UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-K
(Mark One)
X ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934 [FEE REQUIRED]
For the fiscal year ended December 31, 1993
OR
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934 [NO FEE REQUIRED]
For the transition period from ............. to ................
Commission file number 1-3198
IDAHO POWER COMPANY
(Exact name of registrant as specified in its charter)
IDAHO 82-0130980
(State or other jurisdiction of (I.R.S. Employer
incorporation or organization) Identification No.)
1221 W. Idaho Street, Boise, Idaho 83702-5627
(Address of principal executive offices)(Zip Code)
Registrant's telephone number, including area code (208)-383-2200
Securities registered pursuant to Section 12(b) of the Act:
Title of each class Name of each exchange on which registered
Common Stock ($2.50 par value) New York and Pacific
Securities registered pursuant to Section 12(g) of the Act:
Preferred Stock
(Title of Class)
Indicate by check mark if disclosure of delinquent filers
pursuant to Item 405 of Regulation S-K is not contained herein,
and will not be contained, to the best of registrant's knowledge,
in definitive proxy or information statements incorporated by
reference in Part III of this Form 10-K or any amendment to this
Form 10-K.
Indicate by check mark whether the registrant (1) has filed all
reports required to be filed by Section 13 or 15(d) of the
Securities Exchange Act of 1934 during the preceding 12 months
(or for such shorter period that the registrant was required to
file such reports), and (2) has been subject to such filing
requirements for the past 90 days.
Yes X No
Aggregate market value of voting stock
held by nonaffiliates (January 31, 1994) $1,096,807,400
Number of shares of common stock outstanding at February 28, 1994
37,318,594
Documents Incorporated by Reference:
Part III, Item 10 Portions of the definitive proxy statement of
Item 11 the Registrant to be filed pursuant to
Item 12 Regulation 14A for the 1994 Annual Meeting of
Item 13 Shareowners to be held on May 4, 1994.
The exhibit index is located on page 98. This document contains
104 pages.
PART I
ITEM 1. BUSINESS
THE COMPANY
General -
Idaho Power Company (Company) is an electric public utility
incorporated under the laws of the state of Idaho in 1989 as
successor to a Maine corporation organized in 1915. The Company
is engaged in the generation, purchase, transmission,
distribution and sale of electric energy in an approximate 20,000-
square-mile area in southern Idaho, eastern Oregon and northern
Nevada, with an estimated population of 670,000 people. The
Company holds franchises in approximately 70 cities in Idaho and
10 cities in Oregon, and holds certificates from the respective
public utility regulatory authorities to serve all or a portion
of 28 counties in Idaho, 3 counties in Oregon and 1 county in
Nevada. The Company's results of operations, like those of
certain other utilities in the Northwest, can be significantly
affected by weather and streamflow conditions. Variations in
energy usage by ultimate customers occur from year to year, from
season to season and from month to month within a season,
primarily as a result of weather conditions. With the recent
implementation of a power cost adjustment mechanism in the Idaho
jurisdiction, which includes a major portion of the operating
expenses with the largest variation potential (net power supply
costs), the Company's future operating results will be more
dependent upon general regulatory, economic, and temperature
conditions and less on precipitation and streamflow conditions.
As of December 31, 1993, the Company supplied electric energy to
317,772 general business customers and employed 1,729 people in
its operations (1,654 full-time).
The Company operates 17 hydro power plants and shares ownership
in three coal-fired generating plants (see Item 2-"Properties").
The Company relies heavily on hydroelectric power for its
generating needs and is one of the nation's few investor-owned
utilities with a predominantly hydro base. The Company has
participated in the development of thermal generation in the
neighboring states of Wyoming, Oregon and Nevada using low-sulfur
coal from Wyoming and Utah.
For the twelve months ended December 31, 1993, total system
electric revenues from residential customers accounted for 34
percent of the Company's total operating revenues. Commercial
and industrial customers with less than 750 KW demand including
street lighting customers accounted for 18 percent, commercial
and industrial customers with 750 KW demand and over accounted
for 18 percent and irrigation customers accounted for 9 percent.
Public utilities and interchange arrangements accounted for 16
percent and other operating revenues accounted for 5 percent.
The Company's principal commercial and industrial revenues are
from sales of electric power to customers involved in elemental
phosphorus production; food processing, preparation and freezing
plants; phosphate fertilizer production; electronics and general
manufacturing facilities; lumber; beet sugar refining; and
electric loads associated with the year-round recreational
business, such as lodges, condominiums, ski lifts and other
related facilities, including those at the Sun Valley resort
area.
The Company has three large long-term special contract customers
in its Idaho retail jurisdiction - the Idaho Engineering
Laboratory (INEL), the J. R. Simplot Company and FMC Corporation
(FMC). The rates charged these customers under their contracts
are subject to the jurisdiction of the Idaho Public Utilities
Commission (IPUC). The Company has contracts to supply up to 45
megawatts of capacity and energy to the INEL in eastern Idaho and
up to 38 megawatts of capacity and energy to the J. R. Simplot
Company for its chemical fertilizer operations plant near
Pocatello, Idaho.
Since 1948, the Company has supplied capacity and energy to FMC
for its elemental phosphorus production plant near Pocatello,
Idaho. Under an agreement effective on January 1, 1974, the
maximum amount of power that FMC may schedule is 250 megawatts.
The agreement is subject to renewal every two years as to one-
fourth of the power deliveries and contains annual minimum
payment guarantees giving consideration to FMC's ability to
decrease its electric demands during periods in which the Company
may request reductions specified in the agreement. Revenues from
FMC were approximately $30.7 million for 1.4 million megawatt-
hours (MWH) of energy supplied during the twelve months ended
December 31, 1993.
Competition -
The electric utility industry in general has become, and is
expected to be, increasingly competitive due to a variety of
regulatory, economic and technological developments. The Energy
Policy Act of 1992 was designed, among other things, to foster
competition in the wholesale electric market (a) through
amendments to the Public Utility Holding Company Act of 1935,
facilitating the ownership and operation of generating facilities
by "exempt wholesale generators" (which may include independent
power producers as well as affiliates of electric utilities) and
(b) through amendments to the Federal Power Act, authorizing the
FERC under certain conditions to order utilities owning
transmission facilities to provide wholesale transmission
services to or for other utilities and other entities generating
electric energy for sale or resale.
With the passage of the Energy Policy Act and the advent of a
more competitive electric utility environment, the Company has
intensified its ongoing strategic planning process. The
Company's goal is to anticipate and fully integrate into its
operations any legislative, regulatory, environmental,
competitive and technological changes. The Company is well
positioned to succeed in a more competitive environment with its
low cost of energy production and its strategic geographic
location which provides excellent opportunities to purchase,
sell, exchange and transmit Northwest energy coupled with
historically providing open access to its transmission system.
With its predominantly hydro base and low-cost thermal plants,
the Company is the lowest cost producer of electric energy in the
nation among investor-owned utilities.
With its interconnections and transmission line capacity
agreements with BPA and other Northwest investor-owned utilities,
the Company has access to all the major electric systems in the
West. These interconnections allowed the Company to generate
$86.5 million in wholesale revenues (16 percent of its total
revenues) in 1993 (see "Power Supply").
Some industrial and large commercial customers have the ability
to own and operate facilities to generate their own electric
energy and if such facilities are qualifying facilities, can
require the displaced electric utility to purchase the output of
such facilities at a state regulatory commission established
"avoided cost" rate (see "Power Supply"). With the Company's
rates for its large (750 kW and over) industrial customers,
excluding special contracts, averaging approximately 2.8 cents
per kilowatt hour (see "Power Supply"), these customers are
converting waste heat to electricity for added revenues and not
displacing the Company's electric service. The Company's rates
for its small (under 750 kW) commercial and industrial customers
average approximately 4.2 cents per kilowatt hour.
The legislatures and/or the regulatory commissions in several
states have considered or are considering "retail wheeling."
Retail wheeling means the movement of electric energy produced by
another entity over an electric utility's transmission and
distribution system, to a retail customer in the utilities
service territory. A requirement to transmit directly to retail
customers would permit retail customers to purchase electric
capacity and energy from the electric utility in whose service
area they are located or from any other electric utility or
independent power producer.
The Idaho Legislature and the IPUC have not yet addressed retail
wheeling. However, the Company believes it is well positioned
with its low-cost energy production to provide energy to retail
customers in other utility service areas if retail wheeling is
adopted by one or more of the Western states (see "Regulation").
Subsidiaries -
The Company has four wholly-owned subsidiary companies: Ida-West
Energy Company (Ida-West), Idaho Energy Resources Co. (IERCo),
Idaho Utility Products Company (IUPCo) and IDACORP, INC.
Ida-West was formed in 1989 to participate through partnership
interests in cogeneration and small power production (CSPP)
projects. Ida-West, through various partnerships, completed
construction in 1993 of the Hazelton B, Wilson Lake and Falls
River Projects as well as acquiring in 1992 an existing operating
facility (South Forks Project). All of the projects are
"qualified facilities" under the Public Utility Regulatory
Policies Act of 1978 (PURPA) with the energy from the facilities
being sold to the Company under IPUC approved firm energy sales
agreements. Power purchased from these facilities amounted to
approximately $6.0 million in 1993.
As part of its Resource Contingency Program, the Bonneville Power
Administration (BPA) requested proposals to provide up to 800
average megawatts of energy options. A partnership including Ida-
West submitted a proposal for a 227-megawatt gas-fired
cogeneration project to be located near Hermiston, Oregon. On
June 4, 1993, BPA selected the partnership's project, together
with two other projects, to participate in the program. The
partnership and BPA have signed an option development agreement
which grants BPA an option to acquire energy from the project at
any time during a five year option hold period after all option
development period tasks, including permitting, have been
completed. If BPA does not elect to begin construction or
decides to cancel the project, a termination payment will be made
to the partnership as defined in the option development
agreement. In addition, the agreement states that BPA will
reimburse the partnership for certain development tasks as
defined in the agreement. The partnership expects these
development period tasks to be completed by year-end 1995.
The Company made an additional investment of $8.0 million in Ida-
West during 1993 bringing its total equity investment to $20
million. Ida-West continues to actively seek or develop new
projects.
IERCo has been in operation since 1974. Its primary purpose is
to participate as a joint venturer in the Bridger Coal Company,
which operates the mine supplying coal to the Jim Bridger plant
near Rock Springs, Wyoming (see "Fuel"). As of December 31,
1993, the Company's total investment in IERCo was $5.2 million.
IUPCo was formed in 1983 to develop and market products to the
utility industry. IDACORP, INC. was organized in 1986 to
commence an exempt non-regulated diversification program. No
material activity occurred in either of these subsidiaries in
1993. As of December 31, 1993, the combined total investment in
these subsidiaries was $3.4 million.
Research and Development -
In 1992, the Company joined Southern California Edison, the U. S.
Department of Energy and others in retrofitting an existing 10-
megawatt solar thermal experimental power plant called Solar Two.
The project will use hundreds of sun-tracking mirrors to collect
the sun's heat and a molten-salt fluid to store and transfer the
heat. The molten-salt, which is environmentally safe, will
retain heat longer and more efficiently than the original oil and
rock heat storage system, allowing the plant to generate
electricity during periods of cloud cover or at night. The
Company will contribute $630,500 over the next three years and
the Electric Power Research Institute (EPRI), of which the
Company is a member, will contribute an additional $630,500 of
matching funds, bringing the Company's credited contribution to
approximately $1.3 million. The project is located near Barstow,
California, and should begin generating electricity in 1995.
Parts of the Company's service territory show a strong potential
for solar power. Research into efficiencies and costs at the
Solar Two power plant will help determine whether the Company can
effectively pursue solar power. This renewable energy resource
could serve a part of the Company's needs through the next
century.
During 1993, the Company spent approximately $2.1 million on
research and development of which $1.8 million was the Company's
membership in EPRI. This matches the 1992 amount. EPRI's
mission is to discover, develop and deliver advances in science
and technology for the benefit of society. Some of the projects
of benefit to the Company include: electrification technologies,
power quality, electric transportation systems, EMF
assessment/risk management and air quality issues.
Energy Efficiency -
The Company continues to promote the efficient use of electrical
energy, recognizing the associated long-term benefits to
customers and the Company. The IPUC and Oregon Public Utility
Commission (OPUC) both emphasize the need for cost-effective
conservation resources as well as the identification of potential
conservation measures which can be utilized in the future. The
Company now has active conservation programs in both Idaho and
Oregon for the efficient use of energy in residential
manufactured homes, commercial, agricultural and industrial
sectors along with a weatherization program operating in
conjunction with an established state program providing energy
conservation measures to eligible low-income families. The
Company plans to apply in 1994 for approval of a program that
will encourage both energy and water use efficiency in the
residential sector by changing to flow efficient showerheads.
The Company supported legislation in Idaho that established
energy-efficient building codes for new home construction and
continues to support the adoption of even more stringent energy
codes by local government jurisdictions. In 1993, the Company
expended $8.0 million on its various energy-efficiency programs
and continues to evaluate programs to encourage the efficient use
of energy.
