MANAGEMENT'S DISCUSSION AND ANALYSIS
EARNINGS OVERVIEW
Millions of dollars, except per share information 1996 1995 1994
- --------------------------------------------------------------------------------
Earnings contribution on common stock
Domestic Electric Operations $ 341.5 $ 276.4 $ 339.8
Australian Electric Operations 30.1 .7 --
Telecommunications 74.7 103.0 70.5
Other Operations 28.8 86.2 18.0
----------------------------
$ 475.1 $ 466.3 $ 428.3
----------------------------
Earnings per common share $ 1.62 $ 1.64 $ 1.51
----------------------------
PacifiCorp and its subsidiaries (the "Company") increased earnings on common
stock 11%, or $.11 per share, compared to 1995, after deducting from 1995
results a gain of $37 million ($.13 per share) relating to the sale of the
Company's Alaskan long-distance operations. Each of the Company's major
businesses contributed to the earnings increase: Domestic Electric Operations,
Australian Electric Operations and Telecommunications. The Company achieved
these positive results while continuing to prepare itself to become a dominant
player in an increasingly global energy marketplace. Domestically, this
preparation included finding new ways to manage costs, improve customer service
and expand the Company's presence in eastern U.S. markets. Powercor Australia
Ltd. ("Powercor"), the Company's first major international endeavor, exceeded
expectations during its first full year of operations as a PacifiCorp company.
The Company's telecommunications business continues to focus on its successful
strategy of growth through acquisitions of rural telephone exchange operations.
Domestic Electric Operations' contribution to earnings on common stock
increased $33 million, or 11%, after adding back to 1995 earnings $32 million
resulting from a tax settlement with the Internal Revenue Service (the "tax
settlement") for the years 1983-1988. This tax settlement was offset in Other
Operations discussed below. The higher earnings were a result of several
factors: an increased focus on the wholesale power marketplace, where the
Company established itself as a leading bulk power trader in the West; price
increases in Oregon and Wyoming; and increased demand for electricity from all
customer segments. Purchased power played a more prominent role as increased
demand in the wholesale and retail markets drove the need to acquire power from
external sources.
Australian Electric Operations contributed earnings of $30 million, before
allocation of corporate interest costs. In July 1996, customers in the State of
Victoria who use 750 or more megawatt hours per year became "contestable,"
meaning they could choose their supplier. Powercor, the Company's marketing and
distributing entity in Australia, has established itself as a leader in the
contestable market, and currently serves 46% of Victoria's contestable
customers. New South Wales' contestable market opened in October 1996. Powercor
was the first company outside the state to receive a retail license to sell
power in that market, and currently serves 5% of New South Wales' contestable
customers. The Company expanded its Australian business in 1996 with the
acquisition of a 19.9% interest in the Hazelwood Power Partnership
("Hazelwood"). Hazelwood's 1,600 megawatt ("MW") coal-fired generating station
and coal mine provides the Company with an opportunity to employ its mining
skills in a new, deregulated marketplace.
Telecommunications continued its steady growth in the rural and suburban
telecommunications market, increasing its contribution to earnings by $2
million, after deducting from 1995 results a gain of $37 million relating to the
sale of Alascom, Inc. ("Alascom") and adjusting for minority interest. This
improvement was the direct result of local exchange operations acquired in 1995,
taken together with growth in existing operations. Telecommunications expects
this growth to continue due to customer access line growth within existing
service areas and acquisitions outside of those areas.
Other Operations' earnings contributions totaled $29 million in 1996 compared
to $54 million in 1995, after deducting from 1995 results the $32 million tax
settlement referred to above. The 1996 results were impacted by interest expense
associated with the investment in Powercor and costs associated with new,
unregulated energy businesses.
24
DOMESTIC ELECTRIC OPERATIONS
REVENUES
Millions of dollars 1996 1995 1994
- ---------------------------------------------------------
Residential $ 785.6 $ 721.9 $ 724.9
Wholesale 738.8 520.0 532.7
Industrial 705.0 697.6 726.3
Commercial 622.4 575.9 570.4
Other 109.0 100.7 93.5
---------------------------------
$ 2,960.8 $ 2,616.1 $ 2,647.8
---------------------------------
ENERGY SALES
Millions of kWh 1996 1995 1994
- ---------------------------------------------------------
Residential 12,819 12,030 12,127
Wholesale 29,665 16,376 15,625
Industrial 20,332 19,748 20,306
Commercial 11,497 10,797 10,645
Other 640 592 623
---------------------------------
74,953 59,543 59,326
---------------------------------
REVENUES
Domestic Electric Operations' revenues rose 13% during 1996, driven primarily by
an 81% increase in kilowatt hours ("kWh") sold in the wholesale market.
Wholesale revenues increased to a record $739 million in 1996 primarily due
to an increased focus in this very competitive market. Despite the 81% increase
in wholesale kWh sold, the Company saw only a 42% increase in revenues due to
the impact of competition on market prices. Average revenue per kWh declined
from $.0318 to $.0249 as a result.
Residential and commercial revenues grew a combined 8% in 1996 as a result of
both increased prices and volumes. Price increases of approximately 4% were
approved in both the Oregon and Wyoming customer jurisdictions in July 1996.
These price increases should contribute approximately $37 million of additional
revenue annually. In the last half of 1996, these increases contributed an
additional $16 million of revenue. Weather conditions that increased energy
requirements, 2% residential and 3% commercial customer growth and increased
customer usage led to an additional 1.5 billion kWh of residential and
commercial energy sales and contributed $36 million, $29 million and $21 million
of revenue, respectively.
On February 12, 1997, the Division of Public Utilities and Committee of
Consumer Service in Utah filed a joint petition with the Utah Public Service
Commission (the "PSC") requesting the Commission to commence proceedings to
establish new rates for Utah customers. The petitioners requested an immediate
hearing on a $12 million interim rate reduction and a subsequent general rate
case, which the petitioners allege could result in rates being reduced as much
as $54 million. On March 4, 1997 the Utah Legislature passed
a bill which creates a legislative task force to study stranded cost issues and
the timing of customer choice. The bill freezes rates at January 31, 1997 levels
until 60 days following the conclusion of the 1998 legislative general session.
The PSC is precluded from holding any hearings on rate changes during the freeze
period. The Company has committed to reduce prices to Utah customers by $12
million annually on approximately May 1, 1997.
Industrial revenues grew at a slower pace than residential and commercial
revenues during 1996, increasing 1%. Revenues from irrigation customers
increased $7 million due to drier weather compared to 1995. While sales to oil
and gas customers declined $10 million due to permanent well closures, volumes
increased overall as a result of higher volumes sold to new nonagricultural
customers at competitive prices.
In 1995, revenues declined in all areas except commercial and other sales
when compared to 1994. In general, retail revenues decreased due to the $15
million effect of the December 1994 sale of the Sandpoint, Idaho distribution
facilities and warmer winter weather. However, both residential and commercial
revenues increased due to a 2% increase in the number of customers. Industrial
usage declined $29 million primarily due to a $21 million decrease in sales to
oil and gas customers in Wyoming as a result of permanent well closures and a
$15 million decrease in sales to irrigation customers due to increased rainfall
and mild temperatures in 1995.
Wholesale revenues declined $13 million while kWh volume increased 5%. A $22
million increase in revenue from new long-term contracts partially offset
decreases in spot market and short-term contract prices totaling $34 million.
NUMBER OF RETAIL CUSTOMERS
Thousands, at year-end 1996 1995 1994
- -----------------------------------------------------
Residential 1,194 1,176 1,155
Commercial 167 162 159
Industrial 20 20 19
Other 4 3 4
--------------------------
1,385 1,361 1,337
--------------------------
OPERATING EXPENSES
Many of the Company's efforts to control operating costs proved
effective in 1996, keeping the growth in fuel, operations and maintenance and
other costs well below the growth in revenues. However, purchased power costs
increased $231 million since the Company met the higher demand for electricity
in 1996 largely by purchasing additional power in the market. Additional power
was also purchased from the Hermiston Plant which began operation in July 1996
(see Investing Activities).
25
OPERATING EXPENSES
Millions of dollars 1996 1995 1994
- --------------------------------------------------------------------------------
Fuel $ 443.0 $ 431.6 $ 483.0
Purchased power 586.9 356.4 356.7
Other operations and maintenance 445.0 442.4 437.7
Depreciation and amortization 343.4 320.4 301.6
Other 272.7 264.4 249.5
-------------------------------
$ 2,091.0 $ 1,815.2 $ 1,828.5
-------------------------------
Operating Expenses as a Percent of Revenue 71% 69% 69%
PURCHASED POWER
Millions of MWh 1996 1995 1994
- --------------------------------------------------
Short-term or spot market 16.9 5.0 3.3
Long-term contracts 8.5 6.0 5.9
Short-term firm and spot market purchases in 1996 were more than three times
the 1995 level. These purchases averaged $13 per megawatt hour ("MWh") in 1996
compared to $10 per MWh in 1995. Increased volumes purchased under new long-term
firm power contracts, net of expiring contracts, added $29 million to purchased
power costs in 1996.
As a result of these additional costs and other factors, net power costs (the
net cost to serve the Company's retail customers on a MWh basis, measured as the
sum of fuel, purchased power and wheeling expense, less wholesale power and
wheeling revenues) were $7.20 per MWh in 1996 compared to $6.83 per MWh in 1995,
a 5% increase. Given the Company's commitment to take all of the output of the
Hermiston Plant, net power cost is expected to increase in 1997. The Company
continually evaluates the cost of alternative sources of power and attempts to
minimize its cost to meet the demands of consumers by balancing its utilization
of hydro and thermal generation with purchased power.
Depreciation and amortization expense increased 7% in 1996 primarily due to a
$410 million increase in average depreciable plant. This included the Hermiston
Plant and a new customer service system which were placed in service in 1996 and
added $6 million of depreciation during the year.
In 1995, the Company's fuel cost decreased 11% compared to 1994 primarily due
to the use of lower cost hydroelectric power generation and lower cost purchased
power. Total purchased power costs remained flat, as higher firm contract
volumes were offset by a $27 million decrease resulting from lower spot market
prices.
OTHER INCOME AND EXPENSE
Interest expense declined $8 million, or 2%, to $304 million in 1996. Excluding
$28 million of interest cost associated with the tax settlement in 1995,
interest expense increased $20 million, or 7%, 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 $18 million in 1996 as a result of lower levels of capitalized
interest, reduced asset sale gains and increased product and business
development expense.
COMPETITION AND REGULATION
Domestic Electric Operations continues to operate as a regulated monopoly
within its seven-state franchise service territories, with relatively low cost
and efficient power sources. Competition in these areas varies in form and
intensity, but is expected to increase over time, principally as a result of
industry deregulation and consequent increases in advertising and marketing by
alternative energy suppliers. Large industrial customers are actively seeking
choice of suppliers, and have options to build their own generation or
cogeneration, or to use alternative energy sources, such as natural gas. Other
consumers also, in many cases, have the option to switch energy sources for
heating and air conditioning, and to consider alternatives such as
municipalization.
The U.S. power industry is undergoing a dramatic transformation, via
deregulation and restructuring, that will substantially increase
competition. Developments in this transformation have been largely dependent on
state legislative and regulatory initiatives and vary considerably from state to
state. Industry restructuring bills range from those which require study of
direct retail access to those which would result in implementation of direct
access for retail customers. The Company expects any legislation passed to
specifically provide a reasonable opportunity to recover costs which have been
placed at risk due to the introduction of competition. Legislation has been
enacted in California, AB1890, which requires direct access for a portion of
the state's retail customers by January 1, 1998. California provides
approximately 3% of the Company's retail revenues.
26
Competition has already transformed the electric utility industry
at the wholesale level. In 1996, the Federal Energy Regulatory Commission
("FERC") ordered all investor-owned utilities to allow others access to their
transmission systems for wholesale power sales. As a result of increased
competition and excess capacity, wholesale prices have dropped significantly
over the past two years.
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.
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.
