations 0.07 0.06 0.09 1.31
Extraordinary item -- -- -- (0.05)
Common dividends paid and
declared per share 0.27 0.27 0.27 0.27
Common stock price
per share (NYSE)
High 21 3/4 22 3/8 23 3/8 27 5/16
Low 20 1/8 19 1/4 20 9/16 21 7/16
1996
Revenues $883.4 $856.6 $1,011.9 $1,051.8
Income from operations 276.9 218.5 297.3 293.7
Income from continuing operations 114.0 81.3 122.6 112.3
Discontinued operations 15.9 17.9 20.3 20.6
Net income 129.9 99.2 142.9 132.9
Earnings on common stock 120.9 90.2 136.6 127.4
Earnings per common share:
Continuing operations 0.36 0.25 0.39 0.37
Discontinued operations 0.06 0.06 0.07 0.06
Common dividends paid and
declared per share 0.27 0.27 0.27 0.27
Common stock price
per share (NYSE)
High 22 22 1/2 22 3/8 22
Low 20 1/8 19 1/2 19 1/8 19 7/8
A significant portion of the operations are of a seasonal nature. Previously
reported quarterly information has been revised to reflect certain
reclassifications. These reclassifications had no effect on previously
reported consolidated net income.
In the fourth quarter of 1997, the Company recorded after-tax amounts as
follows: asset sales gains of $395 million or $1.33 per share, special
charges of $106 million, or $0.36 per share, and an extraordinary charge of
$16 million, or $0.05 per share. See Notes 4, 5, and 15. Additionally, in the
fourth quarter of 1997, the Company recorded after-tax depreciation
adjustments of $10 million, or $0.03 per share, and an SAP process
reengineering charge of $9 million, or $0.03 per share. See Management's
Discussion and Analysis, pages 29 and 33.
See Note 3 for information regarding discontinued operations.
On March 1, 1998, there were 115,693 common share-holders of record.
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