POWER SUPPLY
The Company is a dual-peaking system, with the larger energy peak
generally occurring in the summer. This complements the winter
peaking utilities which predominate the Pacific Northwest. Even
though its significant hydroelectric generation can operate to
meet demand peaks, seasonal energy requirements are important to
the Company because its seasonal energy capability is determined
in part by the availability of water. Heavy spring precipitation
and cool summer temperatures in the Company's service territory
coupled with near-normal accumulations of snow in the winter
propelled the 1993 water year to more than three times that of
1992. Even though streamflows were much improved, hydro
generation did not fully return to normal levels during 1993.
The major adverse factors were the carryover effects of six years
of drought on reservoirs and ground water supplies and the
inability to fully utilize hydro generation capability during the
first few months of 1993 as the Company restored and then
maintained Brownlee reservoir levels for later use. The 1993
general business (retail) demand for energy nearly reached 1992's
record, reflecting continued growth in the economy of the
Company's service territory. Revenues from sales to other
utilities increased $8.2 million in 1991, decreased $10.6 million
in 1992 but increased $44.5 million in 1993. Revenues from firm
sales to other utilities amounted to $41.5 million in 1991,
$37.5 million in 1992 and $45.4 million in 1993. Revenues from
opportunity sales to other utilities amounted to $11.0 million
for 1991, decreased to $4.5 million in 1992 but increased to
$41.1 million in 1993. For the years 1991 and 1992, the
drought's adverse effect on the Company's hydrogeneration
resulted in reduced sales, while in 1993 the return to more
normal hydro conditions increased dramatically the volume of
sales and revenues. The system peak demand for 1993 was 2,154
megawatts set on February 17, 1993, which was 5.0 percent below
the 1992 peak demand and 7.4 percent below the record demand of
2,327 megawatts set during unusually cold weather on February 7,
1989.
The following table sets forth the total energy sources of the
Company for the last five years:
Total Energy Sources
(000's of MWH)
1993 1992 1991 1990 1989
Generation - net
station output -
Hydro 8,361.7 4,990.3 5,819.2 6,108.8 7,443.6
Coal-fired 6,485.5 7,295.6 5,833.7 5,957.0 6,017.4
Purchased and
interchange 1,273.8 2,102.8 2,583.1 1,936.7 1,496.8
Total 16,121.0 14,388.7 14,236.0 14,002.5 14,957.8
Purchased power expenses were high and fluctuated during the last
three years reflecting necessity purchases from neighboring
utilities during the drought and increased purchases from CSPP
projects during 1993 as a result of improved hydro conditions.
The Company increased utilization of its thermal facilities by
operating at high capacity factors during the drought which
increased fuel expense for 1992 by $21.5 million. In 1993 fuel
expense decreased $8.9 million as a direct result of increased
availability of hydro facilities to meet customer demand.
During 1993, approximately 52 percent of the Company's load
requirements were met with the Company's hydroelectric generating
plants, 40 percent from the thermal generating plants and the
remaining 8 percent was purchased from or exchanged with
neighboring utilities or from CSPP facilities. By comparison,
hydroelectric generation met 35 percent of load requirements in
1992, 41 percent in 1991, 44 percent in 1990 and 50 percent in
1989. In a normal water year this source contributes
approximately 58 percent of the total system requirements.
Although it is too early to predict with certainty what
hydroelectric conditions will be during 1994, preliminary reports
indicate the mountain snowpack is below normal. However, the
carryover reservoir storage is above average throughout the Snake
River Basin. The Company expects to meet projected energy loads
during the coming year by utilizing its hydro and coal-fired
facilities and strategic geographic location - which provides
excellent opportunities to purchase, sell, exchange and transmit
Northwest energy - even if below normal streamflow conditions
prevail.
The Company's generating facilities are interconnected through
its integrated transmission system and are operated on a
coordinated basis to achieve maximum load-carrying capability and
reliability. The transmission system of the Company is directly
interconnected with the transmission systems of the Bonneville
Power Administration, The Washington Water Power Company, the
Pacific Power & Light and Utah Power & Light Divisions of
PacifiCorp, The Montana Power Company and Sierra Pacific Power
Company. Such interconnections, coupled with transmission line
capacity made available under agreements with certain of the
above utilities, permit the advantageous interchange, purchase
and sale of power among the various systems and other electric
systems in the West. The Company is a member of the Intercompany
Pool, the Western Systems Coordinating Council and the Western
Systems Power Pool.
Increasing competitiveness in the electric power marketplace, the
growing mobility of retail customers and the potential for
deregulation of the electric power industry, all indicate a need
for the Company to adjust its resource acquisition policy toward
a greater emphasis on resource marketability. In order to avoid
burdening the Company and its customers with unnecessary future
power supply costs and higher rates, the Company has adopted a
policy of acquiring all new resources as close as possible to the
actual time of need for them, and selecting the lowest cost
resources meeting all of the Company's requirements. In
practice, this policy will result in the purchase of power from
others through the marketplace whenever purchases are the lowest
cost resources, and new investment in resource ownership by the
Company only when a Company-owned resource would be cost
effective on the market.
In September, 1993, the Company submitted to its state regulators
a position paper entitled "Acquisition of Supply-side Resources"
describing its new resource acquisition policy, and is currently
taking several steps toward implementing the policy. First, the
Company filed an application with the IPUC in December, 1993 for
permission to lower the price it must pay for new purchases from
independent qualifying facilities (QFs) under the Public
Utilities Regulatory Policies Act of 1978. The Company believes
that the existing "avoided cost" rates are no longer appropriate,
and that the timing of purchases, and the prices paid to QFs,
should be based more closely on the Company's need for power and
the current market prices of alternative resources. The IPUC is
expected to rule upon the Company's application in 1994.
Secondly, the Company is taking action to avoid new investments
in Company-owned resources unless such new resources are cost
effective compared to alternative market resources, or unless
they are upgrades to existing hydroelectric facilities required
under federal relicensing regulations. The Company expects to
forego upgrades to its Shoshone Falls and Upper Salmon
hydroelectric plants unless they are required as a condition for
relicensing, and anticipates requesting permission to abandon the
proposed A. J. Wiley Project on the Snake River. Refer to the
"Construction Program" for facilities under construction.
New Projects -
During 1991, 1992 and 1993, the Company's new retail customers
increased by 6,008 (or 2.1 percent), 9,759 (or 3.3 percent) and
10,205 (or 3.3 percent) respectively. The Company periodically
updates its load and resource projections and now expects system
energy requirements over the next 20 years to grow at an annual
rate of 1.4 percent.
The Company's current projects are the following: Rebuilding and
expansion of the Swan Falls hydro plant, adding 13 megawatts
(1994); and expansion from 10 to 53 megawatts at the Twin Falls
hydro plant (1995).
Capitalizing on the Company's strategic location between the
Intermountain West and the Pacific Northwest, the Company is
considering the construction and operation of a new transmission
line that could serve as a major artery for regional transfers of
power between north and south. The Southwest Intertie Project
(SWIP) is a proposed 520-mile, 500-Kv transmission line that
would interconnect the Company's system with utilities in the
Southwest. The Bureau of Land Management (BLM) has completed the
Final Environmental Impact Statement/Proposed Plan Amendment
(EIS) for the SWIP. Approval of the EIS from the BLM is expected
during the second quarter of 1994. After approval of the EIS,
the economic feasibility of the line will be validated before the
Company proceeds with construction. The Company has received
preliminary commitments from various utilities and electric
providers for financial participation in the project. The
Company intends to retain up to a 20 percent ownership in the
line.
The following tables show how the Company expects to meet its
forecast energy and peak demand requirements through 1998 from
system generation and contracted resources. Because of its
reliance upon hydroelectric generation, which varies according to
streamflows, the Company's generating system is more energy
constrained than capacity limited. Seasonal exchanges of winter-
for-summer power are included among the contracted resources to
maximize the firm load carrying capability. Exchanges are
currently made with The Montana Power Company under a 10-year
contract signed in 1987 and with Seattle City Light under an
extended contract that expires in 2003.
Summer Peak Capability (MW) (a)
1994 1995 1996 1997 1998
Generating capability 2,635 2,635 2,640 2,640 2,640
Contracts:
Exchange (b) 175 175 175 175 175
Cogeneration and small
power production 113 156 207 211 215
Firm peak load less
interruptible (2,388) (2,424) (2,393) (2,423) (2,455)
Peak capability margin 535 542 629 603 575
Percent 22.4% 22.4% 26.3% 24.9% 23.4%
[FN]
(a) Based upon median hydro conditions.
(b) Net summer-winter exchange.
Annual Energy Capability
(000's of MWH)(a)
1994 1995 1996 1997 1998
Generation capability 15,702 15,614 15,702 15,679 15,766
Contracts:
Cogeneration and
small power
production 654 1,056 1,617 1,637 1,663
Annual firm load (b) (14,976) (15,225) (14,984) (14,747) (14,978)
Energy capability
margin 1,380 1,445 2,335 2,569 2,451
Percent 9.2% 9.5% 15.6% 17.4% 16.4%
[FN]
(a) Forecast based upon average of 65 historical water
conditions.
(b) The growth in retail load is being offset by termination of
some large short-term firm contracts.
During the 1994-1998 period, the Company plans to provide all the
energy required to serve its firm load requirements during
periods of heavy demand, reduced hydrogeneration caused by below
normal streamflow conditions, or unscheduled outages of
generating units by utilizing its hydroelectric and coal-fired
generating units. The Company plans to meet any temporary
resource deficiencies caused by these conditions through short-
term purchases of power from neighboring utilities. For
additional information concerning new resource additions see
"Construction Program."
CSPP Purchases -
As a result of the enactment of the Public Utility Regulatory
Policies Act of 1978 (PURPA) and the adoption of avoided cost
standards by the IPUC, the Company has entered into contracts for
the purchase of energy from private developers. Because the
Company's service territory encompasses substantial irrigation
canal development, forest products production facilities,
mountain streams, and food processing facilities, considerable
amounts of energy are available from these sources. Such energy
comes from hydro power producers who own and operate small plants
and from cogenerators converting waste heat or steam from
industrial processes into electricity. The estimated annualized
cost for the 61 CSPP projects on-line as of December 31, 1993, is
currently $40.6 million. During 1993, the Company purchased
567.6 million kilowatt-hours of power from these private
developers at a blended price of 5.9 cents per kilowatt-hour.
Firm Wholesale Power Sales -
The Company has firm wholesale power sales contracts with Sierra
Pacific Power Company, Portland General Electric Company, The
Montana Power Company, the City of Weiser, Idaho, two entities in
the state of Utah, one in the state of California and one in the
state of Oregon. These contracts are for various amounts of
energy and range from 7 to 100 average megawatts and are of
various lengths that will expire between 1996 and 2009.
Transmission Service -
The BPA sells electricity to certain irrigation districts in
southern Idaho for irrigation pumping and provides wholesale
electric service to certain communities and rural cooperatives in
and adjacent to the Minidoka Irrigation Project in Minidoka and
Cassia Counties, Idaho. In addition, the Company has reciprocal
wheeling agreements with various surrounding utilities. The
Company has an open access philosophy and is experienced in
providing reliable, high quality, economical transmission
service. The transmission system is well maintained and due to
the Company's strategic geographic location is able to offer
transmission service if capacity is available.
FUEL
The Company, through Idaho Energy Resources Co., owns a one-third
interest in the Bridger Coal Company and the Jim Bridger coal
mine that supplies coal to the Jim Bridger generating plant in
Wyoming. The mine, located near the Jim Bridger plant, operates
under a long-term sales agreement providing for delivery of coal
over a 41-year period that began in 1974 (see Item 2 "Prop
erties"). The Bridger Coal Company has sufficient reserves to
provide coal deliveries pursuant to the sales agreement. The
average cost to the Company per ton of coal burned at the Jim
Bridger plant, the largest thermal station on the Company's
system, for the last five years is as follows: 1989 - $20.48;
1990 - $20.68; 1991 - $20.78; 1992 - $20.13 and 1993 - $20.99.
The Company also has a coal supply contract providing for annual
deliveries of coal through 2005 from the Black Butte Coal
Company's Leucite Hills mine adjacent to the Jim Bridger project.
This contract supplements the Bridger Coal Company deliveries and
provides another coal supply to operate the Jim Bridger plant.
The Jim Bridger plant's rail load-in facility and unit coal train
allows the plant to take advantage of potentially lower-cost coal
from outside mines for tonnage requirements above established
contract minimums.
Portland General Electric Company (PGE), with whom the Company is
a 10 percent participant in the ownership and operation of the
Boardman plant, has a flexible contract with a division of AMAX
Coal Company for delivery of low sulfur coal from its mine near
Gillette, Wyoming, to Boardman Unit No. 1. Under this contract,
PGE has the option to purchase 750,000 tons of coal annually
through 1999. This agreement enables PGE and the Company to take
advantage of lower cost spot market coal for some or all of the
Boardman plant's requirements.