ENVIRONMENTAL ISSUES
The Company's generating plants burn low-sulfur coal. Major construction
expenditures have already been made at many 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. Studies are underway to evaluate the Centralia Plant and determine a
cost-effective manner of bringing emissions into compliance with limitations
ordered by the environmental authorities in the state of Washington. It may not
be possible to reach an economically viable solution. The Company has also been
engaged in discussions with the environmental authorities in Wyoming with
respect to alleged violations of the opacity and SO(2) standards applicable to
the Jim Bridger Plant. Resolution of these alleged violations is not expected to
require significant additional capital expenditures.
In addition, the Company and the other joint owners of the Craig Generating
Station ("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 an interest of approximately 20% in the Station. A settlement conference has
been scheduled for March 1997.
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
certain of its hydroelectric projects under the Federal Power Act and will be
seeking licenses for other projects in the future. The licenses of 12 of
Domestic Electric Operations' hydroelectric projects expire within the next 10
years. These projects represent 664 MW, or 62%, of Domestic Electric Operations'
hydroelectric generating capacity, or 8% of total generating capacity. In the
new licenses, the FERC is expected to impose conditions designed to address the
impact of the projects on fish and other environmental concerns. 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 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. In addition, insurance
resources are reviewed and investigated.
All of 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. 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.
27
AUSTRALIAN ELECTRIC OPERATIONS
For the year 1996, expressed in millions, except per kWh Revenues Energy Sales Cents per kWh
- ----------------------------------------------------------------------------------------------------------
Residential $ 239.4 $ 2,608 $ 9.2
Industrial 179.3 3,282 5.5
Commercial 165.5 1,926 8.6
Other 74.6 494 --
-------------------------------
$ 658.8 $ 8,310 $ --
-------------------------------
POWERCOR
The operations of the Company's first significant international venture,
Powercor, exceeded management's expectations for 1996, its first full year of
operations as a PacifiCorp company. Powercor contributed earnings of $33
million, before allocation of corporate interest costs. Allocation of interest
expense on U.S. borrowings associated with the December 1995 acquisition of
Powercor would have reduced Powercor's earnings contribution by approximately
$28 million in 1996.
Powercor, based in Melbourne, Australia, was acquired in December 1995 after
the Victorian state government decided to disaggregate and sell parts of the
state-owned electricity industry. Accordingly, the State Electricity Commission
separated the electricity industry into three components--generation,
transmission and distribution. Five companies were formed to manage the network
of poles and wires that deliver power to customers. Powercor is one of those
companies, responsible for the largest network system and geo-graphical area in
the state.
In addition to being a distributor, Powercor is also a retailer of
electricity with about 547,000 customers--the majority of which are located in
its network area. Under Victorian state government reforms, Powercor is able to
sell electricity to large customers outside its network area. On July 1, 1996,
approximately 2,000 customers using 750 or more MWh per year of power became
"contestable," meaning they could choose their electricity provider. Powercor
has emerged as the leader in the new market, not only obtaining new customers
but also retaining most of its existing customer base. Powercor now holds the
largest share of customers in this market. New customers include two of
Australia's largest banks, Australia's second-largest retailer and several large
industrials.
POWERCOR OPERATING RESULTS
Powercor achieved total revenues of $659 million in 1996. Higher than expected
revenues were achieved primarily through retaining customers in its network area
and through obtaining additional contestable customers. These additional
customers provided $40 million of revenue in 1996 and are expected to add
approximately $130 million to revenues in 1997, albeit at lower margins than the
noncontestable market. As of December 31, 1996, Powercor held about 46% of the
State of Victoria's contestable market and 5% of the market in neighboring New
South Wales.
Powercor's operating expenses aggregated $531 million in 1996, with purchased
power costs of $305 million representing 57% of operating expenses. See Note 16
to the Consolidated Financial Statements. Powercor's operating expenses totaled
81% of its revenue compared to Domestic Electric Operations where operating
expenses totaled 71% of its revenue in 1996. As Powercor's operations do not
include power generation, this relationship is consistent with management's
expectations and is expected to continue into the near future.
Although Powercor was successful in 1996, its ability to continue to meet or
exceed the Company's expectations is not without risks. Powercor buys all of the
electricity it sells and can, therefore, be impacted by fluctuating energy
prices. To minimize this risk, Powercor has established a risk management system
to manage its pool price expense. See Notes 1, 7 and 8 to the Consolidated
Financial Statements. The Company's investment in Hazelwood is strategically
important because, among other things, it provides a natural hedge to a portion
of Powercor's exposure to fluctuating energy prices.
HAZELWOOD
As discussed under Investing Activities, the Company acquired a 19.9% interest
(the maximum allowable under current law) in Hazelwood in September 1996 with a
consortium including subsidiaries of National Power Corporation PLC, Destec
Energy and Commonwealth Bank Group of Australia. The coal-fired generating
station and the associ-ated coal mine are located in the coal-rich Latrobe
Valley, about 90 miles east of Melbourne, Australia, where several other large,
coal-fired power stations are located. The plant is fueled by brown coal from
the mine that contains approximately 450 million tons of reserves, enough fuel
to operate the station for at least 40 years.
Among the partners in Hazelwood there are considerable skills in managing and
operating coal-fired plants. National Power, which owns 51.9% of Hazelwood,
oversees plant operations and the Company oversees the operation of the adjacent
coal mine. Since the Company is one of the largest coal producers in the U.S.,
management believes there will be significant opportunities to share best
practices between its mining operations.
28
HAZELWOOD OPERATING RESULTS
Hazelwood sells its power through a statewide generation pool and enters into
hedging arrangements with Australian distribution companies, such as Powercor.
Energy prices vary with weather, economic growth and other factors affecting the
supply of and demand for power. Power prices are lowest during Australia's
summer months (the fourth and first calendar quarters).
Since its acquisition in September 1996, the Company's share of Hazelwood's
net loss totaled $3 million, including approximately $2 million of interest
associated with the transaction. As demand is lowest during Australia's summer
months (the winter months in the U.S.), the Company does not expect to see its
share of losses accumulate at the rate they did since its acquisition in
September 1996. Moreover, the Company expects to see Hazelwood's operating
results improve as the Company's expertise leads to more efficient mining
operations and as the power plant becomes a more efficient generator.
Nonetheless, as these changes will take time, the Company expects Hazelwood to
be slightly dilutive to 1997 earnings.
COMPETITION
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 customers can increasingly 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.
As mentioned above, Hazelwood operates in an area where several large,
coal-fired generating facilities are located. It will continue to compete
against these plants, as well as others outside the geographic area.
REGULATION
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.
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 non-exclusive state-wide license
to sell to contestable customers. All customers with loads in excess of 750 MWh
per year are now contestable and other customers will become contestable over
the next four years depending on their energy demand level, with substantially
all residential customers remaining franchise customers until 2001. If a
Powercor customer chooses a different retailer, Powercor will continue to
receive network revenue associated with the customer.
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 with 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 prices, 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 or 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 apply for not less than five years.
The Company does not expect regulation to adversely impact its existing
operations in Australia.
29
TELECOMMUNICATIONS
REVENUES
Millions of dollars 1996 1995 1994
- --------------------------------------------------------------
Network access service $ 259.1 $ 223.7 $ 168.5
Local network service 140.9 120.5 96.9
Cellular 44.0 33.9 23.6
Other 77.1 68.9 64.0
Alascom -- 193.1 343.5
------------------------------
$ 521.1 $ 640.1 $ 696.5
------------------------------
EXPENSES
Millions of dollars 1996 1995 1994
- --------------------------------------------------------------
Operations $ 81.5 $ 78.2 $ 66.7
Maintenance 91.2 86.0 74.4
Other operations expense 83.2 68.2 61.7
Depreciation and amortization 106.5 86.2 66.2
Alascom -- 156.2 262.8
------------------------------
$ 362.4 $ 474.8 $ 531.8
------------------------------
OVERVIEW
Pacific Telecom, Inc. ("PTI") contributed earnings of $75 million in 1996
compared to earnings of $103 million in 1995. The results for 1995 included a
gain of $37 million relating to the sale of Alascom. In addition, the Company
acquired the 13% publicly held minority interest in PTI in September 1995. After
adjusting for the Alascom gain and normalizing for the minority interest
acquired, PTI's earnings contributions in 1995 would have been $73 million. See
Note 14 to the Consolidated Financial Statements. Earnings from local exchange
operations ("LEC") acquired in 1995, internal customer access line growth of 5%,
growth in cellular operations and cable capacity sales offset the $19 million
earnings contribution associated with Alascom operations included in the 1995
results of $73 million.
REVENUES
Revenues decreased 19% from $640 million in 1995 to $521 million in 1996. The
decrease was the result of the sale of Alascom, which accounted for $193 million
of revenue in 1995 prior to its sale, offset by revenue growth from LEC assets
acquired, LEC access lines, cellular operations and cable capacity sales. Local
network service and network access service revenues increased $20 million and
$35 million, respectively, in 1996 primarily as a result of LEC assets acquired,
which contributed revenues of $40 million, and a 5% increase in the number of
customer access lines. Cellular revenues increased $10 million in 1996 primarily
as a result of a 37% increase in the number of cellular customers. PTI expects
local network service revenues to increase in 1997 as a result of continued
internal growth and pending acquisitions (see Planned Expansion).
Revenues in 1995 were below 1994 levels primarily due to a $150 million
decrease in revenue associated with the operations of Alascom prior to its sale.
This decrease was offset by $63 million of growth from acquisitions, $10 million
of growth from an increase in cellular customers and $21 million from increases
in internal access lines, enhanced services, revised LEC revenue estimates,
increased Universal Service Fund ("USF") support, and other factors.
OPERATING EXPENSES
PTI's expenses decreased 24% from $475 million in 1995 to $362 million in 1996.
As with revenues, the decrease resulted primarily from the sale of Alascom,
which incurred $156 million of expenses prior to its sale in 1995. This decrease
was offset by additional expenses of $24 million stemming from operating the LEC
properties acquired in 1995 for a full year in 1996 and also by additional
expenses needed to support the internal access line and cellular growth.
Excluding the $107 million impact of the Alascom sale, operating expenses
increased approximately $50 million in 1995 compared to 1994 due to acquisitions
and internal growth. Costs associated with operations acquired in 1995
(operating costs, maintenance and depreciation) generated additional expenses of
approximately $38 million in 1995. At the same time, cellular growth and other
internal growth increased operating expenses by approximately $12 million.
COMPETITION
On February 8, 1996, President Clinton signed into law the Telecommunications
Act of 1996 (the "1996 Act"). The 1996 Act has a general goal of promoting the
development of competitive service in all telecommunications markets over time,
including local exchange services. The issues addressed by the 1996 Act are
those affecting removal of barriers to entry for various geographic and services
markets, universal service standards and mechanisms, eligibility for and access
to universal service support funding, interconnection and unbundling of
telecommunications networks, large carrier entry into interstate interexchange
communications markets and infra-structure sharing.
The 1996 Act, which applies generally to PTI, also contains provisions with
specific importance to PTI's operations. Definitional provisions of the 1996 Act
classify PTI as a "rural telephone company" for certain purposes of the 1996
Act. Various of the inter-connection and unbundling requirements applicable
generally to incumbent LECs are subject to exemption provisions available to
rural telephone companies or to waiver provisions for LECs with less
than 2% of the total nationwide access lines, which qualification PTI also
meets.
30
TELECOMMUNICATIONS
CUSTOMER ACCESS LINES
Thousands, at year-end Projected 1997 1996 1995 1994
- --------------------------------------------------------------------
Lines 660 559 530 418
The 1996 Act authorized the establishment of a universal service fund to
provide support for eligible telecommunications carriers, for which designation
PTI believes it will qualify in the future. PTI's management believes these and
other provisions will prove consistent with PTI's current and planned
operations. PTI recognized USF revenues of $55 million in 1996 and anticipates
recognition of approximately that amount in 1997.
With respect to a number of matters, the 1996 Act permits or requires further
proceedings by the Federal Communications Commission (the "FCC") or state
regulatory commissions, or both. Following the effective date of the 1996 Act,
the FCC initiated more than one hundred separate dockets to address various
aspects of the 1996 Act's implementation. A Federal-State Joint Board was also
convened to examine and to make recommendations concerning issues pertaining to
future universal service definitions and the establishment of mechanisms for
support funding. Independently, a number of state regulatory commissions
overseeing PTI's LECs commenced proceedings relating to both the 1996 Act and
specific state statutory initiatives and requirements. PTI has actively
participated in all major proceedings that are likely to have an impact upon its
future operations and financial performance. Additionally, PTI has helped to
organize or has participated, or both, in industry organizations in an effort to
communicate its views effectively on these various issues.