Sierra Pacific Power Company (SPPCo), with whom the Company is a
joint (50/50) participant in the ownership and operation of the
North Valmy Steam Electric Generating plant (Valmy plant),
entered into a 22-year coal contract that began in July of 1981
with Southern Utah Fuel Company, a subsidiary of Coastal States
Energy Corporation, for the delivery of 17.5 million tons of low-
sulfur coal from a mine near Salina, Utah, for Valmy Unit No. 1.
With the commercial operation of Valmy Unit No. 2 in May 1985, an
additional coal source was needed to assure an adequate supply
for both units at the Valmy plant. Accordingly, in 1986 the
Company and SPPCo signed a long-term coal supply agreement with
the Black Butte Coal Company. This contract provides for Black
Butte to supply coal to the Valmy project over the next two
decades under a flexible delivery schedule that allows for
variations in the number of tons to be delivered ranging from a
minimum of 200,000 tons per year to a maximum of 1,150,000 tons
per year. This flexibility will accommodate fluctuations in
energy demands, hydroelectric generating conditions and purchases
of energy from CSPP facilities.
WATER RIGHTS
The Company, except as otherwise stated herein, has valid water
rights, unlimited as to time, to the waters used in its
generating stations, which were obtained under applicable
provisions of state law. Such rights, however, are subject to
prior rights and, with respect to license provisions of certain
hydroelectric facilities and water licenses, are subject to
future upstream diversion of water for irrigation and other
consumptive use.
Over time, increased irrigation and other consumptive diversions
on the Snake River have resulted in some reduction in the
streamflows available for the Company's hydroelectric generating
facilities. In this regard, the Company has pursued a course of
action to determine and protect its water rights and their
priority consistent with the settlement agreements negotiated
with the state of Idaho signed on October 25, 1984. In 1987,
Congress passed and the President signed into law House Bill 519
which permitted implementation of the agreements and provided
that the Federal Energy Regulatory Commission would accept the
settlement agreements and that the settlement was consistent with
the terms of hydroelectric licenses and was prudent for the
purpose of determining rates under Section 205 of the Federal
Power Act during the remaining term of certain project licenses
on the Snake River.
The Idaho State Legislature has charged the Idaho Department of
Water Resources with the responsibility of proceeding with the
adjudication of water rights on the Snake River. The
adjudication process commenced in 1987 and has yet to be
completed. The Company does not anticipate any modification of
its water rights in conjunction with the adjudication process.
REGULATION
The Company is not in direct competition with any electric public
utility company or municipality within its service territory.
The Company is under the regulatory jurisdiction (as to rates,
service, accounting and other general matters of utility
operation) of the Federal Energy Regulatory Commission (FERC),
the Idaho Public Utilities Commission, the Public Utility
Commission of Oregon and the Public Service Commission of Nevada.
The Company is also under the regulatory jurisdiction of the
IPUC, OPUC and the Public Service Commission of Wyoming as to the
issuance of securities. The Company is subject to the provisions
of the Federal Power Act as a "licensee" and "public utility" as
therein defined. The Company's retail rates are established
under the jurisdiction of the state regulatory agencies and its
wholesale and transmission rates are regulated by the FERC (see
"Rates"). Pursuant to the requirements of Section 210 of the
PURPA, the state regulatory agencies have each issued orders and
rules regulating the Company's purchase of power from CSPP
facilities.
As a licensee under the Federal Power Act, the Company and its
licensed hydroelectric projects are subject to the provisions of
Part I of the Act. All licenses are subject to conditions set
forth in the Act and regulations of the FERC thereunder,
including, but not limited to, provisions relating to
condemnation of a project upon payment of just compensation,
amortization of project investment from excess project earnings,
possible takeover of a project after expiration of its license
upon payment of net investment, severance damages, and other
matters.
The state of Oregon has a Hydroelectric Act providing for
licensing of hydroelectric projects in that state. The Company's
Brownlee, Oxbow and Hells Canyon facilities are on the Snake
River where it forms the boundary between Idaho and Oregon and
occupy land located in both states. These facilities are
subject, with respect to project property located in Oregon, to
such provisions of the Oregon Hydroelectric Act. The Company has
obtained Oregon licenses for these facilities and these licenses
as are not in conflict with the Federal Power Act or the
Company's FERC license.
ENVIRONMENTAL REGULATION
Environmental controls at the federal, state, regional and local
levels are having a continuing impact on the Company's operations
due to the cost of installation and operation of equipment
required for compliance with such controls.
Based upon the requirements of present environmental laws and
regulations, the Company estimates its capital expenditures
(excluding allowance for funds used during construction) for
environmental matters for 1994 and during the period 1995-1998
will total approximately $1.7 million and $7.4 million,
respectively. However, to the extent regulations under federal
and state environmental protection laws, as well as the laws
themselves, are changed, costs for compliance with such laws and
regulations in connection with the Company's existing facilities
and facilities under construction are subject to change in an
amount not determinable.
Air -
The Company has analyzed the Clean Air Act legislation and its
effects upon the Company and its ratepayers. The Company's coal-
fired plants in Nevada and Oregon already meet the federal
emission rate standards and the Company's coal-fired plant in
Wyoming meets that state's even more stringent regulations. The
Company anticipates no material adverse effect upon its
operations.
Water -
The Company has received National Pollutant Discharge Elimination
System Permits, as required under the Federal Water Pollution
Control Act Amendments of 1972, for the discharge of effluents
from its hydroelectric generating plants.
The state of Oregon Department of Environmental Quality
determined that the flow of water over large dams on the Columbia
and Snake Rivers could result in the supersaturation of the water
with dissolved nitrogen possibly resulting in damage to the fish
population. The Company has obtained a permit from the Oregon
Department of Environmental Quality to operate the Brownlee,
Oxbow and Hells Canyon Dams in accordance with the water quality
program of the state of Oregon.
At the Company's American Falls hydroelectric generating plant,
the Company has agreed to meet certain dissolved oxygen
standards. The Company signed amendments to the agreements
relating to the operation of the American Falls Dam and the
location of water quality monitoring facilities to provide more
accurate and reliable water quality measurements necessary to
maintain water quality standards during the May 15 to October 15
period each year downstream from the Company's plant.
The Company has also installed aeration equipment, water quality
monitors and data processing equipment as part of the Cascade
hydroelectric project to provide accurate water quality data and
increase dissolved oxygen levels as necessary to maintain water
quality standards on the Payette River.
The Company owns and finances the operation of anadromous fish
hatcheries and related facilities to mitigate the effects of its
hydroelectric dams on fish populations. In connection with its
fish facilities, the Company sponsors ongoing programs for the
control of fish disease and improvement of fish production. The
Company's anadromous fish facilities at Hells Canyon, Oxbow,
Rapid River, Pahsimeroi and Niagara Springs continue to be
operated under agreements with the Idaho Department of Fish and
Game. In 1993, the operation of these facilities pursuant to the
FERC License 1971 cost approximately $2.1 million.
Endangered Species -
The Northwest as a region continues to grapple with the problem
of the long-term survival of anadromous fish runs - particularly
salmon - on the Columbia and Lower Snake Rivers. The number of
fish from several species of salmon has been declining over the
last several years, the exact cause or causes of such decline is
not fully known, but over-harvest, federal government dams,
habitat losses and other man-caused impediments appear to be
contributing factors.
In addition to the Snake River sockeye which the federal
government has declared endangered, two other ocean-going salmon
stocks on the Columbia and Lower Snake Rivers have been granted
threatened species listing. The Company is cooperating with all
regional interests in an effort to resolve these issues and again
in 1993 assisted the federal government by operating the
Company's hydroelectric facilities to enhance downstream fish
passage through federal dams. The Company, which over the years
has invested millions of dollars in fish protection, mitigation
and enhancement, undertook this assistance voluntarily. The
Company fully supports and actively participates in the regional
effort to develop a comprehensive and scientifically credible
recovery program for the salmon.
The Snake River Salmon Recovery Team submitted its Draft Recovery
Plan to the National Marine Fisheries Service (NMFS) detailing
its draft recommendations for restoring the listed Snake River
salmon runs. The Company has concluded a review of the 500-page
report and believes it sets forth a course of action that, if
fully implemented, could lead to a successful recovery. The
Draft Plan details comments regarding some institutional changes
and responsibility for management of the recovery efforts. It
suggests reductions in the ocean and in-river harvest rates,
calls for significant improvements in transportation and
collection systems, supports flow augmentation and habitat
improvements, calls for a test drawdown of the federal Lower
Granite Reservoir on the Snake River and suggests habitat,
hatchery and predation improvements. The Company will continue
to closely monitor the finalization of the Recovery Plan which is
expected to be released in 1994.
It is possible the final recovery plan could have a material
impact on the Company, as well as every other person, community
and industry in the Northwest that depends on the Snake and
Columbia Rivers. The Company is hopeful that the anadromous fish
runs can be restored to the level that society demands without
undue hardship on the Company and those who benefit from its
service.
In mid-December 1992, five Snake River mollusks were listed as
endangered and threatened species. This has been a part of all
the Company's discussions regarding relicensing and new hydro
development since that time. The listing specifically mentions
the impact fluctuating water levels related to hydro operations
may have on the snails' habitat. While most of the facilities on
that stretch of the river are run of the river (baseload)
facilities, some do provide peaking capability. There is
uncertainty on exactly what impact, if any, water fluctuations
caused by the facilities have on the snails. The Company intends
to testify to the U. S. Fish and Wildlife Service, the listing
agency, that there is little data in this area and that it
proposes to study these operations. While there is potential the
listing could impact the way the Company operates these
facilities, at this time it is difficult to estimate what impact,
if any, the issue could have on the Company and its operations.
Hazardous/Toxic Wastes and Substances -
Under the Toxic Substances Control Act (TSCA), the Environmental
Protection Agency (EPA) has adopted regulations governing the
use, storage, testing, inspection and disposal of electrical
equipment that contain polychlorinated biphenyls (PCBs). The
regulations permit the continued use and servicing of certain
electrical equipment (including transformers and capacitors) that
contain PCBs. The Company continues to meet all federal
requirements of the TSCA for the continued use of equipment
containing PCBs. The Company has a program to make the 200-plus
substations on its system PCB free. The costs for this disposal
program were $0.9 million, $0.3 million and $0.1 million for
1991, 1992, and 1993 respectively. While the Company's use of
equipment containing PCBs falls well within the federal safety
standards, the Company has voluntarily decided to virtually
eliminate these compounds from the substation sites. This
program will save costs associated with the long-term monitoring
and testing of substation equipment and grounds for PCB
contamination as well as being good for the environment today.
The Comprehensive Environmental Response, Compensation and
Liability Act of 1980 and the Resource Conservation and Recovery
Act of 1976 authorize the EPA to seek a court order compelling
responsible parties to undertake cleanup action at any location
determined to present an imminent and substantial danger to the
public or to the environment because of an actual or threatened
release of one or more hazardous substances. Because of the
nature of the Company's business, various by-products and
substances are produced and/or handled which are classified as
hazardous under one or more of these statutes. The Company
provides for the disposal or recycling of such substances through
licensed independent contractors, but these statutory provisions
also impose potential responsibility for certain clean up costs
on the generators of the wastes. As discussed in Item 3- "Legal
Proceedings," the Company accepted the responsibility to clean up
certain portions of a designated Superfund site.
Electric and Magnetic Fields -
While scientific research has yet to establish any conclusive
link between electric and magnetic fields and human disease, the
possibility of a connection has caused public concern nationally
and internationally. Electric and magnetic fields are found
wherever there is electric current, whether it be in a high-
voltage transmission line or the simplest of household electrical
appliances. Concern over possible health effects already has
prompted regulatory efforts to limit human exposure to electric
and magnetic fields in several areas of the nation. Depending on
what researchers ultimately discover and what regulations may be
deemed necessary, it is an issue that could impact a number of
industries, including electric utilities. At this time, it is
difficult to estimate what impact, if any, the issue could have
on the Company and its operations.
RATES
Idaho Jurisdiction -
In May 1992, the IPUC issued an order which authorized the
Company to put in place for a twelve-month period a drought-
related temporary rate increase of 3.9 percent or $15.0 million
in additional revenues.
On March 29, 1993, the IPUC approved a Power Cost Adjustment
(PCA) mechanism that would enable the Company to collect, or
require it to refund, all or a portion of the difference between
net power supply costs actually incurred and those allowed in the
base rates of the Company. The PCA is intended to avoid the need
for temporary rate increases during low water years and will
return benefits to customers in high water years. Under the
approved PCA, customers' power rates will be adjusted annually to
reflect forecasted changes in the Company's net power supply
costs in the current year and to true-up any deviation between
forecasted and actual costs for the previous year. At the same
time the temporary rate increase initiated in May 1992 ceased in
May 1993, the Company implemented its first PCA rate increase of
$5.0 million, combining for a net decrease of $10.0 million in
rates. For the current year (May 1993 through April 1994) the
PCA will be applied to 60 percent of the deviations from
normalized power costs. Following the IPUC's next formal review
of the Company's general revenue requirements, the PCA will be
raised to recover 90 percent of the variation in power supply
costs. The current balance is adjusted monthly as actual
conditions are compared to the forecasted net power supply costs.
The final cumulative PCA amount as of May 15, 1994 will be
included in the true-up portion of the 1994 PCA.
On January 8, 1993, the IPUC authorized the Company to suspend
five and one-half months (January 1, 1993, through June 15, 1993)
of the revenue deferral associated with the Afton generation
facility for a total of $1,225,707. This allowed the Company to
defer additional 1992 reserve capacity (purchased generation
available to meet load if needed) costs of $1,225,707 against the
suspension of revenue deferral in 1993.
The Company intends to file a general revenue requirements case
in its Idaho retail jurisdiction during 1994. One purpose of the
filing is to bring all of the Company's cost components to a
current level in response to concerns expressed by the IPUC and
various customer groups in recent regulatory proceedings
regarding the length of time since the Company's costs were
reviewed on a comprehensive basis. In these proceedings the
Company indicated that an opportunity for such a review would
occur in the 1993/1994 time frame and full implementation of the
PCA will not occur until such a proceeding is completed. The
amount of any additional revenue requirement to be requested, if
any, has not yet been determined.
Oregon Jurisdiction -
In 1992 the Company received OPUC authority to defer, with
interest, 33.5 percent of Oregon's share of increased power
production costs starting on March 23, 1992, and continuing
through December 31, 1992. The Company subsequently filed a
request and received approval from the OPUC for a 24-month
amortization period of an annual rate increase of $526,360 or
2.57 percent effective July 1, 1993.
In 1993, the Company did not file any applications for general
rate relief in the Oregon retail jurisdiction.
Other Jurisdictions -
The Company also submitted a rate increase request to the FERC to
increase rates to certain wholesale customers to recover
additional 1992 power supply costs incurred due to the drought.
The FERC granted a $547,900 rate increase for a twelve-month
period effective November 10, 1992.
In 1993 the Company did not file any applications for rate relief
in its Nevada retail jurisdiction.
CONSTRUCTION PROGRAM
The Company's construction program for the 1994-1998 period
includes completion of the rebuild of the Swan Falls hydro
facility and expansion of the Twin Falls hydro facility. The
total cash construction program (excluding allowance for funds
used during construction) for the five-year period 1994-1998 is
presently estimated to require cash funds of approximately $580.9
million as follows:
1994 1995-1998(a)
(Millions of Dollars)
Generating Facilities:
Hydro $ 34.7 $ 56.1
Thermal 12.2 59.8
Total generating facilities 46.9 115.9
Transmission lines and substations 13.5 103.1
Distribution lines and substations 37.0 171.8
General 22.1 70.6
Total cash construction 119.5 461.4
AFUDC 3.2 4.4
Total construction including AFUDC (b) $122.7 $465.8
[FN]
(a) Includes construction costs escalated at 3.86%, 3.14%, 2.66%
and 2.90% annually for the years 1995-1998, respectively.
(b) Does not include Ida-West equity investment in construction
which is $0.2 million in 1994 and $0.5 million for the 1995-
1998 period. Ida-West intends to develop a major portion of
its construction as a participant in joint ventures which
are not a part of the consolidated entity.
These estimates are subject to constant revision in light of
changing economic, regulatory and environmental factors and
patterns of conservation.
Construction started in 1991 to rebuild the Swan Falls powerhouse
and increase its generating capacity from 12 megawatts to 25
megawatts. The amended FERC license provides for the retirement
of the present powerhouse and construction of a new powerhouse
containing two generating units of 12.5 megawatts each with
completion scheduled in 1994. In January 1991, the Company
received authority from the IPUC to include the costs of the
rebuild of the Swan Falls hydroelectric facility in the Company's
rate base. The total cash expenditures of the rebuild are
presently estimated at $53.6 million with total construction
costs at $60.0 million including an allowance for funds used
during construction.
In January 1991, the Company received a 50-year license from the
FERC for the Twin Falls Project that approves increasing the
generating capacity from 10 megawatts to 53 megawatts.
Construction started in July 1993 with completion scheduled for
mid-1995. In July 1993, the Company received approval from the
IPUC to rebuild the Twin Falls hydroelectric facility as proposed
in its application. The commitment estimate, including allowance
for funds used during construction, is $50.8 million which
represents the maximum amount the Company recommends be included
in Idaho ratebase. The total cash expenditures of the expansion
are presently estimated at $32.3 million with total construction
costs at $34.2 million including allowance for funds used during
construction.
Remodeling the old general office building began in 1993. The
total cash expenditures for the remodel are presently estimated
at $6.0 million.
As these and other potential projects become more definitive as
to amount, timing and regulation, future construction forecasts
will change accordingly. The Company has no nuclear involvement
and its future construction plans do not include development of
any nuclear generation. The Company is looking at various
options that may be available to meet the future energy
requirements of its customers which include: (1) customer
conservation resulting from incentive programs, (2) efficiency
improvements on the Company's generation, transmission and
distribution systems, (3) additional power purchases from CSPP
facilities, (4) purchased power and exchange agreements with
other utilities and (5) participation in a solar demonstration
project. As additional energy demands are placed upon the
system, the project or projects best meeting the changed
requirements will be pursued.
FINANCING PROGRAM
The Company's five-year financing program primarily is designed
to finance its construction program and to repay maturing long-
term debt. The most recent estimate of capital requirements and
sources of capital for the period is $598.7 million outlined as
follows:
1994 1995-1998
(Millions of Dollars)
Capital Requirements:
Net cash construction expenditures $119.5 $461.4
Conservation expenditures 11.7 28.5
Other cash expenditures (7.2) (15.2)
Total $124.0 $474.7
Sources of Capital:
Internal generation $ 69.6 $384.3
Short-term bank loans - Net 17.9 26.1
First mortgage bonds 25.0 108.0
Common stock 13.0 13.0
Cash investments (increase) (1.5) (56.7)
Total (a) $124.0 $474.7
[FN]
(a) Does not include Ida-West financing.
These estimates are subject to constant review in light of
changing economic, regulatory and environmental factors and
patterns of energy conservation. Any additional securities to be
sold will depend upon market conditions and other factors, but it
is the Company's objective to maintain capitalization ratios of
approximately 45 percent common equity, 8 to 10 percent preferred
stock and the balance long-term debt. The Company will continue
to take advantage of any refinancing opportunities as they become
available.
The Company, in its five-year financial forecast, plans to sell
additional debt securities and to issue common stock. It further
expects that over one-half of its capital requirements will be
met through internal cash generation.
Under the terms of the Indenture relating to the Company's First
Mortgage Bonds, net earnings must be at least two times the
annual interest on all bonds and other equal or senior debt. For
the twelve months ended December 31, 1993, net earnings were 6.27
times. Additional preferred stock may be issued when earnings
for twelve consecutive months within the preceding fifteen months
are at least equal to 1.5 times (until December 31, 2000, at
which time the issuance ratio will increase to 1.75 times) the
aggregate annual interest requirements on all debt securities and
dividend requirements on preferred stock. At December 31, 1993,
the actual preferred dividend earnings coverage was 2.90 times.
If the dividends on the shares of Auction Preferred Stock were to
reach the maximum allowed, the preferred dividend earnings
coverage would be 2.62 times. The Indenture and the Company's
Restated Articles of Incorporation are exhibits to the Form 10-K
and reference is made to them for a full and complete statement
of their provisions.
ITEM 2. PROPERTIES
The Company's system includes 17 hydroelectric generating plants
located in southern Idaho and eastern Oregon (detailed below) and
an interest in three coal-fired steam electric generating plants.
The system also includes approximately 4,654 miles of high
voltage transmission lines; 21 step-up transmission substations
located at power plants; 17 transmission transformer substations;
7 transmission switching stations; and 196 energized distribution
substations (excludes mobile substations and dispatch centers).
Refer to Item 1 - "Construction Program" for facilities under
construction.
The Company holds licenses under the Federal Power Act for 13
hydroelectric projects from the FERC. These and the other
generating stations and their capacities are listed below:
Maximum
Non-Coincident
Operating Nameplate License
Project Capacity KW Capacity KW Expiration
Properties Subject to Federal
Licenses:
Lower Salmon 70,000 60,000 1997
Bliss 80,000 75,000 1998
Upper Salmon 39,000 34,500 1998
Shoshone Falls 12,500 12,500 1999
C J Strike 89,000 82,800 2000
Upper Malad 9,000 8,270 2004
Lower Malad 15,000 13,500 2004
Brownlee-Oxbow-Hells Canyon 1,398,000 1,166,500 2005
Swan Falls 11,100 9,465 2010
American Falls 112,420 92,340 2025
Cascade 14,000 12,420 2031
Twin Falls 10,000 8,437 2041
Milner 59,448 59,448 2038
Other Generating Plants:
Other Hydroelectric 10,400 11,300
Jim Bridger (Coal-Fired 693,333 678,077
Station)
Valmy (Coal-Fired Station) 260,650 260,650
Boardman (Coal-Fired Station) 53,000 53,000
On December 31, 1993, the composite average ages of the principal
parts of the Company's system, based on dollar investment, were:
production plant, 15.9 years; transmission system and
substations, 17.7 years; and distribution lines and substations,
13.9 years. The Company considers its properties to be well
maintained and in good operating condition.
The Company owns in fee all of its principal plants and other
important units of real property, except for portions of certain
projects licensed under the Federal Power Act and reservoirs and
other easements, subject to the lien of its Mortgage and Deed of
Trust and the provisions of its project licenses, and to minor
defects common to properties of such size and character that do
not materially impair the value to, or the use by, the Company of
such properties.
As a result of various federal legislative actions and proposals
(such as the Electric Consumers Protection Act of 1986, Energy
Policy Act of 1992, Clean Water Act Reauthorization and
Endangered Species Act Reauthorization), a major issue facing the
Company is the relicensing of its hydro facilities. Because the
federal licenses for the majority of the Company's hydroelectric
projects expire during the next 10 to 15 years, the Company has
established an internal task force to vigorously pursue the
relicensing process. The relicensing of these projects is not
automatic under federal law. The Company must demonstrate
comprehensive usage of the facilities, that it has been a
conscientious steward of the natural resource entrusted to it and
that there is a strong public interest in the Company continuing
to hold the federal licenses. The Company cannot anticipate what
type of environmental or operational requirements may be placed
on the projects in the relicensing process, nor can it estimate
what the eventual cost will be for relicensing. However, the
Company anticipates that its efforts in this matter for all of
the hydro facilities will be successful.
Idaho Energy Resources Co. owns a one-third interest in certain
coal leases near the Jim Bridger generating plant in Wyoming from
which coal is mined and supplied to the plant.
Ida-West owns a 50 percent interest in five PURPA-qualified
facilities that have a total generating capacity of approximately
34 MW. The energy from these facilities is sold to the Company.
ITEM 3. LEGAL PROCEEDINGS
The Company is a defendant in a Superfund case entitled United
States of America vs. Pacific Hide & Fur Depot, et al., Civil No.
83-4062, pending in the United States District Court for the
District of Idaho. The suit involves PCB contamination at a
scrap metal/recycling facility near Pocatello, Idaho. The
Company entered into a Partial Consent Decree which was signed by
the District Judge on September 26, 1989, wherein the Company
agreed to remediate PCBs at the site.
After completion of certain Initial Tasks and the Final Remedial
Design, by letter dated October 4, 1990, EPA notified the Company
of the discovery of lead and other metals contamination at levels
of concern at the site, and instructed the Company to suspend
further remedial action at the site until further notice.
On April 24, 1991, the Company initiated discussions with EPA in
an effort to facilitate the commencement and completion of PCB
remediation. On July 16, 1991, the Company submitted a proposal
whereby the PCB and lead/other metal contaminants would be
divided into at least two operable units for purposes of site
remediation. On January 20, 1992, a Final Operable Unit Focused
Feasibility Study was submitted by the Company to EPA.
On January 4, 1992, EPA issued a Proposal to Amend Record of
Decision which proposed to divide the site into "operable units"
to allow for immediate cleanup of PCB contamination at the site
through the removal of the PCB and PCB mixed with lead
contaminated soils from the site and disposal of the soils at an
EPA approved waste facility.
An Amended Record of Decision authorizing the foregoing was
issued on April 29, 1992.
Remedial Design Documents were approved by EPA on July 8, 1992.
In order to facilitate the commencement/completion of remedial
activities during 1992, an "interim" Administrative Order
directing the Company to undertake remedial activities was issued
on July 13, 1992.
Remediation activities commenced on July 27, 1992, and were
completed on October 21, 1992.
A Certification of Completion for the Operable Unit Remedial
Action dated March 31, 1993, was issued by EPA to the Company.
The Amended Partial Consent Decree which will supersede EPA's
"Interim" Administrative Order has not yet been completed.
On August 30, 1993, Notice of the Lodging of the Amended consent
Decree was published in the Federal Register, creating a 30-day
period for public comment.