PTI believes that the 1996 Act, and the regulatory proceedings deriving
therefrom, continue to prove consistent with its long-term strategic plan. Based
in part upon the rural nature of PTI's operations and the recognition currently
being accorded to rural serving requirements in the 1996 Act and derivative
regulatory proceedings, the Company does not believe that the 1996 Act and its
associated regulatory interpretations will have a material adverse impact on the
Company's consolidated financial statements.
OTHER OPERATIONS
EARNINGS CONTRIBUTION
Millions of dollars 1996 1995 1994
- --------------------------------------------------------
PFS $ 34.1 $ 30.4 $ 3.0
PGC 7.8 5.6 8.5
Tax settlement -- 32.2 --
Holdings and other (13.1) 18.0 6.5
-------------------------------
$ 28.8 $ 86.2 $ 18.0
-------------------------------
OTHER OPERATIONS
Other Operations includes two main businesses and several start-up- phase energy
ventures as well as the activities of PacifiCorp Holdings, Inc. ("Holdings").
PacifiCorp Financial Services ("PFS") has tax-advantaged investments in
affordable housing and leasing operations that consist principally of aircraft
leases. Pacific Generation Company ("PGC") has ownership interests in numerous
independent power production and cogeneration businesses. Holdings also has
ownership interests in several start-up-phase energy ventures.
RESULTS OF OPERATIONS
The earnings contribution from Other Operations decreased from 1995 to 1996
primarily as a result of the 1995 tax settlement which had the effect of
reducing Domestic Electric Operations' earnings by $32 million and increasing
Other Operations' earnings by $32 million in 1995.
The earnings of PFS and PGC increased in 1996, but were offset by Holdings
and other expense increases.
The $31 million decrease in earnings of Holdings and other in 1996 was
attributable to approximately $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 are being made, offset by the tax benefits
thereof. The increased interest expense was attributable in part to Holdings'
investment in Powercor.
Other Operations' earnings contribution increased from $18 million in 1994 to
$86 million in 1995 as a result of the impact of the $32 million tax settlement
in 1995 and approximately $19 million of impairment charges taken by PFS in
1994, as well as certain other factors.
31
LIQUIDITY AND CAPITAL RESOURCES
CASH FLOWS
Millions of dollars 1996 1995 1994
- ----------------------------------------------------------------------------
Operating activities
Domestic Electric Operations $ 718 $ 700 $ 747
Australian Electric Operations 95 10 --
Telecommunications 197 152 141
Other Operations 67 50 74
--------------------------------
Cash provided by operating activities 1,077 912 962
Investing activities (903) (2,333) (340)
Financing activities (178) 1,420 (630)
--------------------------------
Change in cash during the year $ (4) $ (1) $ (8)
--------------------------------
Cash dividends paid $ 346 $ 346 $ 345
--------------------------------
OPERATING ACTIVITIES
Operating cash flows increased by $165 million from 1995 to 1996 despite net
income remaining flat. Powercor's operations contributed $95 million of
operating cash flow in its first full year, while increased operating income in
other businesses provided $70 million of increased cash flow. Increases in
accounts receivable at Domestic Electric Operations were only partially offset
by increases in accounts payable. These changes were due to increased wholesale
and retail activity and changes in retail billing processes.
INVESTING ACTIVITIES
While investing activities in 1995 were dominated by the $1.6 billion
purchase of Powercor, no single transaction had such a pervasive influence on
1996. Rather, investing activities in 1996 focused on continued capital spending
to improve and expand existing operations and a couple of smaller but
strategically important investments--Hazelwood and the Hermiston Plant.
The Company expanded its presence in Australia when it invested approximately
$157 million, including an associated $12 million advance, for a 19.9% ownership
interest in Hazelwood which, in turn, 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 financed its investment with long-term borrowings in the U.S.
under a five-year credit facility.
On July 30, 1996, Domestic Electric Operations paid $154 million for a 50%
ownership interest in the Hermiston Plant located near Hermiston, Oregon. This
474 MW natural gas cogeneration plant began commercial operation on July 1,
1996. The payment was initially funded with short-term debt.
The Company takes all of the energy produced by the Hermiston Plant under a
long-term contract. Such commitment is expected to reduce income from operations
in 1997 by approximately $15 million as compared to 1996.
Construction spending for production, transmission, distribution
and other purposes at Domestic Electric Operations remained relatively constant,
decreasing from $455 million in 1995 to $442 million in 1996.
Powercor's construction expenditures totaled $80 million in 1996.
Capital expenditures for PTI declined $371 million from 1996 to 1995 as
spending returned to recurring levels, considering 1995 expenditures included
$376 million for LEC assets acquired. Construction spending remained constant at
$122 million.
Capital expenditures in Other Operations declined by $119 million primarily
due to the Company's 1995 purchase of the minority interest in PTI for $131
million. During 1996, the Company continued to invest in new, energy-related
ventures and will continue to do so during 1997.
The Company believes that its existing and available capital resources are
sufficient to meet working capital, dividend and construction needs in 1997.
32
LIQUIDITY AND CAPITAL RESOURCES
CAPITAL SPENDING
Millions of dollars Forecasted 1997 1996 1995 1994
- -----------------------------------------------------------------------------
Construction
Domestic Electric Operations $ 480 $ 442 $ 455 $ 638
Australian Electric Operations 75 80 2 --
Telecommunications 140 122 122 148
Other Operations 10 7 -- 3
---------------------------------------
705 651 579 789
Acquisitions and Investments
Domestic Electric Operations -- 154 -- --
Australian Electric Operations -- 145 1,589 --
Telecommunications 230 5 376 5
Other Operations 75 49 175 10
---------------------------------------
305 353 2,140 15
---------------------------------------
$ 1,010 $ 1,004 $ 2,719 $ 804
---------------------------------------
PLANNED EXPANSION
The Company continuously explores opportunities for growth in unregulated energy
and telecommunications markets. In addition to the identified expansion
opportunities highlighted below, the Company will also seek to increase its
presence throughout the world.
Because the Company believes that the U.S. will move from the existing
regulated marketplace to a market driven by customer choice, it will focus on
expansion of its unregulated businesses and other energy-related businesses,
such as natural gas. The Company believes that the experience gained by focusing
on the unregulated marketplace will facilitate the conversion to a market driven
by customer choice.
Holdings and Big Rivers Electric Corporation ("Big Rivers"), a generation and
transmission cooperative based in Henderson, Kentucky, signed an agreement
during 1996 providing for a subsidiary of Holdings to operate and manage Big
Rivers' power plants under a 25-year operating agreement for annual payments of
approximately $30 million. Big Rivers filed for bankruptcy in September 1996. In
February 1997, the bankruptcy judge opened the Big Rivers facilities to
auction. Holdings asked the U.S. District Court to take jurisdiction over
the Big Rivers reorganization away from the U.S. Bankruptcy Court. In
addition, Holdings filed a motion in bankruptcy court requesting that the
bankruptcy judge remove himself and the bankruptcy examiner from the case and
impose sanctions on the examiner. The examiner responded and requested that
sanctions be imposed on the Company and its counsel. On March 18, 1997, the
district court declined to take jurisdiction of the bankruptcy case, ruling
that the bankruptcy judge must first decide the disqualification and removal
motion. On March 19, 1997, the bankruptcy court accepted a bid from LG&E
Energy Corp. for Big Rivers' facilities. The outcome of these proceedings is
uncertain.
PTI has signed definitive agreements with US WEST Communi-cations, Inc. to
purchase local exchange telephone properties in Minnesota with 27,100 access
lines and with GTE North Incorporated to purchase properties in Michigan with
11,300 access lines. PTI has also signed a definitive agreement with the City of
Fairbanks to acquire its telephone and cellular operations that have 32,000
access lines and 6,800 cellular customers. PTI anticipates that the three
acquisitions, if approved by regulators, will require $248 million in cash, net
of approximately $20 million of cash to be acquired in the acquisitions. PTI
expects to fund these acquisitions through the issuance of external debt and
internally generated funds. All three acquisitions are expected to close in
1997.
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.
33
LIQUIDITY AND CAPITAL RESOURCES
CAPITALIZATION
Millions of dollars, except percentages 1996 1995
- --------------------------------------------------------------------------------
Long-term debt $ 5,148 47% $ 4,792 46%
Common equity 4,032 37 3,633 35
Short-term debt 937 9 1,227 12
Preferred stock 314 3 531 5
Preferred securities of Trust 210 2 -- --
Quarterly income debt securities 176 2 176 2
---------------------------------------
Total capitalization $ 10,817 100% $ 10,359 100%
---------------------------------------
The Company manages its capitalization and liquidity position in a consolidated
manner through policies established by senior management. 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. However, as a result of the $1.6 billion acquisition
of Powercor in December 1995, debt comprised 60% of total capitalization at
December 31, 1995. Through the common stock offerings described below, and
strong earnings, common equity increased $399 million. As a result, the debt to
capitalization ratio improved to 58% at December 31, 1996.
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, the Company may offer additional shares of common
stock to the public in 1997.
As described below, the Company also completed a preferred stock refunding
during 1996 that significantly lowered the after-tax cost of the preferred stock
component of its capitalization.
EQUITY TRANSACTIONS
The Company issued 8.8 million shares of common stock to the public in March and
April 1996 for net proceeds of $178 million, after deducting offering costs of
$6 million. The proceeds of such offerings were used to repay short-term debt.
During the year, the Company also issued 2.1 million shares of its common
stock under the dividend reinvestment and stock purchase plan (the "Plan"),
raising $43 million. Due to the public sales of shares in March and April 1996
and issuances under the Plan, the average number of common shares outstanding
increased 3%, from 284 million shares during 1995 to 292 million shares during
1996.
In June 1996, a wholly owned subsidiary trust (the "Trust") issued, in a
public offering, 8.7 million of its 8G% Cumulative Quarterly Income Preferred
Securities, Series A, for net proceeds of $210 million, after deducting issuance
costs of approximately $7 million. The sole asset of the Trust is $224 million
of Series C Junior Subordinated Deferred Interest Debentures issued by the
Company to the Trust. See Note 5 to the Consolidated Financial Statements.
In July and August 1996, the Company redeemed preferred stock with an
aggregate carrying value of $214 million for $222 million. The present value of
the cost savings as a result of the redemption more than justified the $8
million premium over carrying value.
DEBT TRANSACTIONS
In January 1996, the Company issued $200 million of secured medium-term notes in
the form of First Mortgage and Collateral Trust Bonds with interest rates of
6.1% and 6.7% and maturities from 2006 to 2026. Net proceeds of $198 million
were used to repay short-term debt that had been classified as long-term debt at
December 31, 1995.
In September 1996, the Company established a $500 million Secured Medium-Term
Note Program and a $250 million Unsecured Medium-Term Note Program. No issuances
occurred under either program during 1996.
In April 1996, Holdings issued $150 million of 6.75% senior notes due 2001
and $100 million of 7.2% senior notes due 2006 for net proceeds of $247 million.
The proceeds were used to repay short-term debt incurred in the Powercor
acquisition.
34
LIQUIDITY AND CAPITAL RESOURCES
REVOLVING CREDIT AGREEMENTS
Millions of dollars committed 1996
- --------------------------------------------------------------------
Domestic Electric Operations $ 700
Australian Electric Operations 1,250
Telecommunications 300
Holdings and other 500
--------
$ 2,750
--------
AVAILABLE CREDIT FACILITIES
At December 31, 1996, PacifiCorp had $700 million of committed bank revolving
credit agreements. Regulatory authorities limited PacifiCorp to $1 billion of
short-term debt, of which $675 million was outstanding at December 31, 1996. At
December 31, 1996, subsidiaries of PacifiCorp had $2.1 billion of committed
bank revolving credit agreements. The Company had $1.2 billion of short-term
debt classified as long-term debt at December 31, 1996, 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 3 and 4 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 current capital
structure, management believes PacifiCorp and its subsidiaries could have
borrowed an additional $3.4 billion of debt at December 31, 1996. PacifiCorp's
principal debt limitation is a 60% debt to capitalization test contained in its
principal credit agreements. Considering such limitation, an additional $1.7
billion of debt was available to PacifiCorp at December 31, 1996. Holdings'
adjusted consolidated debt is limited to 70% of its consolidated capitalization.
Under this test, an additional $1.7 billion of debt was available at
December 31, 1996.
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.
VARIABLE RATE LIABILITIES
Millions of dollars 1996 1995
- --------------------------------------------------------------------
Domestic Electric Operations $ 1,090 $ 1,240
Australian Electric Operations 511 896
Telecommunications 43 165
Holdings and other 202 542
-------------------
$ 1,846 $ 2,843
-------------------
Percentage of total capitalization 17% 27%
RISK MANAGEMENT
The risk management process established by the Company is designed to measure
both quantitative and qualitative risks in its businesses. A senior risk
management committee has been established to review these risks on a regular
basis. The principal quantitative risks that are measured are the risks and
volatility of cash flows for the Company's energy trading activities. Similar
processes for interest rate risk and foreign currency exchange risk will be
established in 1997.
As part of the Company's overall approach to risk management, the Company
utilizes derivative instruments. The use of such instruments is governed by a
policy that was established in 1994 and is reviewed on a regular basis by senior
management.
The Company uses interest rate swap agreements, collars, futures and forwards
to manage its exposure to interest rate fluctuations and to increase the
predictability of its cash flows by effectively converting its variable rate
debt to fixed rate debt. At December 31, 1996, the Company had entered into
derivatives with notional principal amounts totaling $958 million to manage its
interest rate exposure.
The Company uses foreign currency exchange agreements to reduce a portion of
its exposure to fluctuations in the Australian dollar stemming from its net
investments in Powercor and to hedge obligations denominated in foreign
currencies. At December 31, 1996, the notional amount of such contracts totaled
$341 million.
The Company uses electricity futures and similar instruments to hedge its
cost of electricity and has recently started to actively trade electricity and
electricity-related financial products. The trading of electricity-related
financial products is currently done in a limited number of markets, and the
Company plans to continue to develop its commodity trading expertise and expand
its activities as these markets develop.
See Notes 1, 7 and 8 to the Consolidated Financial Statements for additional
information about the Company's use of derivatives.
35
LIQUIDITY AND CAPITAL RESOURCES
CASH FLOW SUMMARY
Forecasted Actual
Millions of dollars/For the year 1999 1998 1997 1996 1995 1994
- --------------------------------------------------------------------------------- -----------------------------
Net Cash Flow from Operating Activities
Domestic Electric Operations $ 718 $ 700 $ 747
Australian Electric Operations 95 10 --
Telecommunications 197 152 141
Other Operations 67 50 74
-----------------------------
Total 1,077 912 962
Cash Dividends Paid 346 346 345
-----------------------------
Net $ 850-900 $ 825-875 $ 775-825 $ 731 $ 566 $ 617
- --------------------------------------------------------------------------------- -----------------------------
Construction
Domestic Electric Operations $ 525 $ 500 $ 480 $ 442 $ 455 $ 638
Australian Electric Operations 60 60 75 80 2 --
Telecommunications 120 145 140 122 122 148
Other Operations 10 10 10 7 -- 3
- --------------------------------------------------------------------------------- -----------------------------
Total 715 715 705 651 579 789
Acquisitions and Investments
Domestic Electric Operations 45 -- -- 154 -- --
Australian Electric Operations -- -- -- 145 1,589 --
Telecommunications 270 200 230 5 376 5
Other Operations 50 50 75 49 175 10
------------------------------------- -----------------------------
Total 365 250 305 353 2,140 15
------------------------------------- -----------------------------
Total Capital Spending $ 1,080 $ 965 $ 1,010 $ 1,004 $ 2,719 $ 804
- --------------------------------------------------------------------------------- -----------------------------
Maturities of Long-Term Debt
Domestic Electric Operations $ 299 $ 197 $ 209 $ 182 $ 51 $ 76
Australian Electric Operations -- -- -- 42 -- --
Telecommunications 48 29 16 56 15 17
Other Operations 6 15 11 19 29 61
------------------------------------- -----------------------------
Total $ 353 $ 241 $ 236 $ 299 $ 95 $ 154
------------------------------------- -----------------------------
Other Refinancings $ 42 $ 191 $ 295
- --------------------------------------------------------------------------------- -----------------------------
FORWARD-LOOKING STATEMENTS
The information in the tables and text in this document include certain forward-
looking statements that involve a number of risks and uncertainties that may
influence the financial performance and earnings of the Company and its
subsidiaries. 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 economic conditions; weather variations affecting customer
usage; competition in bulk power markets and hydroelectric production; wholesale
power marketing results; environmental, regulatory and tax legislation,
including industry restructure and deregulation initiatives; technological
developments in the electricity and telecommunications industries; and the cost
of debt and equity capital. Any forward-looking statements issued by the Company
should be considered in light of these factors.
36
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,
independent public accountants. Management made available to Deloitte & Touche
LLP 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 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 LLP also considered the internal control
structure in connection with their audit. Management considers the internal
auditors' and Deloitte & Touche LLP's recommendations concerning the Company's
internal control structure and takes cost-effective actions to respond
appropriately to these recommendations.
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.
The Audit Committee of the Board of Directors is comprised solely of outside
directors. It meets at least quarterly with management, Deloitte & Touche LLP,
internal auditors and counsel to review the work of each and ensure the
Committee's responsibilities are being properly discharged. Deloitte & Touche
LLP and internal auditors have free access to the Committee, without management
present, to discuss 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 BOARD OF DIRECTORS AND SHAREHOLDERS OF PACIFICORP:
We have audited the accompanying consolidated balance sheets of PacifiCorp and
subsidiaries as of December 31, 1996 and 1995, 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, 1996. These
consolidated 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, 1996 and 1995, and the results of their operations and their cash
flows for each of three years in the period ended December 31, 1996, in
conformity with generally accepted accounting principles.
/s/ Deloitte & Touche LLP
Deloitte & Touche LLP
Portland, Oregon
January 31, 1997 (March 11, 1997 as to Note 15)
37
STATEMENTS OF CONSOLIDATED INCOME AND RETAINED EARNINGS
Millions of dollars, except per share amounts/For the year 1996 1995 1994
- --------------------------------------------------------------------------------------------------------------
Revenues $ 4,293.8 $ 3,416.9 $ 3,498.0
----------------------------------------
Expenses
Operations 1,782.4 1,259.4 1,391.8
Maintenance 308.5 281.0 292.3
Administrative and general 308.5 254.9 244.6
Depreciation and amortization 530.4 445.6 424.3
Taxes, other than income taxes 118.9 120.1 122.7
----------------------------------------
Total 3,048.7 2,361.0 2,475.7
----------------------------------------
Income from Operations 1,245.1 1,055.9 1,022.3
----------------------------------------
Interest Expense and Other
Interest expense 465.7 378.7 334.5
Interest capitalized (11.9) (15.1) (14.5)
Minority interest and other 2.5 (51.5) (15.5)
----------------------------------------
Total 456.3 312.1 304.5
----------------------------------------
Income before income taxes 788.8 743.8 717.8
Income taxes 283.9 238.8 249.8
----------------------------------------
Net Income 504.9 505.0 468.0
Retained Earnings, January 1 632.4 474.3 351.3
Cash dividends declared
Preferred stock (29.1) (38.4) (39.6)
Common stock per share of $1.08 (317.9) (306.6) (305.4)
Preferred stock retired (7.5) (1.9) --
----------------------------------------
Retained Earnings, December 31 $ 782.8 $ 632.4 $ 474.3
----------------------------------------
Earnings on Common Stock (Net income
less preferred dividend requirement) $ 475.1 $ 466.3 $ 428.3
Average number of common
shares outstanding (Thousands) 292,424 284,272 282,912
Earnings per Common Share $ 1.62 $ 1.64 $ 1.51
(See accompanying Notes to Consolidated Financial Statements)
38
STATEMENTS OF CONSOLIDATED CASH FLOWS
Millions of dollars/For the year 1996 1995 1994
- ----------------------------------------------------------------------------------------------------
Cash Flows from Operating Activities
Net income $ 504.9 $ 505.0 $ 468.0
Adjustments to reconcile net income
to net cash provided by operating activities
Depreciation and amortization 552.0 466.2 472.5
Deferred income taxes and investment
tax credits--net 48.4 62.5 (7.5)
Minority interest and other (33.3) (28.6) 23.6
Accounts receivable and prepayments (171.2) (71.5) 5.4
Materials, supplies, fuel stock and inventory 31.9 (8.6) 11.8
Accounts payable and accrued liabilities 144.6 (13.0) (11.7)
------------------------------------
Net Cash Provided by Operating Activities 1,077.3 912.0 962.1
------------------------------------
Cash Flows from Investing Activities
Construction (650.8) (578.6) (788.7)
Operating companies and assets acquired (199.4) (2,002.1) (5.9)
Investments in and advances to affiliated
companies--net (153.5) (138.4) (9.5)
Proceeds from sales of assets 55.1 377.0 381.6
Proceeds from sales of finance assets and
principal payments 55.8 36.6 109.1
Other (10.5) (27.4) (26.7)
------------------------------------
Net Cash Used in Investing Activities (903.3) (2,332.9) (340.1)
------------------------------------
Cash Flows from Financing Activities
Changes in short-term debt (319.6) 581.5 (98.7)
Proceeds from long-term debt 669.4 1,530.8 246.6
Proceeds from issuance of common stock 221.3 .4 57.2
Proceeds from issuance of preferred securities of
Trust holding solely PacifiCorp debentures 209.6 -- --
Dividends paid (346.4) (346.5) (344.8)
Repayments of long-term debt (341.1) (285.8) (448.5)
Redemptions of capital stock (221.6) (2.6) --
Other (50.0) (58.0) (41.7)
------------------------------------
Net Cash Provided by (Used in) Financing Activities (178.4) 1,419.8 (629.9)
------------------------------------
Decrease in Cash and Cash Equivalents (4.4) (1.1) (7.9)
Cash and Cash Equivalents at Beginning of Year 22.2 23.3 31.2
------------------------------------
Cash and Cash Equivalents at End of Year $ 17.8 $ 22.2 $ 23.3
------------------------------------
Supplemental Disclosure of Cash Flow Information
Cash paid during the year for
Interest (net of amount capitalized) $ 505.7 $ 407.7 $ 399.4
Income taxes 207.9 185.5 225.6
Noncash financing activities
8.55% Junior subordinated debentures
exchanged for 2,233,037 shares of
$1.98 No Par Serial Preferred Stock -- 55.9 --
(See accompanying Notes to Consolidated Financial Statements)
39
CONSOLIDATED BALANCE SHEETS
ASSETS
Millions of dollars/December 31 1996 1995
- --------------------------------------------------------------------------------
Current Assets
Cash and cash equivalents $ 17.8 $ 22.2
Accounts receivable less allowance for doubtful
accounts: 1996/$8.6 and 1995/$7.4 718.6 545.0
Materials, supplies and fuel stock at average cost 188.7 212.1
Inventory 55.2 62.8
Other 78.2 70.1
----------------------
Total Current Assets 1,058.5 912.2
Property, Plant and Equipment
Domestic Electric Operations
Production 4,659.2 4,420.0
Transmission 2,069.2 2,042.5
Distribution 3,029.7 2,829.9
Other 1,687.9 1,655.7
Construction work in progress 252.8 310.0
----------------------
Total Domestic Electric Operations 11,698.8 11,258.1
Australian Electric Operations 1,361.9 1,302.8
Telecommunications 1,670.0 1,606.9
Other Operations 68.8 65.0
Accumulated depreciation and amortization (4,583.8) (4,280.5)
----------------------
Total Property, Plant and Equipment--Net 10,215.7 9,952.3
Other Assets
Investments in and advances to affiliated companies 358.9 187.9
Intangible assets--net 870.5 743.2
Regulatory assets--net 1,017.4 1,060.3
Finance note receivable 214.6 217.5
Finance assets--net 425.6 453.7
Real estate investments 217.0 179.8
Deferred charges and other 256.3 308.3
----------------------
Total Other Assets 3,360.3 3,150.7
----------------------
Total Assets $ 14,634.5 $ 14,015.2
----------------------
(See accompanying Notes to Consolidated Financial Statements)
40
LIABILITIES AND SHAREHOLDERS' EQUITY
Millions of dollars/December 31 1996 1995
- ------------------------------------------------------------------------------
Current Liabilities
Long-term debt currently maturing $ 235.6 $ 206.1
Notes payable and commercial paper 701.5 1,021.1
Accounts payable 469.7 345.3
Taxes, interest and dividends payable 303.5 256.4
Customer deposits and other 152.6 176.0
------------------------
Total Current Liabilities 1,862.9 2,004.9
Deferred Credits
Income taxes 1,953.1 1,910.1
Investment tax credits 148.4 159.2
Other 758.9 786.2
------------------------
Total Deferred Credits 2,860.4 2,855.5
Minority Interest 31.9 23.0
Long-Term Debt 5,323.8 4,968.2
Guaranteed Preferred Beneficial Interests
in Company's Junior Subordinated Debentures 209.7 --
Preferred Stock Subject to Mandatory Redemption 178.0 219.0
Preferred Stock 135.5 311.5
Common Equity
Common shareholders' capital
shares authorized 750,000,000;
shares outstanding: 1996/295,139,753
and 1995/284,276,709 3,236.8 3,012.9
Retained earnings 782.8 632.4
Cumulative currency translation adjustment 12.7 --
Guarantees of Employee Stock Ownership
Plan borrowings -- (12.2)
------------------------
Total Common Equity 4,032.3 3,633.1
------------------------
Commitments and Contingencies (See Notes 9 and 10)
Total Liabilities and Shareholders Equity $ 14,634.5 $ 14,015.2
------------------------
(See accompanying Notes to Consolidated Financial Statements)
41
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Years ended December 31, 1996, 1995 and 1994
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 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; Pacific Telecom, Inc.