On September 30, 1993, the Company was advised that the public
comment period would be extended until October 21, 1993, at which
time, barring any disclosure of facts or considerations which
indicate that the proposed settlement is inappropriate, improper
or inadequate, the District Court for the District of Idaho
should enter a final judgment in the matter resolving the
government's claims against the Company.
Pursuant to the Request for Public Comment, a number of
Potentially Responsible Parties involved with the lead
contamination at the site filed objections to the proposed
Amended Consent Decree. The objections generally contend that
the government's information relating to the Company's
contribution to the lead contaminations at the site is erroneous,
and that the Company's proposed settlement is disproportionately
low in relation to its liability. On November 19, 1993, the
Company provided the Department of Justice with its responses to
the objections.
The government is continuing to prepare its responsive comments
to the objections. The Company was advised on February 8, 1994,
that the government anticipated the filing of its responsive
summary with the court by the end of February 1994.
This matter has been previously reported in Form 10-K dated
March 9, 1989, March 8, 1990, March 14, 1991, March 16, 1992,
March 12, 1993, and other reports filed with the Commission.
On February 16, 1994, an action for declaratory relief and breach
of contract entitled Idaho Power Company vs. Underwriters at
Lloyds London, et al., was filed by the Company in Federal
District Court in Pocatello, Idaho, against its solvent liability
insurers in the period of 1969 to 1974, arising out of the
insurer's denial of coverage for the Company's environmental
remediation of a hazardous waste site in Pocatello. The action
seeks a declaratory judgment that the policies cover the
Company's costs of defending claims related to the site and of
site remediation, and damages for the insurers' breach of the
insurance contracts based on their failure to pay such costs,
which at the present time are approximating $6.9 million.
On December 6, 1991, a complaint entitled Nez Perce Tribe,
Plaintiff, v. Idaho Power Company, Defendant, Civil No. CIV 91-
0517-S-EJL, was filed against the Company in the United States
District Court for the District of Idaho. The Company was served
with the Complaint on March 26, 1992. In the Complaint, the
Tribe contends that pursuant to treaties with the United States
Government including the Treaty of June 11, 1855, 12 Stat. 957,
and the Treaty of June 9, 1863, 14 Stat. 647, the right to take
fish at all usual and accustomed fishing places outside the Nez
Perce Reservation and the exclusive right to take fish in all
streams running through or bordering the reservation were
reserved for the Tribe in said treaties. The Complaint further
states that the Snake River supported substantial runs of
anadromous fish and that the construction of Brownlee, Oxbow and
Hells Canyon Dams in 1958, 1961 and 1967, respectively, created
total barriers to the migration of the anadromous fish, thereby
destroying the fish runs and violating the reserved fishing
rights stated in the above-described treaties. In the Complaint,
the Tribe seeks actual, incidental and consequential damages in
amounts to be proven at trial together with $150,000,000 in
punitive damages as well as pre- and post-judgment interest and
costs and attorney fees.
On September 11, 1992, the Tribe filed an Amended Complaint in
which it amplified its original Complaint by asserting that
Brownlee, Oxbow and Hells Canyon Dams were "constructed, operated
and maintained in such a manner as to damage plaintiff's rights"
to harvest fish, which rights the Tribe asserts to be "present,
possessory property right(s)". As the basis for its alleged
right to recover damages from the Company, the Tribe asserts that
the Company negligently constructed, operated and maintained
Brownlee, Oxbow and Hells Canyon Dams, that the Company
negligently failed to prevent or mitigate harm to the Tribe, that
the Company intentionally and willfully destroyed, interfered
with, and dispossessed the Tribe of its property rights, and that
the Company improperly exercised dominion over the Tribe's
property, thus depriving the Tribe of its possession. The Tribe
has requested to try its case to a jury. As was true for the
Tribe's original Complaint, the Tribe seeks through its Amended
Complaint to secure actual, incidental, and consequential damages
in amounts to be proven at trial, together with pre and post-
judgment interest, costs and disbursements of the action,
attorney fees and witness fees. The Amended Complaint restates
the Tribe's claim for punitive damages, but omits the prior
reference to a sum certain in favor of requesting punitive
damages in an "amount sufficient to punish the defendant and
deter others".
On September 18, 1992, the Company filed a motion for summary
judgment in the hope of securing dismissal of the Tribe's action.
On January 19, 1993, a federal court hearing was held before a
federal magistrate on the Company's motion for summary judgment.
On July 30, 1993, the magistrate issued a Report and
Recommendation to the District Judge wherein it was recommended
that the Company's motion for summary judgment be granted. The
Tribe filed briefing in which it urged the District Court to
reject the Magistrate's Report and Recommendation, and the
Company responded with a request that the District Court enter
summary judgment in accordance with the Magistrate's opinion.
On November 30, 1993, the District Court entered a second order
of reference, in which the court sent the case back to the
Magistrate for the Magistrate to make additional findings with
respect to the Tribe's contention that it is entitled to
compensation based on physical exclusion from its usual and
accustomed fishing places. The Magistrate ordered the parties to
brief this issue. That briefing was concluded, and oral argument
was held before the Magistrate on February 11, 1994. On February
28, 1994, the Magistrate issued a Second Report and
Recommendation wherein it was recommended that the District Court
deny the Company's motion for summary judgment as to the tribes
claim for damages arising from precluding the tribe access to its
usual and accustomed fishing places and reaffirmed its
recommendation in the original Report and Recommendation to grant
the Company's motion for summary judgment as to all other claims.
The lawsuit is still in the early stages, and the Company is
unable to predict the outcome of this case. However, the Company
believes its actions were lawful and intends to vigorously defend
this suit.
This matter has been previously reported in Form 10-K dated
March 16, 1992, March 12, 1993, and other reports filed with the
Commission.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
None
EXECUTIVE OFFICERS OF THE REGISTRANT
The names, ages and positions of all of the executive officers of
the Company are listed below along with their business experience
during the past five years. Officers are elected annually by the
Board of Directors. There are no family relationships among
these officers, nor any arrangement or understanding between any
officer and any other person pursuant to which the officer was
elected.
Business Experience During Past Five
Name, Age and Position (5) Years
J. W. Marshall, 55 Appointed August 18, 1989.
Chairman of the Board Mr. Marshall was Executive Vice
and Chief Executive President prior to August 18, 1989.
Officer
L. R. Gunnoe, 58 Appointed July 12, 1990.
President and Chief Mr. Gunnoe was Vice President -
Operating Officer Distribution prior to July 12,
1990.
Daniel K. Bowers, 46 Appointed July 10, 1986.
Vice President and
Treasurer
J. LaMont Keen, 41 Appointed November 14, 1991.
Vice President and Mr. Keen was Controller prior to
Chief Financial Officer November 14, 1991.
Douglas H. Jackson, 57 Appointed July 12, 1990.
Vice President - Mr. Jackson was Senior Manager of
Distribution Corporate Services prior to July
12, 1990, and Assistant to the
Chairman and Chief Executive
Officer prior to August 21, 1989.
Paul L. Jauregui, 52 Appointed June 4, 1988.
Vice President -
Human Resources
C. N. Olson, 44 Appointed July 11, 1991. Mr. Olson
Vice President - was Senior Manager - Corporate
Corporate Services Services prior to July 11, 1991,
Senior Manager - Administrative
Services prior to September 1,
1990, Distribution Engineering and
Construction Manager prior to
February 1, 1990, and Division
Electrical Superintendent prior to
May 29, 1989.
J. B. Packwood, 50 Appointed July 13, 1989.
Vice President - Mr. Packwood was Senior Manager -
Power Supply Power Supply, prior to July 13,
1989.
Robert W. Stahman, 49 Appointed July 13, 1989.
Vice President, General Mr. Stahman was General Counsel and
Counsel and Secretary Secretary prior to July 13, 1989.
Harold J. Hochhalter, 58 Appointed January 9, 1992.
Controller and Chief Mr. Hochhalter was Manager of
Accounting Officer Corporate Accounting and Reporting
prior to January 9, 1992.
PART II
ITEM 5. MARKET FOR THE REGISTRANT'S COMMON STOCK AND
RELATED STOCKHOLDER MATTERS
The Company has paid cash dividends on its common stock in each
year since 1918. For the years of 1991, 1992 and 1993, cash
dividends per share of common stock were $1.86. At the July 1993
meeting, the Board of Directors voted to maintain the annual
common dividend at $1.86 per share. It is the intention of the
Board of Directors to continue to pay dividends quarterly on the
common stock, but such dividends in the future will depend on
earnings, cash requirements of the Company and other factors.
The common stock is listed on the New York and Pacific stock
exchange. For the years of 1992 and 1993, the following table
indicates the reported high and low sale price of the Company's
common stock as reported by the Wall Street Journal as composite
tape transactions. The holders of record of the Company's common
stock as of December 31, 1993 was 26,870.
1992 (Quarters)
Common Stock, $2.50 par value: 1st 2nd 3rd 4th
High $28 3/4 $26 3/8 $27 1/4 $28 1/8
Low 24 3/8 24 3/4 25 1/4 25 1/2
Dividends paid per share (cents) 46.5 46.5 46.5 46.5
1993 (Quarters)
Common Stock, $2.50 par value: 1st 2nd 3rd 4th
High $30 3/8 $31 1/2 $33 $32 7/8
Low 27 1/4 27 7/8 31 29 1/8
Dividends paid per share (cents) 46.5 46.5 46.5 46.5
<TABLE>
<CAPTION> ITEM 6. SELECTED FINANCIAL DATA
SUMMARY OF OPERATIONS (000 1993 1992 1991 1990
omitted)
<S> <C> <C> <C> <C> <C> <C> <C> <C>
Revenues:
General business $428,658 $431,818 $409,454 $401,350
Sales to other utilities 86,525 42,000 52,563 44,368
Other revenues 25,219 24,274 21,176 19,217
Total revenues 540,402 498,092 483,193 464,935
Expenses:
Purchased power 45,361 58,496 51,210 43,923
Fuel expense 87,855 96,710 75,161 77,606
Other operation and 164,388 137,547 151,593 134,126
maintenance
Depreciation 58,724 59,823 57,597 55,114
Taxes other than income taxes 22,129 20,562 21,168 20,752
Total expenses 378,457 373,138 356,729 331,521
Income from operations 161,945 124,954 126,464 133,414
Other income and deductions - (12,984) (11,133) (9,453) (11,666)
Net
Interest charges - Net 53,991 52,935 56,901 52,605
Income taxes 36,474 23,162 21,144 23,234
Cumulative effect of accruing
unbilled revenues - - - -
Net income 84,464 59,990 57,872 69,241
Dividends on preferred stocks 6,009 5,516 4,904 4,279
Earnings on common stock 78,455 54,474 52,968 64,962
Dividends on common stock 67,959 65,043 63,197 63,197
Net change to retained earnings $ 10,496 $(10,569) $(10,229) $ 1,765
CAPITALIZATION (000 omitted) % % % %
First mortgage bonds $490,000} 47 $485,000} 49 $435,000} 48 $367,500} 46
Other long-term debt 203,780 216,948 194,981 194,159
Mandatory redeemable preferred
stock -} 9 -} 7 -} 8 -} 5
Preferred stock 132,751 107,874 108,191 58,761
Common stock (incl. prem. &
exp.) 439,467} 44 412,998} 44 356,824} 44 358,078} 49
Retained earnings 222,900 212,404 222,973 233,241
Total capitalization $1,488,898 100 $1,435,224 100 $1,317,969 100 $1,211,739 100
Short-term borrowings
outstanding $4,000 $6,000 $48,500 $48,280
</TABLE>
<TABLE>
<CAPTION>
SUMMARY OF OPERATIONS (000 1989 1988 1987 1986
omitted) (Cont'd)
<S> <C> <C> <C> <C> <C> <C> <C> <C>
Revenues:
General business $397,974 $362,050 $343,899 $336,480
Sales to other utilities 70,749 32,175 35,447 54,987
Other revenues 27,438 18,096 15,251 17,394
Total revenues 496,161 412,321 394,597 408,861
Expenses:
Purchased power 43,845 43,723 30,234 31,849
Fuel expense 77,127 74,528 65,934 31,260
Other operation and maintenance 132,114 116,230 114,235 114,407
Depreciation 53,092 51,691 50,929 49,308
Taxes other than income taxes 20,213 19,301 19,072 18,539
Total expenses 326,391 305,473 280,404 245,363
Income from operations 169,770 106,848 114,193 163,498
Other income and deductions -
Net (10,005) (6,552) (13,115) (17,064)
Interest charges - Net 52,997 50,762 51,843 51,206
Income taxes 42,041 13,558 27,246 50,923
Cumulative effect of accruing
unbilled revenues - - (11,302) -
Net income 84,737 49,080 59,521 78,433
Dividends on preferred stocks 4,285 4,293 4,298 10,553
Earnings on common stock 80,452 44,787 55,223 67,880
Dividends on common stock 62,177 61,159 61,159 59,755
Net change to retained earnings $ 18,275 $(16,372) $ (5,936) $ 8,125
CAPITALIZATION (000 omitted) % % % %
First mortgage bonds $377,000} 47 $392,000} 47 $407,000} 47 $432,000} 47
Other long-term debt 165,551 164,426 160,003 153,887
Mandatory redeemable preferred
stock -} 5 -} 5 -} 5 -} 5
Preferred stock 58,923 59,126 59,238 59,403
Common stock (incl. prem. &
exp.) 357,986} 48 357,866} 48 357,797} 48 357,708} 48
Retained earnings 231,476 213,201 229,573 235,509
Total capitalization $1,190,936 100 $1,186,619 100 $1,213,611 100 $1,238,507 100
Short-term borrowings
outstanding $31,000 $37,000 $4,000 $5,000
</TABLE>
<TABLE>
<CAPTION>
SUMMARY OF OPERATIONS (000 1985 1984 1983
omitted) (Cont'd)
<S> <C> <C> <C> <C> <C> <C>
Revenues:
General business $336,705 $324,701 $289,905
Sales to other utilities 98,980 86,724 67,358
Other revenues 15,495 16,422 18,881
Total revenues 451,180 427,847 376,144
Expenses:
Purchased power 16,188 1,215 (6,788)
Fuel expense 81,961 50,850 44,283
Other operation and 125,728 119,604 109,392
maintenance
Depreciation 45,595 40,974 39,038
Taxes other than income taxes 16,790 16,363 15,119
Total expenses 286,262 229,006 201,044
Income from operations 164,918 198,841 175,100
Other income and deductions -
Net (20,352) (11,191) (20,174)
Interest charges - Net 47,891 45,579 45,591
Income taxes 52,556 64,418 61,602
Cumulative effect of accruing
unbilled revenues - - -
Net income 84,823 100,035 88,081
Dividends on preferred stocks 12,447 13,617 15,917
Earnings on common stock 72,376 86,418 72,164
Dividends on common stock 56,277 52,221 47,691
Net change to retained earnings $ 16,099 $ 34,197 $ 24,473
CAPITALIZATION (000 omitted) % % %
First mortgage bonds $467,000} 47 $467,000} 47 $467,000} 47
Other long-term debt 149,074 138,452 112,046
Mandatory redeemable preferred
stock 63,000} 9 63,000} 10 88,000} 12
Preferred stock 60,585 61,079 61,500
Common stock (incl. prem. &
exp.) 355,007} 44 342,038} 43 329,776} 41
Retained earnings 230,558 214,459 183,562
Total capitalization $1,325,224 100 $1,286,028 100 $1,241,884 100
Short-term borrowings
outstanding $ - $ - $ -
</TABLE>
<TABLE>
<CAPTION>
FINANCIAL STATISTICS 1993 1992 1991 1990
<S> <C> <C> <C> <C>
Income from operations as a
percent of total revenues 30.0% 25.1% 26.2% 28.7%
Times interest charges earned:
Before tax 3.14 2.50 2.34 2.72
After tax 2.50 2.08 1.98 2.29
Market-to-book ratio 170% 159% 168% 148%
Payout ratio 87% 120% 119% 97%
Return on year-end common
equity 11.84% 8.71% 9.14% 10.99%
Common stock data:
Earnings per average share
outstanding $2.14 $1.55 $1.56 $1.91
Dividends declared per share $1.86 $1.86 $1.86 $1.86
Book value per share $17.86 $17.28 $17.07 $17.40
Average shares outstanding
(000 omitted) 36,675 35,116 33,977 33,977
Common shareowners 26,870 27,834 28,069 29,080
CUSTOMER DATA
General business data:
Energy sales - kwh
(000,000 omitted) 11,406 11,606 11,266 11,086
Number of customers 317,772 307,567 297,808 291,800
Residential customer data:
Number of customers 263,682 255,022 246,689 241,790
Average kwh use per customer 14,587 13,856 14,845 14,281
Average rate per kwh (cents) 4.82 4.80 4.72 4.73
OTHER STATISTICS
Total assets (000 omitted) $2,097,417 $1,862,307 $1,773,674 $1,680,110
Gross plant additions
(000 omitted) $116,972 $118,920 $135,904 $80,117
Number of employees (full-time) 1,654 1,638 1,626 1,574
</TABLE>
<TABLE>
<CAPTION>
FINANCIAL STATISTICS (Cont'd) 1989 1988 1987 1986
<S> <C> <C> <C> <C>
Income from operations as a
percent of total revenues 34.2% 25.9% 28.9% 40.0%
Times interest charges earned:
Before tax 3.30 2.18 2.76* 3.40
After tax 2.53 1.93 2.10* 2.46
Market-to-book ratio 169% 138% 127% 150%
Payout ratio 77% 137% 111% 88%
Return on year-end common
equity 13.65% 7.84% 9.40% 11.44%
Common stock data:
Earnings per average share
outstanding $2.37 $1.32 $1.63* $2.00
Dividends declared per share $1.83 $1.80 $1.80 $1.76
Book value per share $17.35 $16.81 $17.29 $17.46
Average shares outstanding
000 omitted) 33,977 33,977 33,977 33,961
Common shareowners 30,291 32,225 33,733 34,456
<FN>
* Includes cumulative effect of
accounting change
CUSTOMER DATA
General business data:
Energy sales - kwh
(000,000 omitted) 11,069 10,563 10,175 9,938
Number of customers 284,363 279,529 276,249 274,129
Residential customer data:
Number of customers 236,008 232,650 230,486 228,921
Average kwh use per customer 14,923 14,364 13,785 14,541
Average rate per kwh (cents) 4.69 4.47 4.34 4.21
OTHER STATISTICS
Total assets (000 omitted) $1,625,120 $1,608,935 $1,602,311 $1,621,887
Gross plant additions (000
omitted) $62,094 $64,358 $38,929 $50,257
Number of employees (full-time) 1,528 1,500 1,521 1,524
</TABLE>
<TABLE>
<CAPTION>
FINANCIAL STATISTICS (Cont'd) 1985 1984 1983
<S> <C> <C> <C>
Income from operations as a
percent of total revenues 36.6% 46.5% 46.6%
Times interest charges earned:
Before tax 3.61 4.12 4.00
After tax 2.61 2.90 2.77
Market-to-book ratio 133% 114% 106%
Payout ratio 78% 60% 66%
Return on year-end common
equity 12.36% 15.53% 14.06%
Common stock data:
Earnings per average share
outstanding $2.16 $2.63 $2.25
Dividends declared per share $1.68 $1.59 $1.49
Book value per share $17.29 $16.74 $15.77
Average shares outstanding
(000 omitted) 33,544 32,893 32,070
Common shareowners 35,959 35,216 35,967
CUSTOMER DATA
General business data:
Energy sales - kwh
(000,000 omitted) 10,366 10,191 9,599
Number of customers 272,155 268,974 265,197
Residential customer data:
Number of customers 227,562 225,319 222,625
Average kwh use per customer 15,432 15,342 14,066
Average rate per kwh (cents) 3.98 4.01 3.69
OTHER STATISTICS
Total assets (000 omitted) $1,646,847 $1,584,874 $1,518,011
Gross plant additions
(000 omitted) $74,064 $99,028 $102,970
Number of employees (full-time) 1,568 1,725 1,705
</TABLE>
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Idaho Power Company's consolidated, wholly-owned subsidiaries
consist of Idaho Energy Resources Co. (IERCO), Ida-West Energy
Company (Ida-West), IDACORP, INC, and Idaho Utility Products
Company (IUPCO). Together, Idaho Power and these subsidiaries
are referred to herein as the Company.
EARNINGS PER SHARE
Earnings per share of common stock increased to $2.14 in 1993 as
compared to $1.55 in 1992 and $1.56 in 1991. The lower earnings
per share in 1991 and 1992 resulted from drought conditions and
accompanying low streamflows. The improved 1993 earnings reflect
more favorable hydroelectric conditions and a gain on the sale of
the Wood River turbine to offset the impact of the 1993 federal
income tax increase. The Company also recorded income tax
reserve adjustments relating to the settlement of prior years'
returns (1983-1990) during the fourth quarter. The two actions
combined to increase the year's earnings approximately $6.0
million over 1992. The 1993 earnings equate to an 11.8 percent
earned return on year-end common equity compared to the 8.7
percent earned in 1992 and 9.1 percent earned in 1991. Book
value per share of common stock was $17.86 at December 31, 1993.
RESULTS OF OPERATIONS
Precipitation and Streamflows
Heavy spring precipitation and cool summer temperatures in the
Company's service territory coupled with near normal
accumulations of snow last winter propelled the 1993 water year
to more than three times that of 1992. Streamflows into Brownlee
Reservoir (which provides water to the three dam Hells Canyon
complex which generates about half of the electricity produced by
the Company in a normal water year) were 5.97 million acre-feet
(MAF) compared to only 1.8 MAF during 1992. Inflows into
Brownlee during 1993 were nearly 25 percent above the 63-year
median of 4.81 MAF.
Energy Requirements
Even though streamflows were much improved, hydro generation did
not fully return to normal levels during 1993. The major adverse
factors were the carryover effects of six years of drought
conditions on reservoirs and the aquifer and the inability to
fully utilize hydro generation capability during the first few
months of 1993, as the Company was restoring and then maintaining
Brownlee reservoir levels for later use. The Company's
hydroelectric output accounted for 52 percent of its total energy
requirements in 1993, a substantial increase from 35 percent in
1992 and 41 percent in 1991. Thermal generation accounted for 40
percent of total energy requirements with purchased power and
other exchanges accounting for 8 percent during 1993. Under
normal conditions the Company's hydro system would contribute
approximately 58 percent with thermal generation providing
approximately 36 percent and the remaining 6 percent from
purchased power and other interchanges.
Although it is too early to predict with certainty what
hydroelectric conditions will be during 1994, preliminary reports
indicate the mountain snowpack is again below normal. However,
carryover reservoir storage is above average throughout the Snake
River Basin. The Company expects to meet projected energy loads
during the coming year by utilizing its hydro and coal-fired
facilities and strategic geographic location - which provides
excellent opportunities to purchase, sell, exchange and transmit
Northwest energy - even if below normal streamflow conditions
prevail.
Economy
For the fifth year the state of Idaho and the Company's service
territory continued to experience extraordinary economic growth.
For the state, nonagricultural employment gains of an expected
3.0 percent in 1993 were preceded by 4.6 percent in 1992 and 3.3
percent in 1991. The Company's service area exceeded state-wide
results with expected gains in non-agricultural employment of
nearly 4.0 percent in 1993 with 5.3 percent and 5.4 percent in
1992 and 1991.
Population growth in the Company's service area remains strong.
Residential customer growth increased by 2.0 percent in 1991, 3.4
percent in 1992 and 3.4 percent in 1993. New households in the
service area are forecasted to grow at a 3 percent annual average
rate during the next five years with population growth estimated
to exceed 2.2 percent per year over the same period.
Power Cost Adjustment
In 1992, the Company asked the Idaho Public Utilities Commission
(IPUC) to adopt a Power Cost Adjustment (PCA) mechanism that
would enable the Company to collect, or require it to refund, all
or a portion of the difference between net power supply costs
actually incurred and those allowed in the base rates of the
Company. The PCA is intended to avoid the need for temporary
rate increases during low water years and will return benefits to
customers in high water years. For the current year (May 1993
through April 1994) the PCA will be applied to 60 percent of the
power cost deviations from normalized rates. After the Company's
next general revenue requirement case is completed, the PCA will
be raised to 90 percent of power supply costs.
On March 29, 1993, the IPUC approved a PCA mechanism in
substantially the form proposed by the Company. Under the
approved PCA, customers' power rates will be adjusted annually to
reflect forecasted changes in the Company's net power supply
costs in the current year and to true-up any deviation between
forecasted and actual costs for the previous year.
In May 1993, the Company implemented its first PCA rate increase
of $5.0 million. The current balance is adjusted monthly as
actual conditions are compared to the forecasted net power supply
costs. The final cumulative PCA amount as of May 15, 1994 will
be included in the true-up portion of the 1994 PCA.
Revenue
For the three-year period 1991, 1992, and 1993, an average of 87
percent of the Company's operating revenues were derived from
electric sales in Idaho, 5 percent in Oregon, less than 1 percent
in Nevada and 8 percent from the wholesale market. For the same
three year period, residential customers averaged 34 percent of
the Company's total operating revenues. Commercial and
industrial customers with less than 750 Kw demand combined with
irrigation and street lighting customers averaged 30 percent and
commercial and industrial customers with 750 Kw demand and over
averaged 19 percent. Sales to other utilities and interchange
arrangements averaged 12 percent, and miscellaneous revenues
averaged 5 percent.