("PTI"), a telecommunications operation (formerly 87% owned, see Note 14); and
PacifiCorp Financial Services, Inc., a financial services business. 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
approximates the Company's equity in their underlying net book value.
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 domestic utility businesses conforms with gener-ally accepted
accounting principles as applied to regulated public utilities and as prescribed
by agencies and the commissions of the various locations in which the utility
businesses operate. The Company prepares its financial statements as they relate
to Domestic Electric Operations and Telecommunications in accordance with
Statement of Financial Accounting Standards ("SFAS") 71, "Accounting for the
Effects of Certain Types of Regulation." See Note 2.
ASSET IMPAIRMENTS
Effective January 1, 1996, the Company adopted SFAS 121 "Accounting for the
Impairment of Long-Lived Assets and for Long-Lived Assets to Be Disposed Of."
This Statement requires that long-lived assets and certain identifiable
intangibles to be held and used by an entity be reviewed for impairment whenever
events or changes in circumstances indicate that the carrying amount of an asset
may not be recoverable. The Company evaluated all its assets based upon SFAS 121
and within the context of SFAS 71 for its regulated operations and concluded
that no material adjustments were required. See Note 2.
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 significant gains and
losses resulting from foreign currency transactions are included in income.
PROPERTY, PLANT AND EQUIPMENT
Property, plant and equipment are stated at original cost of contracted
services, direct labor and material, interest capitalized during construction
and indirect charges for engineering, supervision and similar overhead items.
The cost of depreciable utility properties retired, including the cost of
removal, less salvage, is charged to accumulated depreciation.
DEPRECIATION AND AMORTIZATION
At December 31, 1996, the average depreciable life of property, plant and
equipment by category was: Domestic Electric Operations--Production, 41 years;
Transmission, 42 years; Distribution, 30 years; Other, 18 years; Australian
Electric Operations, 21 years; and Telecommunications, 16 years.
Depreciation and amortization is generally computed by the straight-line
method over the estimated economic useful lives of the related assets after
giving effect to requirements as prescribed by the Company's various regulatory
jurisdictions. Provisions for depreciation (excluding amortization of capital
leases) in the domestic electric, Australian electric, and telecommunications
businesses were 3.6%, 3.5% and 3.4% of average depreciable assets in 1996, 1995
and 1994, respectively.
42
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 ($460 million and $32 million, respectively, in
1996 and $312 million and $30 million, respectively, in 1995); franchises of
local exchange and cellular companies ($397 million in 1996 and $398 million in
1995); and excess cost over net assets of businesses acquired ($43 million in
1996 and 1995). These costs are offset by accumulated amortization ($62 million
in 1996 and $40 million in 1995). Intangible assets are generally being
amortized over 40 years.
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 $63 million and
$71 million at December 31, 1996 and 1995, 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 those 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.
INTEREST CAPITALIZED
Costs of debt applicable to domestic utility properties are capitalized during
construction. Generally, the composite capitalization rates were 5.7% for 1996,
6.2% for 1995 and 4.7% for 1994.
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.
Investment tax credits for regulated operations in the United States are
deferred and amortized to income over the average estimated
lives of the properties. All other investment tax credits are recognized when
utilized.
Provision is made for U.S. income taxes 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.
PTI participates with other telephone companies in access revenue pools for
certain interstate and intrastate revenues, which are initially recorded based
on estimates.
PREFERRED STOCK RETIRED
Amounts paid in excess of the net carrying value of preferred stock retired are
amortized in accordance with regulatory orders.
RECLASSIFICATION
Certain amounts from prior years have been reclassified to conform with the 1996
method of presentation. These reclassifications had no effect on previously
reported consolidated net income.
43
NOTE 2
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, the Company's domestic utility
operations capitalize certain costs, regulatory assets, in accordance with
regulatory authority whereby those costs will be expensed and recovered in
future periods. Regulatory assets--net at December 31, 1996 and 1995 included
the following:
Millions of dollars/December 31 1996 1995
- --------------------------------------------------------------------------------
Deferred taxes--net $ 670.6 $ 687.1
Deferred pension costs 102.9 116.8
Demand-side resource costs 118.8 110.0
Unamortized net loss on reacquired debt 68.4 71.8
Unrecovered Trojan Plant and regulatory
study costs 26.8 28.4
Various other costs 29.9 46.2
------------------------
Total $ 1,017.4 $ 1,060.3
------------------------
If the Company, at some point in the future, determines that all or a
portion of the domestic utility operations no longer meet the criteria for
continued application of SFAS 71, the Company would be required to adopt the
provisions of SFAS 101, "Regulated Enterprises--Accounting for the
Discontinuation of Application of FASB Statement No. 71." Adoption of SFAS 101
would require the Company to write off the regulatory assets and liabilities
relating to those operations not meeting SFAS 71 requirements.
The utility industry will also be impacted by the application of SFAS 121
as a result of deregulation. This accounting statement 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 cost recovery
mechanisms.
Restructuring bills are being considered in all states in which the Company
provides retail service. The Company expects any legislation passed to provide
an opportunity to recover costs which have been placed at risk.
NOTE 3
SHORT-TERM DEBT AND
BORROWING ARRANGEMENTS
The Companies' short-term debt and borrowing arrangements were as follows:
December 31 For the year
----------------------- ----------------------
Average Average
Interest Average Interest
Millions of dollars Balance Rate(a) Outstanding Rate(b)
- -------------------------------------------------------------------------------
1996
PacifiCorp $ 549.3 5.6% $ 424.4 5.4%
Subsidiaries 152.2 5.6 287.2 5.6
1995
PacifiCorp $ 479.9 5.9% $ 407.2 5.9%
Subsidiaries 541.2 6.1 180.0 6.2
1994
PacifiCorp $ 433.0 6.0% $ 372.8 4.5%
Subsidiaries 21.7 7.5 95.0 4.6
(a) Computed by dividing the total interest on principal amounts outstanding at
the end of the period by the weighted daily principal amounts outstanding.
(b) Computed by dividing the total interest expense for the period by the
average daily principal amount outstanding for the period.
At December 31, 1996, PacifiCorp's commercial paper and bank line
borrowings were supported by revolving credit agreements totaling $700 million.
At December 31, 1996, subsidiaries had committed bank revolving credit
agreements totaling $2.1 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, 1996, PacifiCorp had $123 million and subsidiaries had $1.1 billion
of short-term debt classified as long-term. Consolidated commitment fees were
approximately $2 million in 1996 and 1995 and $3 million in 1994.
44
NOTE 4
LONG-TERM DEBT
The Company's long-term debt was as follows:
Millions of dollars/December 31 1996 1995
- -------------------------------------------------------------------------------
PacifiCorp
First mortgage and collateral trust bonds
Maturing 1997 through 2001/5.9%-9.5%(a) $ 946.5 $ 1,112.1
Maturing 2002 through 2006/6.1%-9% 601.0 519.8
Maturing 2007 through 2011/6.6%-9.2% 235.8 237.5
Maturing 2012 through 2016/7.3%-8.8% 172.9 175.6
Maturing 2017 through 2021/8.4%-8.5% 38.1 38.4
Maturing 2022 through 2026/6.7%-8.6% 441.5 341.5
Guaranty of pollution control revenue bonds
5.6%-5.7% due 2021 through 2023(b) 71.2 71.2
Variable rate due 2013 through 2024(b)(c) 216.5 216.5
Variable rate due 2005 through 2030(c) 450.7 456.6
Funds held by trustees (12.1) (12.4)
8.4%-8.6% Junior subordinated debentures
due 2025 through 2035 175.8 175.8
Commercial paper(c)(e) 123.4 200.0
Other 28.1 31.3
----------------------
Total 3,489.4 3,563.9
Less current maturities 203.8 176.8
----------------------
Total 3,285.6 3,387.1
----------------------
Subsidiaries
2%-11.8% First mortgage notes and bonds
maturing through 2028 139.3 143.2
6.8%-10.2% Notes due through 2020 291.2 59.8
Australian bank bill borrowings(d)(e) 922.3 896.2
Commercial paper and committed bank lines(c)(e) 185.0 75.0
Variable rate notes due through 2007(c) 35.8 42.0
6.6%-9.4% Medium-term notes due through 2008 323.5 223.5
4.5%-11% Nonrecourse debt due through 2031 170.8 155.9
Other 2.1 14.8
----------------------
Total 2,070.0 1,610.4
Less current maturities 31.8 29.3
----------------------
Total 2,038.2 1,581.1
----------------------
Total $ 5,323.8 $ 4,968.2
----------------------
(a) Includes $50 million of 9.4% bonds issued to secure obligations under an
equivalent 10-year yen loan. A currency swap converted the fixed rate yen
liability to a floating rate U.S. dollar liability based on six-month LIBOR
plus .02% (interest rate 5.9% at December 31, 1996).
(b) 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.
(c) Interest rates fluctuate based on various rates, primarily on certificate
of deposit rates, interbank borrowing rates, prime rates or other short-
term market rates.
(d) Interest rates fluctuate based on Australian Bank Bill Acceptance Rates.
The loan agreement requires that at least 50% of the borrowings must be
hedged against variations in interest rates. Approximately $630 million was
hedged at December 31, 1996 at an average rate of 7.6% and for an average
life of 4.4 years.
(e) 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
$1.2 billion of short-term debt as long-term debt.
Approximately $7 billion of the assets of the Companies secure long-term
debt and capital lease obligations. 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 bonds, pollution control
revenue bonds, commercial paper, bank debt, capital lease obligations and any
future senior indebtedness.
Nonrecourse long-term notes are secured by assignment of
related finance receivables, asset security interests and cash flows from
operating leases. The noteholders have no additional recourse to
the Companies.
The annual maturities of long-term debt and redeemable
preferred stock outstanding are $236 million, $241 million, $353
million, $1.1 billion and $622 million in 1997 through
2001, respectively.