Energy sales to the Company's general business customers
increased 1.6 percent in 1991, 3.0 percent in 1992 but decreased
1.7 percent in 1993. These increases reflect the strong economic
growth in the Company's service territory and varied temperature,
precipitation and energy usage patterns. The decrease for 1993
resulted from a wet spring which reduced irrigation sales by 28.8
percent and temporary changes in operations at two of the
Company's large industrial customers which lowered consumption
during 1993. FMC Corporation's (FMC) elemental phosphorus
production plant reduced operations at times during 1993 due to
market conditions for the sale of its manufactured product. FMC
also intends to maintain this reduced production level for a
portion of 1994. The Idaho National Engineering Laboratory's
(INEL) 1993 electrical use was down and can be volatile due to
federal regulatory mandates and maintenance schedules. The INEL
estimates a steady growth in the amount of consumption during
1994 and beyond.
General business revenues constitute approximately 84 percent of
total operating revenues and were $409.5 million in 1991, $431.8
million in 1992 and $428.7 million in 1993. The increase in 1992
reflects an increase in irrigation revenues due to the drought
and an increase in the number of customers served along with the
temporary rate relief granted by the IPUC in May 1992. The
decrease in 1993 results from the 27.9 percent decrease in
irrigation revenue due to the wet spring which was partially
offset by increases in residential revenues (9.3 percent) and
small commercial revenues (4.0 percent). The number of general
business customers served increased by 8.9 percent (or 25,972
customers) during the three year period. Energy usage per
residential customer was 14,845 Kwh in 1991 versus 13,856 Kwh in
1992 and 14,587 Kwh in 1993.
Total operating revenues increased $18.3 million or 3.9 percent
in 1991, $14.9 million or 3.1 percent in 1992, and $42.3 million
or 8.5 percent in 1993. The increase for 1992 was due in part to
the temporary rate relief granted by the IPUC in May 1992, along
with an increase in customers served, while the increase for 1993
was due to increased opportunity sales to other utilities
resulting from improved hydroelectric conditions and an increase
in the number of general business customers.
Regulatory Action
Drought-Related Temporary Rate Increases
In response to drought conditions which reduced streamflows and
increased power supply costs, the Company requested temporary
rate relief several times during the three year period. In May
1992, the IPUC issued an order which authorized the Company to
put in place for a twelve-month period a temporary rate increase
of 3.9 percent or $15.0 million in additional revenues. At the
same time the temporary rate increase ceased in May 1993, the
Company implemented its first PCA rate increase of $5.0 million,
combining for a net decrease of $10.0 million in rates.
In 1992 the Company received Oregon Public Utility Commission
(OPUC) authority to defer with interest 33.5 percent of Oregon's
share of increased power production costs starting on March 23,
1992 and continuing through December 31, 1992. The Company
subsequently filed a request and received approval from the OPUC
for a 24 month amortization period of an annual rate increase of
$526,360 or 2.57 percent effective July 1, 1993.
The Company also submitted a rate increase request to the Federal
Energy Regulatory Commission (FERC) to increase rates to certain
wholesale customers. The FERC granted a $547,900 rate increase
for a twelve-month period effective November 10, 1992.
On January 8, 1993, the IPUC authorized the Company to suspend
five and one-half months (January 1, 1993, through June 15, 1993)
of the revenue deferral associated with the Afton generation
facility for a total of $1,225,707. This allowed the Company to
defer additional 1992 reserve capacity (purchased generation
available to meet load if needed) costs of $1,225,707 against the
suspension of revenue deferral in 1993.
General Revenue Requirement Case
The Company intends to file a general revenue requirements case
in its Idaho retail jurisdiction during 1994 and may also file in
its Oregon retail jurisdiction. The purpose of the filing is to
bring all of the Company's cost components to a current level in
response to concerns expressed by the IPUC and various customer
groups in recent regulatory proceedings regarding the length of
time since the Company's costs were reviewed on a composite
basis. In these proceedings the Company indicated that an
opportunity for such a review would occur in the 1993/1994 time
frame and full implementation of the PCA will not occur until
such a proceeding is completed. The amount of any additional
revenue requirement to be requested has not yet been determined.
When a case is filed the Company's allowed return on common
equity will, among other things, be subject to review. Recent
allowed returns on equity granted nationally have declined as a
result of the current low interest rate environment. Low allowed
returns on equity are a concern because they have created a
contrast with dividend payout levels set during periods of higher
interest rates for some utilities. The Company will seek an
allowed return on equity above its present dividend yield on year-
end book value sufficient to provide current earnings to cover
dividend payments, but cannot predict the final outcome of such
rate proceedings in the current low interest rate environment.
Off-System Sales
Revenues from sales to other utilities increased $8.2 million in
1991, decreased $10.6 million in 1992 but increased $44.5 million
in 1993. These deliveries are comprised of firm sales, which are
long-term contractual arrangements, and opportunity sales which
are made on a when available basis. The volume and price of
these sales depend on the Company's firm energy demand,
hydrogeneration conditions in the Company's service area, and
market conditions throughout the West. Revenues from firm sales
to other utilities amounted to $41.5 million in 1991, $37.5
million in 1992 and $45.4 million in 1993. The decrease for 1992
was due to the termination at the end of 1991 of a short-term
firm sales agreement and a reduction in the amount of energy
taken by another customer pursuant to contract agreements.
Revenues from opportunity sales to other utilities amounted to
$11.0 million for 1991, decreased to $4.5 million in 1992 but
increased to $41.1 million in 1993. For the years 1991 and 1992,
the drought's adverse effect on the Company's hydrogeneration
resulted in reduced sales, while in 1993 the return to more
normal hydro conditions increased dramatically the volume of
sales and revenue.
Expenses
Total operating expenses increased $25.2 million in 1991, $16.4
million in 1992 and $5.3 million in 1993. The increases for 1991
and 1992 reflect the drought conditions which increased reliance
on thermal generation and purchased power. The increase in
operating expenses for 1993 reflects the deferral of certain net
power supply costs to 1993 from 1992 to better match drought
related expenses with surcharge revenues. Maintenance expense
for 1993 increased reflecting more normal operating conditions.
Purchased power expenses were high and fluctuated during the last
three years reflecting necessity purchases from neighboring
utilities during the drought periods and increased purchases from
cogeneration and small power production (CSPP) projects during
1993 as a result of the improved hydro conditions. The estimated
annualized cost for the 61 CSPP projects on-line as of December
31, 1993, is currently $40.6 million. The Company increased
utilization of its thermal facilities by operating at high
capacity factors during the drought which increased fuel expense
for 1992 by $21.5 million. In 1993 fuel expense decreased $8.9
million as a direct result of increased availability of hydro
facilities to meet customer demand.
All other operation and maintenance expenses increased $30.3
million over the same three year period. These increases were
due, in part, to an increase in payroll and benefits ($10.1
million and 80 new employees), an increase in maintenance expense
($7.2 million) due to a return to more normal operating
conditions and an increase in thermal operations ($6.0 million).
Depreciation expense increased for the three year period by $3.6
million or 6.6 percent due to a greater plant investment base.
Taxes other than income taxes increased $1.4 million or 6.6
percent due to increased property taxes and taxes on increased
generation and sale of hydro power.
Interest Charges
Interest charges on long-term debt fluctuated during the three-
year period, ultimately increasing by $2.7 million reflecting the
maturity, early redemption, and issuance of several series of
first mortgage bonds. The Company took advantage of the
declining interest rate environment and refinanced several higher
cost bond issues. These refinancings reduced the overall cost of
debt and annual interest expense which largely offset the cost of
additional financing (see Note 6 of Notes to Consolidated
Financial Statement). Interest on short-term debt fluctuated due
to varying interest rates on short-term debt during the period
and changes in the level of short-term debt borrowings (see Notes
7 of Notes to Consolidated Financial Statement). The Company
purchased Prairie Power Cooperative's (PPC) assets on July 24,
1992 and under the terms of the acquisition agreement with PPC,
assumed the Cooperative's long-term debt (REA notes) of
approximately $1,914,000.
Income Taxes
In August 1993, Congress enacted the "Omnibus Budget
Reconciliation Act of 1993" which, among other things, changed
the statutory corporate federal income tax rate from 34 percent
to 35 percent retroactive to January 1, 1993. Accordingly, taxes
on current income were computed at the new higher rate. The
Company requested and received from the IPUC permission to offset
these higher taxes against a portion of the gain from the
disposition of the Wood River Turbine recorded in 1993. The
actual rates charged for electric service will not change due to
the tax increase until the next general revenue requirement case
is finalized. Also during 1993, the Company settled federal tax
liabilities on the 1987 through 1990 tax years except for
immaterial amounts that relate to a partnership.
Ida-West
Ida-West Energy Company (Ida-West), a wholly owned subsidiary of
the Company, through various partnerships, has completed
construction of the Hazelton B Project, the Wilson Lake Project
and the Falls River Project. Third parties unaffiliated with Ida-
West own 50 percent of each of these projects and the South Forks
Project (which an Ida-West subsidiary and its partner acquired as
an operating project in March 1992), thus satisfying "qualifying
facility" status under PURPA guidelines. These partnerships have
obtained project financing (non-recourse to the Company) having
recently procured the initial permanent financing for the
Hazelton B and Wilson Lake Projects from a single institutional
investor and for the Falls River Project from a commercial
lending institution.
Construction of both the Hazelton B and Wilson Lake Projects
started in July 1991, and commenced commercial operation in May
1993. Construction of the Falls River Project began in August
1991, and started commercial operation in August 1993.
As a result of a construction-related incident involving the
Falls River Project in 1992, the cost to complete the project
increased from $15 million to $28.1 million, net after recovery
of $2.56 million from insurance carriers. To help defray a
portion of these additional costs, the project entity obtained an
increase in project financing from $11.5 million to $18 million.
On June 16, 1993, the FERC issued a notice proposing civil
penalties of no more than $500,000 for alleged license and FERC
regulation violations in connection with the construction of the
Falls River Project. The project entity is currently negotiating
with the FERC for a reduction of these penalties and has recorded
a portion of them as a liability.
On August 13, 1993, the state of Idaho appealed to the Ninth
Circuit the FERC's June 16 denial of the state's request for
rehearing of the FERC's January 13 order allowing resumption of
construction. On November 24, 1993, the project entity reached a
settlement with the state. Under the settlement, the project
entity paid the state $150,000 for deposit into a fund to be used
for studies and mitigation activities in the project vicinity,
and the state dropped the appeal and released the project entity
from any further liability arising out of past construction
incidents.
As part of its Resource Contingency Program, the Bonneville Power
Administration (BPA) requested proposals to provide up to 800
average megawatts of energy options. Ida-West along with two
partners submitted a proposal for a 227 megawatt gas-fired
cogeneration project to be located near Hermiston, Oregon, which
was one of ten projects being given final consideration by BPA.
On June 4, 1993, BPA selected the partnership's project, together
with two other projects, to participate in the program. The
partnership and BPA have signed an option development agreement
which grants BPA an option to acquire energy from the project at
any time during a five year option hold period after all option
development period tasks, including permitting, have been
completed. The partnership expects these development period
tasks to be completed by year-end 1995.
The Company made an additional investment of $8.0 million in Ida-
West during 1993 bringing its total equity investment to $20
million. Ida-West continues to actively seek or develop new
projects.
LIQUIDITY AND CAPITAL RESOURCES
Cash Flow
Net cash generation from operations for the three-year period
amounted to $365.4 million. After deductions for both common and
preferred dividends ($212.3 million), net cash generation from
operating activities provided approximately $153.1 million for
the Company's construction program and other capital
requirements.
Internal cash generation after dividends provided 33 percent of
the total capital requirements in 1991, 30 percent in 1992, 54
percent in 1993, and is projected to provide approximately 53
percent in 1994 and 73 percent during the five-year period 1994-
1998. The Company expects to continue financing its construction
program using both internally generated funds, and to the extent
required, externally financed capital. Drought conditions have
negatively impacted the Company's internal cash generation in two
of the last three years. In its 1994-1998 five-year forecast the
Company anticipates issuing additional common stock and first
mortgage bonds. During the forecast period, the Company also has
first mortgage bond refundings of $20 million in 1996 and $30.0
million in 1998. At January 1, 1994 the total lines of credit
maintained by the Company with various banks amounted to $70
million. (See Note 7 of Notes to Consolidated Financial
Statements.)
Cash Construction Expenditures
The Company's consolidated cash construction expenditures were
$133.7 million in 1991, $118.0 million in 1992, and $122.9
million in 1993. During 1992, in response to the ongoing drought
conditions, the Company's cash construction budget was reduced.
Approximately 44 percent of these expenditures were spent on
generation facilities, 9 percent for transmission facilities, 32
percent for distribution facilities and 15 percent on general
plant and equipment. Principal additions during the period to
the Company's plant investment base include the completion of the
Milner Powerhouse in October 1992. Testing at the Milner project
was completed and the units were declared available for
commercial operation during the fall of 1992. The total cost of
construction at December 31, 1993 is $56.3 million including
allowance for funds used during construction.
Prairie Power
On June 30, 1992, the Company received approval from the IPUC to
acquire the Prairie Power Cooperative (PPC) and provide service
to its customers. Under the terms of the acquisition agreement,
which was consummated on July 24, 1992, the Company acquired
PPC's assets by assuming the cooperative's long-term debt of
approximately $1.9 million. The Company agreed also to implement
over the next ten years a $2.0 million rehabilitation of the
distribution system and reduced those PPC customers' rates by 15
percent from PPC rates effective at the time of the acquisition.