45
NOTE 5
GUARANTEED PREFERRED
BENEFICIAL INTERESTS IN COMPANY'S
JUNIOR SUBORDINATED DEBENTURES
On June 11, 1996, PacifiCorp Capital I, a wholly owned subsidiary trust of the
Company (the "Trust"), issued, in a public offering, 8,680,000 of its 8G%
Company Obligated Mandatorily Redeemable Preferred Securities (the "Preferred
Securities"), representing preferred undivided beneficial interests in the
assets of the Trust, with a liquidation preference of $25 per Preferred
Security. The sole assets of the Trust are $224 million, in aggregate principal
amount, of the Company's 8G% Junior Subordinated Deferrable Interest Debentures,
Series C, due June 30, 2036 and certain rights under a related guarantee by the
Company. The Company's guarantee of the Preferred Securities, considered
together with the other obligations of the Company with respect to Preferred
Securities, constitutes a full and unconditional guarantee by the Company of the
Trust's obligations with respect to the Preferred Securities.
NOTE 6
COMMON AND PREFERRED STOCK
Common
Shares Shares Share-
Thousands of shares/ Common Preferred holders
Millions of dollars Stock Stock Capital
- -----------------------------------------------------------------------------
At January 1, 1994 281,021 10,532 $2,953.4
Sales through Dividend
Reinvestment and
Stock Purchase Plan 2,194 -- 38.0
Sales through Employees
Stock Plans 1,036 -- 19.2
----------------------------------------
At December 31, 1994 284,251 10,532 3,010.6
Sales through Employees'
Stock Plans 26 -- .4
Junior subordinated
debentures exchanged
for preferred stock -- (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
----------------------------------------
At December 31, 1996, there were 28,905,056 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.
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.
PREFERRED STOCK OUTSTANDING
Thousands of shares/
Millions of dollars
December 31 1996 1996 1995 1995
Series Shares Amount Shares Amount
- -------------------------------------------------------------------------------
Subject to Mandatory Redemption
No Par Serial Preferred,
($100 stated value)
16,000 Shares Authorized
$ 7.12 30 $ 3.0 440 $ 44.0
7.70 1,000 100.0 1,000 100.0
7.48 750 75.0 750 75.0
----------------------------------------------
Total $ 178.0 $ 219.0
----------------------------------------------
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
1.76 -- -- 394 9.8
1.98 -- -- 502 12.6
2.13 -- -- 666 16.7
1.98, Series 1992 2,767 69.1 2,767 69.1
Auction Rate ($100,000
stated value) -- -- 1 100.0
Serial Preferred $100 Stated Value Per
Share, 3,500 Shares Authorized
4.52% 2 .2 2 .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 .6 6 .6
7.00 18 1.8 18 1.8
7.96 -- -- 135 13.5
8.92 -- -- 69 6.9
9.08 -- -- 165 16.5
5% Preferred, $100 Stated
Value, 127 Shares Authorized
and Outstanding 127 12.7 127 12.7
----------------------------------------------
Total $ 135.5 $ 311.5
----------------------------------------------
46
Mandatory redemption requirements at stated value plus accrued dividends on
No Par Serial Preferred Stock are as follows: beginning in 1997, 15,000 shares
of the $7.12 series are redeemable annually; 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 $7.12 series or the $7.48
series, it may not pay cash dividends on common stock.
NOTE 7
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 liabilities, thereby managing its risk. 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 ratings. The Company's credit policy provides that counterparties satisfy
minimum 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 1996 1995
- --------------------------------------------------------------------------------
Interest rate swaps $ 846.4 $ 219.9
Interest rate collars purchased 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 from variable to fixed
interest rates, 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 outstanding.
Under the various swap agreements, the Company agrees with other parties to
exchange, at specified intervals, the difference between fixed-rate and
floating-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.
Millions of dollars/December 31 1996 1995
- -------------------------------------------------------------------------------
Pay-fixed swaps
Average pay rate 7.7% 7.7%
Average receive rate 5.6 4.4
Interest rate futures and forward contracts are generally used by
Australian Electric Operations to mitigate variable interest rate exposure on
Australian bank bill borrowings and are usually settled in cash. The futures
and forwards are accounted for as hedges of the Australian bank bill borrowings.
Additionally, Australian Electric Operations purchases interest rate collar
agreements. The 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%.
FOREIGN EXCHANGE RISK MANAGEMENT--At December 31, 1996, the Company held a
foreign currency exchange agreement, which provides for the exchange of
$50 million for 7.4 billion yen to meet a 1997 yen-denominated obligation of an
equivalent amount. In addition, at December 31, 1996, Holdings held three
combined interest rate and currency swaps that terminate in 2002, with an
aggregate notional amount of $291 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 the three swaps, which also were designated
as a hedge of Holdings' investment in Powercor, were effectively offset in 1997
by the purchase of a swap transaction with approximately the same terms. The net
amount of the swaps should not have a significant impact on future net income.
47
COMMODITY RISK MANAGEMENT--The Company has utilized electricity forward
contracts (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.
At December 31, 1996, Australian Electric Operations had 23
forward contracts with electricity generation companies on notional quantities
amounting to approximately 26.8 million MWh through December 31, 2000. The
average fixed price to be paid by Australian Electric Operations was $28.75 per
MWh compared to the average price of similar contracts at December 31, 1996 of
$27.46.
At December 31, 1996, Domestic Electric Operations had 67 NYMEX futures
contracts to sell electricity with notional quantities amounting to
approximately 49,300 MWh all expiring in 1997. The average fixed price to be
received by Domestic Electric Operations was $19.33 per MWh compared to the
NYMEX average spot market price of $15.78 per MWh.
TRADING ACTIVITIES--During 1996 a subsidiary of Holdings began to trade
electricity related products. Such transactions involved the physical delivery
of electricity and are accounted for as revenue or purchased power upon delivery
and, at December 31, 1996, amounted to a net purchase position of 1,200 MWh. As
additional markets for electricity-related products develop, including
derivative products, the Company anticipates that this activity will expand.
NOTE 8
FAIR VALUE OF
FINANCIAL INSTRUMENTS
December 31, 1996 December 31, 1995
---------------------------------------------
Carrying Fair Carrying Fair
Amount Value Amount Value
- ----------------------------------------------------------------------------
Long-term debt $ 5,536.6 $ 5,621.5 $ 5,134.4 $ 5,370.5
Preferred securities of
Trust holding solely
PacifiCorp debentures 209.7 210.9 -- --
Preferred stock subject to
mandatory redemption 178.0 195.8 219.0 240.3
Derivatives relating to
Currency (21.5) (21.5) -- (1.4)
Interest (10.8) (52.5) -- (35.4)
Electricity futures -- .2 -- --
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, 1996.
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 and capital lease
obligations were excluded. 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, currency swaps and electricity
futures is the estimated amount the Company would have to pay to terminate the
agreements, taking into account current interest and currency exchange rates,
electricity market prices and the current credit-worthiness of the agreement
counterparties. 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 entered into for the long-term forward contracts and the
inactive trading in the electricity spot market.
NOTE 9
LEASES
The Companies lease 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, 1996, 1995 and 1994 was
$29 million, $50 million and $59 million, respectively.
Future minimum lease payments under noncancellable operating leases are
$20 million, $14 million, $7 million, $5 million and $4 million for 1997 through
2001, respectively.
NOTE 10
COMMITMENTS AND CONTINGENCIES
CONSTRUCTION AND OTHER
Construction and acquisitions are estimated at $1 billion for 1997.
As a part of these programs, substantial commitments have been made.
The Company is subject to numerous environmental laws including: the
Federal Clean Air Act, as enforced by the Environmental Protection Agency and
various state agencies; the 1990 Clean Air Act Amendments; the Endangered
Species Act as it relates to certain potentially endangered species of salmon;
the Comprehensive Environmental Response, Compensation and Liability Act,
relating to environmental cleanups; along with the Federal Resource Conservation
and Recovery Act and the Clean Water Act relating to water quality. These laws
could potentially impact future operations. For those contingencies identified
at December 31, 1996, principally the Superfund sites where the Company has been
or may be designated as a potentially responsible party and violations under the
Clean Air Act, future costs
48
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 costs 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. This is
consistent with industry practices, and the Company believes its reclamation
obligations are adequately provided for.
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.
JOINTLY OWNED PLANTS
At December 31, 1996, 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% $ 178.1 $ 108.0 $ 4.2
Jim Bridger
Units 1, 2, 3 and 4 66.7 789.7 308.1 2.2
Trojan(a) 2.5 -- -- --
Colstrip Units 3 and 4 10.0 203.4 63.2 1.1
Hunter Unit 1 93.8 260.2 100.9 .8
Hunter Unit 2 60.3 187.6 66.4 1.3
Wyodak 80.0 303.9 96.6 1.8
Craig Station
Units 1 and 2 19.3 150.0(b) 56.9 1.1
Hayden Station Unit 1 24.5 17.1(b) 10.6 1.1
Hayden Station Unit 2 12.6 17.0(b) 9.9 .8
Hermiston(c) 50.0 164.9 3.4 --
(a) Plant, inventory, fuel and decommissioning costs totaling $27 million
relating to the Trojan Plant, were included in regulatory assets--net at
December 31, 1996.
(b) Excludes unallocated acquisition adjustments of $119 million.
(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.
PURCHASED POWER
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, including sales contracts with minimum payment
requirements, and retail load growth. As part of its energy resource portfolio,
Domestic Electric Operations acquires power through long-term purchases and/or
exchange agreements which require minimum fixed payments of $298 million in
1997, $294 million in 1998 and 1999, $291 million in 2000 and $252 million in
2001.
These 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 1996, such purchases approximated
3.5% of energy requirements.
At December 31, 1996, 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% $ 5.0
Priest Rapids 2005 109,602 13.9 3.7
Rocky Reach 2011 64,297 5.3 2.4
Wells 2018 59,617 7.7 1.9
------------------------------------------------------
Total 388,960 $ 13.0
------------------------------------------------------
(a) Annual costs, in millions of dollars, include debt service of $6 million.
The Company has a 4% interest in the Intermountain Power Project
("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.
49
NOTE 11
INCOME TAXES
The Company's combined federal and state effective income tax rate was 36% in
1996, 32% in 1995 and 35% in 1994. The difference between taxes calculated as if
the statutory federal tax rate of 35% was applied to income before income taxes
and the recorded tax expense is reconciled as follows:
Millions of dollars/For the year 1996 1995 1994
- -------------------------------------------------------------------------------
Computed Federal Income Taxes $ 276.1 $ 260.3 $ 251.2
--------------------------------
Increase (Reduction) in Tax Resulting from
Depreciation differences 12.8 9.7 8.4
Investment tax credits (11.0) (12.3) (15.5)
Excess of tax over book stock basis (1.0) (24.4) (1.4)
Audit settlement .5 (16.8) --
Affordable housing credits (10.6) (8.4) (8.2)
Other items capitalized and miscellaneous
differences (5.3) 4.8 .7
--------------------------------
Total (14.6) (47.4) (16.0)
--------------------------------
Federal Income Tax 261.5 212.9 235.2
State Income Tax, Net of Federal
Income Tax Benefit 22.4 25.9 14.6
--------------------------------
Total Income Tax Expense $ 283.9 $ 238.8 $ 249.8
--------------------------------
The provision for income taxes is summarized as follows:
Millions of dollars/For the year 1996 1995 1994
- -------------------------------------------------------------------------------
Current
Federal $ 207.5 $ 152.2 $ 222.7
State 28.0 23.1 34.6
Foreign -- 1.0 --
--------------------------------
Total 235.5 176.3 257.3
--------------------------------
Deferred
Federal 43.7 56.5 17.8
State 7.6 17.3 (9.8)
Foreign 8.1 1.0 --
--------------------------------
Total 59.4 74.8 8.0
--------------------------------
Investment Tax Credits (11.0) (12.3) (15.5)
--------------------------------
Total Income Tax Expense $ 283.9 $ 238.8 $ 249.8
--------------------------------
50
The tax effects of significant items comprising the Company's net deferred
tax liability were as follows:
Millions of dollars/December 31 1996 1995
- ----------------------------------------------------------------------------
Deferred Tax Liabilities
Property, plant and equipment $ 1,306.8 $ 1,213.1
Regulatory assets 733.6 756.8
Other deferred liabilities 30.7 52.5
Deferred Tax Assets
Regulatory liabilities (63.0) (69.7)
Book reserves not deductible for tax (55.0) (42.6)
--------------------------
Net Deferred Tax Liability $ 1,953.1 $ 1,910.1
--------------------------
--------------------------
During 1995, the Company and the Internal Revenue Service (the "IRS")
agreed on a settlement of all issues related to the IRS examination of the
Company's federal income tax returns for the years 1983 through 1988, including
matters relating to the Company's abandonment of
its 10% interest in Washington Public Power Supply System Unit No. 3.
During 1996, the Company received an examination report for 1989 and 1990
proposing adjustments that would increase income tax by $11 million. The Company
filed a protest of certain proposed adjustments on July 30, 1996. The Company's
1991, 1992 and 1993 federal income tax returns are currently under examination
by the IRS.
Financial Services acquires housing projects that qualify for the low-
income housing credit established as part of the Tax Reform Act of 1986 to
provide an incentive for the development and preservation of privately owned
affordable rental housing. Annual tax benefits scheduled to be received from
these projects are expected to be $13 million, $12 million, $11 million,
$7 million and $6 million for 1997 through 2001, respectively.
NOTE 12
RETIREMENT PLANS
The Companies have pension plans covering substantially all of their employees.
Benefits under plans in the United States are generally 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, 1996, plan assets were primarily invested in common stocks, bonds
and U.S. government obligations.
All permanent employees of Powercor engaged prior to October 4, 1994 are
members of Divisions B or C of the Superannuation Fund ("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. Division B members
contribute at 6% of superannuation salary, and Division C members can contribute
at 0, 3, or 6%. During 1996, contributions were made to the Fund at the rate of
9.25% for the defined benefit.
Net pension cost is summarized as follows:
Millions of dollars/For the year 1996 1995 1994
- ------------------------------------------------------------------------------
Service cost--benefits earned $ 35.5 $ 24.4 $ 26.4
Interest cost on projected
benefit obligation 89.0 80.1 74.1
Actual (gain) loss on plan assets (79.9) (153.5) 4.9
Net amortization and deferral 9.3 100.5 (59.7)
Regulatory deferral(a) 14.2 29.4 .7
---------------------------------
Net Pension Cost $ 68.1 $ 80.9 $ 46.4
---------------------------------
---------------------------------
(a) Domestic Electric Operations has received accounting orders from its
primary and certain other regulatory authorities to defer the difference
between pension cost as determined in accordance with SFAS 87 and 88 and
that determined for funding purposes. See Note 2.
51
The funded status, net pension liability and significant assumptions are as
follows:
Millions of dollars/December 31 1996 1995
- -----------------------------------------------------------------------------
Actuarial present value of
benefit obligations
Vested benefit obligation $ 1,045.5 $ 1,033.9
----------------------------
Accumulated benefit obligation 1,120.8 1,090.1
----------------------------
Projected benefit obligation 1,270.7 1,262.1
Plan assets at fair value 1,042.5 895.6
----------------------------
Projected benefit obligation
in excess of plan assets 228.2 366.5
Unrecognized prior service cost (11.9) (9.8)
Unrecognized net loss (65.5) (104.0)
Unrecognized net obligation (7.5) (89.5)
Minimum liability adjustment 2.9 65.2
----------------------------
Net Pension Liability $ 146.2 $ 228.4
----------------------------
Discount rate 7.25%-7.5% 7.25%
Expected long-term rate of return
on assets 8.5%-9% 8.5%-9%
Rate of increase in compensation levels 4.5%-6% 5%-6%
Domestic Electric Operations offered early retirement incentive programs in
1987 and 1990. Included in the table above is the present value of all future
termination benefits provided of $58 million. Domestic Electric Operations
received regulatory accounting orders to defer early retirement costs as a
regulatory asset to be amortized through the year 2020. See Note 2.
NOTE 13
OTHER POSTRETIREMENT BENEFITS
Domestic Electric Operations and Telecommunications provide health care and life
insurance benefits through various plans for their 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. For those employees retiring after January 1, 1993, the Company
funds postretirement benefit expense through a combination of funding vehicles.
The Company funded $38 million and $40 million of postretirement benefit expense
during 1996 and 1995, respectively. These funds are invested in common stocks,
bonds and U.S. government obligations.
The net periodic postretirement benefit cost is summarized as follows:
Millions of dollars/For the year 1996 1995 1994
- -----------------------------------------------------------------------------
Service cost--benefits earned $ 9.6 $ 8.3 $ 9.5
Interest cost on accumulated
postretirement benefit
obligation 27.8 32.6 30.7
Amortization of transition
obligation 14.3 15.7 16.3
Regulatory deferral 3.4 (4.5) (5.2)
Net asset gain (loss) during
the period deferred for
future recognition 3.7 3.7 (4.4)
Actual return on plan assets (14.5) (10.7) .3
-----------------------------------
Net Periodic Postretirement
Benefit Cost $ 44.3 $ 45.1 $ 47.2
-----------------------------------
-----------------------------------
52
The accumulated postretirement benefit obligation ("APBO") was as follows:
Millions of dollars/December 31 1996 1995
- ------------------------------------------------------------------------------
Retirees and dependents $ 209.5 $ 267.7
Fully eligible active plan
participants 22.2 23.5
Other active plan participants 160.8 174.5
--------------------------
APBO 392.5 465.7
Plan assets at fair value 166.2 117.4
--------------------------
APBO in excess of plan assets 226.3 348.3
Unrecognized prior service cost .5 .6
Unrecognized transition obligation (251.0) (266.7)
Unrecognized net gain (loss) 48.2 (50.1)
--------------------------
Accrued Postretirement Benefit
Obligation $ 24.0 $ 32.1
--------------------------
--------------------------
Discount rate 7.5% 7.25%
Estimated long-term rate of
return on assets 9% 8.8%-9%
Initial health care cost trend
rate--under 65 8.8%-11% 11%
Initial health care cost trend
rate--over 65 8.4%-10.5% 10%
Ultimate health care cost trend rate 4.5% 4.5%
The assumed health care cost trend rates gradually decrease over eight years.
The health care cost trend rate assumptions have 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, 1996 by
$29 million, and the annual net periodic postretirement benefit costs by
$3 million.
NOTE 14
ACQUISITIONS AND DISPOSITIONS
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. The other partners in the partnership are subsidiaries of
National Power PLC (51.9%), Destec Energy (20%) and Commonwealth Bank Group of
Australia (8.2%).
On December 12, 1995, Holdings purchased Powercor, an elec-
tricity distributor in Australia, for approximately $1.6 billion in cash.
Powercor's service territory includes a portion of suburban Melbourne and the
western and central regions of the State of Victoria. Powercor currently has
approximately 547,000 customers. 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.
On September 27, 1995, holders of a majority of the 5.3 million shares of
outstanding common stock held by minority shareholders of PTI voted in favor of
the merger of a wholly owned subsidiary of Holdings into PTI. Shareholders
tendering shares pursuant to the merger were paid a total of $131 million, or
$30 per share, and an accrued liability of $28 million was established to cover
estimated amounts payable to dissenters.
During 1995, PTI purchased certain rural telephone exchange assets in
Colorado, Washington and Oregon for approximately $376 million.
On August 7, 1995, PTI closed the sale of the stock of Alascom, Inc.
("Alascom") to AT&T Corp. ("AT&T"), in a transaction providing $366 million in
proceeds. Under terms of the agreement, AT&T paid $291 million in cash for the
Alascom stock and for settlement of all past cost study issues. AT&T agreed to
allow PTI to retain a $75 million transition payment made by AT&T to Alascom in
July 1994. AT&T made a down payment of $30 million to PTI upon signing the stock
purchase agreement in October 1994. The remaining $261 million was paid when the
transaction closed. The Company recognized an after-tax gain of $37 million from
the sale of Alascom.
Summarized income statement data for Alascom are as follows:
7 months ended For the
July 31, year
Millions of dollars (unaudited) 1995 1994
- --------------------------------------------------------------------------------
Revenues $ 193.1 $ 343.5
Income from operations 36.9 80.7
NOTE 15
SUBSEQUENT EVENTS
On March 4, 1997 the Utah Legislature passed a bill which creates a legislative
task force to study stranded cost issues and the timing of
customer choice. The bill freezes rates at January 31, 1997 levels until 60 days
following the conclusion of the 1998 legislative general session. The PSC is
precluded from holding any hearings on rate changes
during the freeze period. The Company has committed to reduce prices to Utah
customers by $12 million annually on approximately May 1, 1997.
On March 11, 1997, Holdings entered into an agreement to acquire TPC
Corporation, a natural gas gathering, processing, storage and
marketing company. The acquisition is expected to cost approximately $288
million in cash plus assumed debt of approximately $149 million.
53
NOTE 16
SELECTED FINANCIAL AND SEGMENT INFORMATION
Millions of dollars, except per share information/For the year 1996 1995 1994 1993 1992
- --------------------------------------------------------------------------------------------------------------------------------
Revenues
Domestic Electric Operations $ 2,960.8 $ 2,616.1 $ 2,647.8 $2,506.9 $ 2,362.4
Australian Electric Operations 658.8 25.9 -- -- --
Telecommunications 521.1 640.1 696.5 693.8 690.6
Other Operations(a) 153.1 134.8 153.7 196.4 175.1
-------------------------------------------------------------
Total $ 4,293.8 $ 3,416.9 $ 3,498.0 $3,397.1 $ 3,228.1
- --------------------------------------------------------------------------------------------------------------------------------
Income from Operations
Domestic Electric Operations $ 869.8 $ 800.9 $ 819.3 $ 784.3 $ 677.7
Australian Electric Operations 127.4 5.5 -- -- --
Telecommunications 158.7 165.3 164.7 140.8 138.6
Other Operations(a) 89.2 84.2 38.3 44.1 (112.8)
-------------------------------------------------------------
Total $ 1,245.1 $ 1,055.9 $ 1,022.3 $ 969.2 $ 703.5
- --------------------------------------------------------------------------------------------------------------------------------
Net Income (Loss) $ 504.9 $ 505.0 $ 468.0 $ 479.1 $ (340.4)
- --------------------------------------------------------------------------------------------------------------------------------
Earnings Contribution (Loss) on Common Stock
Continuing operations
Domestic Electric Operations $ 341.5 $ 276.4 $ 339.8 $ 322.3 $ 202.9
Australian Electric Operations 30.1 .7 -- -- --
Telecommunications 74.7 103.0 70.5 50.9 57.3
Other Operations(a) 28.8 86.2 18.0 10.2 (147.3)
-------------------------------------------------------------
Total 475.1 466.3 428.3 383.4 112.9
Discontinued operations(b) -- -- -- 52.4 (490.6)
Cumulative effect of change in accounting
for income taxes -- -- -- 4.0 --
-------------------------------------------------------------
Total $ 475.1 $ 466.3 $ 428.3 $ 439.8 $ (377.7)
- --------------------------------------------------------------------------------------------------------------------------------
Earnings (Loss) per Share
Continuing operations
Domestic Electric Operations $ 1.17 $ .97 $ 1.20 $ 1.17 $ .76
Australian Electric Operations .10 -- -- -- --
Telecommunications .25 .36 .25 .19 .21
Other Operations(a) .10 .31 .06 .04 (.55)
-------------------------------------------------------------
Total 1.62 1.64 1.51 1.40 .42
Discontinued operations(b) -- -- -- .19 (1.84)
Cumulative effect of change in accounting
for income taxes -- -- -- .01 --
-------------------------------------------------------------
Total $ 1.62 $ 1.64 $ 1.51 $ 1.60 $ (1.42)
- --------------------------------------------------------------------------------------------------------------------------------
Cash Dividends Declared per Common Share $ 1.08 $ 1.08 $ 1.08 $ 1.08 $ 1.53
- --------------------------------------------------------------------------------------------------------------------------------
Market Price per Common Share(c) 20 1/2 21 1/8 18 1/8 19 1/4 19 3/4
- --------------------------------------------------------------------------------------------------------------------------------
Capitalization
Short-term debt $ 937 $ 1,227 $ 551 $ 709 $ 973
Long-term debt 5,324 4,968 3,768 3,924 4,181
Preferred securities of Trust 210 -- -- -- --
Redeemable preferred stock 178 219 219 219 219
Preferred stock 136 312 367 367 417
Common equity 4,032 3,633 3,460 3,263 2,908
-------------------------------------------------------------
Total $ 10,817 $ 10,359 $ 8,365 $ 8,482 $ 8,698
- --------------------------------------------------------------------------------------------------------------------------------
Total Assets $ 14,635 $ 14,015 $ 11,846 $ 11,957 $ 11,257
- --------------------------------------------------------------------------------------------------------------------------------
(a) Other Operations includes the operations of PacifiCorp Financial Services,
Inc., Pacific Generation Company, and several start-up-phase ventures, as
well as the activities of PacifiCorp Holdings, Inc. including financing
costs.
(b) Discontinued operations includes the Company's interest in NERCO, Inc. and
TRT Communications, Inc.
(c) Unaudited.
54
DOMESTIC ELECTRIC OPERATIONS
3-Year
1996 to 1995 Compound
Percentage Annual
Millions of dollars, except as noted/For the year 1996 1995 1994 Comparison Growth
- ---------------------------------------------------------------------------------------------------------------------------------
Revenues
Residential $ 785.6 $ 721.9 $ 724.9 9% 4%
Commercial 622.4 575.9 570.4 8 5
Industrial 705.0 697.6 726.3 1 --
Other 32.5 29.7 30.7 9 3
---------------------------------------------------------------
Retail Sales 2,145.5 2,025.1 2,052.3 6 3
---------------------------------------------------------------
Wholesale--firm 635.4 487.7 456.2 30 15
Wholesale--nonfirm 103.4 32.3 76.5 * 10
---------------------------------------------------------------
Wholesale Sales 738.8 520.0 532.7 42 14
---------------------------------------------------------------
Other 76.5 71.0 62.8 8 26
---------------------------------------------------------------
Total 2,960.8 2,616.1 2,647.8 13 6
---------------------------------------------------------------
Expenses
Fuel 443.0 431.6 483.0 3 --
Purchased power 586.9 356.4 356.7 65 23
Other operations 277.7 274.0 263.2 1 2
Maintenance 167.3 168.4 174.5 (1) (1)
Administrative and general 176.3 160.5 142.7 10 8
Depreciation and amortization 343.4 320.4 301.6 7 7
Taxes, other than income taxes 96.4 103.9 106.8 (7) (3)
---------------------------------------------------------------
Total 2,091.0 1,815.2 1,828.5 15 7
---------------------------------------------------------------
Income from Operations 869.8 800.9 819.3 9 4
Interest expense 304.2 311.9 264.3 (2) 4
Interest capitalized (11.4) (14.9) (14.5) 23 6
Other income--net (11.2) (25.3) (30.2) 56 5
Income tax expense 216.9 214.1 220.2 1 7
---------------------------------------------------------------
Net Income 371.3 315.1 379.5 18 1
Preferred Dividend Requirement 29.8 38.7 39.7 (23) (9)
---------------------------------------------------------------
Earnings Contribution(a) $ 341.5 $ 276.4 $ 339.8 24 2
---------------------------------------------------------------
---------------------------------------------------------------
Identifiable assets $ 9,864 $ 9,599 $ 9,372 3 3
Capital spending $ 595 $ 455 $ 638 31 (2)
* Not a meaningful number.
(a) Does not reflect elimination of interest on intercompany borrowing
arrangements and includes income taxes on a separate-company basis.
55
DOMESTIC ELECTRIC OPERATIONS STATISTICS(a)
3-Year
1996 to 1995 Compound
Millions of dollars, except as Percentage Annual
noted/For the year 1996 1995 1994 Comparison Growth
- -----------------------------------------------------------------------------------------------------
Energy Sales (Millions of kWh)
Residential 12,819 12,030 12,127 7% 2%
Commercial 11,497 10,797 10,645 6 4
Industrial 20,332 19,748 20,306 3 1
Other 640 592 623 8 2
----------------------------------------------------------
Retail sales 45,288 43,167 43,701 5 2
----------------------------------------------------------
Wholesale--firm 23,189 13,946 12,418 66 25
Wholesale--nonfirm 6,476 2,430 3,207 * 29
----------------------------------------------------------
Wholesale sales 29,665 16,376 15,625 81 26
----------------------------------------------------------
Total 74,953 59,543 59,326 26 9
----------------------------------------------------------
Number of Retail Customers (Thousands)
Residential 1,194 1,176 1,155 2 2
Commercial 167 162 159 3 3
Industrial 20 20 19 -- 4
Other 4 3 4 33 10
----------------------------------------------------------
Total 1,385 1,361 1,337 2 2
----------------------------------------------------------
Residential Customers
Average annual usage (kWh) 10,815 10,321 10,568 5 --
Average annual revenue
per customer (Dollars) 663 619 631 7 2
Revenue per kWh (Cents) 6.1 6.0 6.0 2 2
Miles of Line
Transmission 14,900 14,900 14,900 -- --
Distribution
--Overhead 45,000 44,900 44,800 -- --
--Underground 9,600 9,100 8,800 5 32
System Peak Demand (Megawatts)
Net system load(b)
--summer 7,257 6,855 7,151 6 3
--winter 7,615 7,030 7,174 8 2
Total firm load
--summer(c) 10,572 8,899 8,830 19 8
--winter 10,775 8,904 8,903 21 7
System Capability (Megawatts)(d)
--summer 12,115 10,224 10,020 18 7
--winter 12,160 10,994 10,391 11 7
* Not a meaningful number.
(a) Unaudited.
(b) Excludes off-system sales.
(c) Includes off-system wholesale sales.
(d) Generating capability and firm purchases at time of firm peak.
56
AUSTRALIAN ELECTRIC OPERATIONS
Millions of dollars, except as noted/For the year 1996 1995
- -------------------------------------------------------------------------------
Powercor Earnings Contribution(a)
Revenues
Residential $ 239.4 $ 10.5
Commercial 165.5 5.9
Industrial 179.3 6.4
Other 44.4 2.6
--------------------
Retail Sales 628.6 25.4
Other 30.2 .5
--------------------
Total 658.8 25.9
--------------------
Operating Expenses
Purchased power 305.1 11.0
Other operations 62.3 2.5
Maintenance 50.0 .3
Administrative and general 40.7 3.4
Depreciation and amortization 71.6 3.1
Taxes other than income taxes 1.7 .1
--------------------
Total 531.4 20.4
--------------------
Income from Operations 127.4 5.5
Interest expense 75.2 3.8
Other expense .4 .5
Income tax expense 19.1 .5
--------------------
Powercor Earnings Contribution(b) $ 32.7 $ .7
--------------------
Hazelwood Earnings Contribution(a) $ (2.6) $ --
--------------------
Identifiable assets $ 2,065 $ 1,751
Capital spending $ 226 $ 1,591
Energy Sales (Millions of kWh)(c)
Residential 2,608 112
Commercial 1,926 66
Industrial 3,282 152
Other 494 32
--------------------
Total 8,310 362
--------------------
(a) Results of operations are included since dates of acquisition, December 12,
1995 for Powercor and September 13, 1996 for Hazelwood.
(b) Allocation of interest expense on incremental corporate debt incurred in
the United States as part of the December 1995 acquisition would have
reduced Powercor's earnings contribution by approximately $28 million after
tax in 1996.
(c) Unaudited.
57
TELECOMMUNICATIONS
3-Year
1996 to 1995 Compound
Percentage Annual
Millions of dollars, except as noted/For the year 1996 1995 1994 Comparison Growth
- ---------------------------------------------------------------------------------------------------------------------------
Revenues
Local network service $ 140.9 $ 120.5 $ 96.9 17% 20%
Network access service 259.1 223.7 168.5 16 12
Cellular 44.0 33.9 23.6 30 40
Other 77.1 68.9 64.0 12 1
Alascom -- 193.1 343.5 * *
-------------------------------------------------------------------------
Total 521.1 640.1 696.5 (19) (9)
-------------------------------------------------------------------------
Expenses
Operations 81.5 78.2 66.7 4 9
Maintenance 91.2 86.0 74.4 6 8
Administrative and general 63.6 53.5 48.0 19 5
Depreciation and amortization 106.5 86.2 66.2 24 15
Taxes other than income taxes 19.6 14.7 13.7 33 15
Alascom -- 156.2 262.8 * *
-------------------------------------------------------------------------
Total 362.4 474.8 531.8 (24) (13)
-------------------------------------------------------------------------
Income from Operations 158.7 165.3 164.7 (4) 4
Interest expense 40.8 42.3 34.8 (4) (3)
Other (income) expense--net (4.9) (63.6) 7.7 92 *
Income tax expense 47.5 47.0 40.8 1 26
-------------------------------------------------------------------------
Net Income(a) 75.3 139.6 81.4 (46) (9)
Minority interest and other .6 36.6 10.9 (98) (57)
-------------------------------------------------------------------------
Earnings Contribution(a) $ 74.7 $ 103.0 $ 70.5 (27) 14
-------------------------------------------------------------------------
Identifiable assets $ 1,592 $ 1,599 $ 1,378 -- 4
Capital spending $ 127 $ 498 $ 153 (75) --
Telephone access lines (Thousands)(b) 559 530 418 5 12
* Not a meaningful number.
(a) Does not reflect the elimination of interest on intercompany borrowing
arrangements.
(b) Unaudited.
58
OTHER OPERATIONS
Other Operations includes the operations of PacifiCorp Financial Services, Inc.
("PFS"), Pacific Generation Company ("PGC") and several start-up-phase ventures,
as well as the activities of Holdings, including financing costs.
3-Year
1996 to 1995 Compound
Percentage Annual
Millions of dollars/For the year 1996 1995 1994 Comparison Growth
- --------------------------------------------------------------------------------------------------------------------------
Revenues $ 153.1 $ 134.8 $ 153.7 14% (8)%
Income from operations 89.2 84.2 38.3 6 27
Depreciation and amortization 8.9 10.2 18.2 (13) (14)
Earnings Contribution
PFS 34.1 30.4 3.0 12 *
PGC 7.8 5.6 8.5 39 6
Tax settlement -- 32.2 -- * *
Holdings and other (13.1) 18.0 6.5 * *
-----------------------------------------------------------------------
Total $ 28.8 $ 86.2 $ 18.0 (67)% 41%
-----------------------------------------------------------------------
Identifiable Assets
PFS $ 708 $ 697 $ 731 2% (14)%
PGC 123 116 113 6 --
Holdings and other 283 253 252 12 4
-----------------------------------------------------------------------
Total $ 1,114 $ 1,066 $ 1,096 5 (9)
-----------------------------------------------------------------------
Capital spending $ 56 $ 175 $ 13 (68)% 8%
----------------------------------------------------------------------
* Not a meaningful number.
(a) Does not reflect elimination of interest on intercompany borrowing
arrangements and includes income taxes on a separate-company basis.
SUPPLEMENTAL INFORMATION
QUARTERLY FINANCIAL DATA (UNAUDITED)
Millions of dollars, except per share amounts/Quarter ended March 31 June 30 September 30 December 31
- ---------------------------------------------------------------------------------------------------------------------------
1996
Revenues $ 1,002.6 $ 976.4 $ 1,134.5 $ 1,180.3
Income from operations 312.3 256.3 338.9 337.6
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 .42 .31 .46 .43
Common dividends paid and declared per share .27 .27 .27 .27
Common stock price per share (NYSE)
High 22 22 1/2 22 3/8 22
Low 20 1/8 19 1/2 19 5/8 19 7/8
1995
Revenues $ 856.5 $ 811.4 $ 854.2 $ 894.8
Income from operations 266.2 219.9 287.2 282.6
Net income 114.8 93.5 169.0(a) 127.7
Earnings on common stock 104.7 83.3 158.9(a) 119.4
Earnings per common share .37 .29 .56(a) .42
Common dividends paid and declared per share .27 .27 .27 .27
Common stock price per share (NYSE)
High 19 3/4 19 7/8 19 1/2 21 5/8
Low 18 18 1/2 17 1/2 18 3/4
(a) The third quarter results of operations for 1995 included a gain of
$37 million or $.13 per share relating to the sale of Alascom.
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.
On March 1, 1997, there were 127,412 common shareholders of record.
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