The new reduced rates will remain frozen at that level for 10
years and are higher than the Company's present rates for other
Idaho retail customers.
Wood River Turbine Sale
In 1993 the Company sold a 50-megawatt gas fired turbine
generator for $8.0 million. The Company's after-tax gain was
$4.2 million ($3.6 applicable to the Idaho jurisdiction). The
Company requested and received from the IPUC permission to use a
portion of the gain from the turbine sale as an offset to the
increased revenue requirement resulting from the additional
income taxes for 1993.
Construction Program
The Company's construction program (as detailed below) for the
1994-1998 period includes the rebuild of the Swan Falls hydro
facility and expansion of the Twin Falls hydro facility. The
Company's 1994 cash construction expenditures are expected to be
approximately $119.5 million with the 1994-1998 total presently
estimated at $580.9 million.
Swan Falls
Construction started in 1991 to rebuild the Swan Falls powerhouse
and increase its generating capacity from 12 megawatts to 25
megawatts. The amended FERC license provides for the retirement
of the present powerhouse and construction of a new powerhouse
containing two generating units of 12.5 megawatts each with
completion scheduled in 1994. The total cash expenditures of the
rebuild are presently estimated at $53.6 million with total
construction costs at $60.0 million including an allowance for
funds used during construction.
Twin Falls
In January 1991, the Company received a 50-year license from the
FERC for the Twin Falls Project that approves increasing the
generating capacity from 10 megawatts to 53 megawatts. The
Company received approval from the IPUC to rebuild the Twin Falls
hydroelectric facility as proposed in its application.
Construction started in July 1993 with completion scheduled in
mid 1995. The total cash expenditures of the expansion are
presently estimated at $32.3 million with total construction
costs at $34.2 million including allowance for funds used during
construction.
Southwest Intertie Project
Capitalizing on the Company's strategic location between the
Intermountain West and the Pacific Northwest, the Company is
considering the construction and operation of a new transmission
line which could serve as a major artery for regional transfers
of power between north and south. The Southwest Intertie Project
(SWIP) is a proposed 520-mile, 500 Kv transmission line which
would interconnect the Company's system with utilities in the
Southwest. The Bureau of Land Management (BLM) has completed the
Final Environmental Impact Statement/Proposed Plan Amendment
(EIS) for the SWIP. Approval of the EIS from the BLM is expected
during the second quarter of 1994. After approval of the EIS,
the economic feasibility of the line will be validated prior to
the time the Company proceeds with construction. The Company has
received preliminary commitments from various utilities and
electric providers for financial participation in the project.
It is the Company's intention to retain up to a 20 percent
ownership in the line.
Solar
The Company has joined Southern California Edison, the U. S.
Department of Energy and others in retrofitting an existing 10-
megawatt solar thermal experimental power plant called Solar 2.
The Company will contribute $630,500 over the next three years
and the Electric Power Research Institute, of which the Company
is a member, will contribute an additional $630,500 of matching
funds, bringing the Company's credited contribution to
approximately $1.3 million. The project is located near Barstow,
California, and should begin generating electricity in 1995.
Photovoltaic Systems
In August 1992, the Company proposed a $5 million three-year
pilot program to design, install, and maintain solar-powered
photovoltaic systems for remote locations that would otherwise
require costly line extensions. It is the Company's intent to
service only those inquiries located in its service territory.
The IPUC approved the proposal during September 1993 with the
OPUC giving its approval in October 1993 and the Nevada Public
Service Commission in June 1993.
Financing Program
Capital Structure
The Company's capital structure (as illustrated in Selected
Financial Data) has fluctuated during the three year period with
common equity remaining stable at 44 percent, preferred
increasing to 9 percent and debt decreasing to 47 percent. It is
the Company's objective to maintain capitalization ratios of
approximately 45 percent common equity, 8 to 10 percent preferred
stock and the balance long-term debt. The Company's strategy is
to achieve this target structure through accumulated earnings and
issuance of new equity. The Company's pre-tax interest coverage
ratios were 2.34 times in 1991, 2.50 times in 1992, and 3.14
times in 1993. The Company has on file a shelf registration
statement for the issuance of first mortgage bonds and/or
preferred stock with the total aggregate principal not to exceed
$200.0 million. The primary financial commitments at year-end
1993 are related to contracts and purchase orders for the
Company's program for construction and operation of facilities.
Common Stock
On July 8, 1992, the Company sold 1,250,000 shares of Common
Stock. The net proceeds of $30,706,250 were used for payment of
$4.0 million of short-term debt and the Company's ongoing
construction program.
In 1992, the Company also resumed issuing original issue shares
to its Employee Savings Plan, the Dividend Reinvestment and Stock
Purchase Plan and the Employee Stock Ownership Plan. During the
twelve months ended December 31, 1993 and 1992, common shares
totaling 898,528 and 959,527 were issued producing $26.7 million
and $25.5 million in proceeds to the Company, which were used for
its on-going construction program.
Preferred Stock
During 1991, the Company issued $25.0 million of serial preferred
stock which was used to retire an existing $25.0 million of
serial preferred stock. Also, in November 1991, the Company
issued $50.0 million of Auction Preferred Stock which proceeds
were used to retire early $32.5 million of first mortgage bonds,
to retire at maturity $10.0 million of first mortgage bonds and
other corporate purposes. On July 1, 1993 the Company utilized
its remaining preferred stock shelf registration and issued $25
million of serial preferred stock. The net proceeds of the
issuance were used for the Company's ongoing construction
program.
Long-Term Debt
On January 14, 1991, the Company issued $75,000,000 principal
amount of first mortgage bonds due January 1, 2021. The net
proceeds were used for payment of $48,280,000 of short-term
borrowings. The remainder of the funds were invested in
temporary cash investments until needed for general corporate
purposes.
On August 19, 1991, the Company issued $25,000,000 principal
amount of first mortgage bonds due August 2031. This series of
bonds was issued on a private placement basis and the net
proceeds were used for payment of $21,950,000 of short-term
borrowings with the remainder used for construction and general
corporate purposes.
On March 25, 1992, the Company issued $100,000,000 principal
amount of first mortgage bonds, $50,000,000 due in 2004, and
$50,000,000 due in 2027. The net proceeds were used to pay down
$36,000,000 of outstanding commercial paper notes, the early
redemption of $50,000,000 of existing first mortgage bonds due
2004, and for the Company's ongoing construction program.
On April 28, 1993 the Company issued $160,000,000 principal
amount of secured medium term notes, $80,000,000 due in 2003 and
$80,000,000 due in 2023. In May, the net proceeds were used to
retire early four series of first mortgage bonds totaling
$155,000,000 plus premiums and accrued interest. On September 1,
1993 the Company issued $30,000,000 principal amount of secured
medium term notes due in 1998. In October 1993, the net proceeds
were used to retire early, first mortgage bonds of $30,000,000
plus premiums and accrued interest.
Environmental Issues
Pacific Hide & Fur
During 1989, a Partial Consent Decree was filed with the United
States District Court for the District of Idaho wherein the
Company agreed to clean up the PCBs at a superfund site (Pacific
Hide & Fur Depot) and further agreed to pay for three years of
operation and maintenance of the site after the Certification of
Completion is issued by the Environmental Protection Agency
(EPA). Remediation activities were completed in 1992 by moving
the PCB contaminated soil to an EPA approved off-site disposal
facility.
The EPA is conducting an investigation regarding parties
responsible for lead contamination at the site. Information
indicates that the Company may have contributed a very small
amount of lead to the site. However, the EPA has presently
indicated the Company's involvement in the lead contamination at
the site is insignificant and that the Company may not be
required to participate in the lead clean-up.
At present, the Company has expensed approximately $6.9 million
to cover the estimated total cost of implementing remediation of
the PCBs and lead contaminated soil and scrap at the site.
Mountaineer
In May 1993, the Company was notified that Bridger Coal Company
(BCC), a joint venture, which is one-third owned by Idaho Energy
Resources Co (IERCO), a wholly-owned subsidiary of the Company,
was a potential contributor to a superfund site involving waste
motor oil delivered to a refinery (Mountaineer Refinery) in
Wyoming. In November 1993, BCC agreed to be included on the
potentially responsible party list for this site. The current
estimated cost for clean up is from $2.6 million to $5.0 million.
BCC's portion of the clean up, based on the amount of oil
delivered to the site, is estimated to be approximately 9
percent, or $234,000 to $450,000. IERCO would be liable for one-
third of the BCC portion, or approximately $78,000 to $150,000.
This liability has not been recorded in the Company's
consolidated financials because it does not have a material
effect on the results of operations.
PCB Program
The Company has a program to make the 200-plus substations on its
system non-PCB. The costs for this disposal program were $0.9
million, $0.3 million and $0.1 million for 1991, 1992, and 1993
respectively. While the Company's use of equipment containing
PCBs falls well within the federal safety standards, the Company
has voluntarily decided to virtually eliminate these compounds
from the substation sites. This program will save costs
associated with the long-term monitoring and testing of
substation equipment and grounds for PCB contamination as well as
being good for the environment today.
Salmon Recovery Plans
The Company continues to be actively involved with the long-term
survival of anadromous fish runs on the Columbia and Lower Snake
Rivers. The Company fully supports and actively participates in
the regional effort to develop a comprehensive and scientifically
credible recovery program for the salmon.
The Snake River Salmon Recovery Team submitted its Draft Recovery
Plan to the National Marine Fisheries Service (NMFS) detailing
its draft recommendations for restoring the listed Snake River
salmon runs. The Company has concluded a review of the 500-page
report and believes it sets forth a course of action that, if
fully implemented, could lead to a successful recovery. The Draft
Plan details comments regarding some institutional changes and
responsibility for management of the recovery efforts. It
suggests reductions in the ocean and in-river harvest rates,
calls for significant improvements in transportation and
collection systems, supports flow augmentation and habitat
improvements, calls for a test drawdown of the Lower Granite
Reservoir on the Snake River and suggests habitat, hatchery and
predation improvements. The Company will continue to closely
monitor the finalization of the Recovery Plan which is expected
to be released in 1994.
It is possible the final recovery plan could have a material
impact on the Company, as well as every other person, community
and industry in the Northwest that depend on the Snake and
Columbia Rivers. The Company is hopeful that the anadromous fish
runs can be restored to the level that society demands without
undue hardship placed upon the Company and those who benefit from
its service.
Nez Perce Tribe
On December 6, 1991, the Nez Perce Tribe filed a civil action
against the Company in the United States District Court for the
District of Idaho. The Tribe alleges that the Company's
construction, operation and maintenance of the Hells Canyon
Project, consisting of the Brownlee, Oxbow and Hells Canyon Dams,
prevented anadromous fish from reaching their traditional
spawning areas, and destroyed certain runs of those fish. This
allegedly deprived the Nez Perce Tribe of its treaty right to
take fish from the Snake and Columbia Rivers. The Nez Perce Tribe
is seeking compensatory and punitive damages, each in an amount
to be proven at trial. The Company maintains the suit is without
merit and has asked the federal court to enter a summary judgment
dismissing the action. The Company believes responsibility for
the concerns the Nez Perce Tribe has identified lies with the
United States. The Company's Hells Canyon Project was licensed by
the federal government and built in accordance with federally
approved plans. Since its inception, the Project has been
operated subject to federal regulation. The Company has complied
with all governmental requirements for mitigation of any impacts
the Project may have had on the fisheries. On January 19, 1993, a
hearing was held in Federal Court on the Company's motion for
summary judgment and the Court took the matter under advisement.
On July 30, 1993, the magistrate issued a Report and
Recommendation to the District Judge wherein it is recommended
that the Company's motion for summary judgment be granted.
Following briefing by the parties the District Judge by order
dated November 30, 1993, referred to the magistrate for
additional findings the tribes claim for compensation based on
exclusion from its usual and accustomed fishing places resulting
from the construction of the Hells Canyon Project. This issue
has been fully briefed by the parties and oral argument was held
on February 11, 1994.
Snake River Mollusk
In mid-December 1992, five Snake River mollusks were listed as
endangered and threatened species. This possibility has been a
part of all the Company's discussions regarding relicensing and
new hydro development since that time. The listing could
influence the way the Company operates its existing mid-Snake
River hydro facilities.
The listing specifically mentions the impact fluctuating water
levels related to hydro operations may have on the snails'
habitat. While most of the facilities on that stretch of the
river are baseload facilities, some do provide load-following
capability. There is uncertainty on exactly what impact, if any,
water fluctuations caused by the facilities have on the snails.
The Company intends to testify to the U. S. Fish and Wildlife
Service, the listing agency, that there is little data in this
area and that it proposes to study these operations. While there
is potential the listing could impact the way the Company
operates these facilities, the Company believes such changes will
be minor and not present any undue hardship.
Clean Air
The Company has analyzed the Clean Air Act legislation and its
effects upon the Company and its ratepayers. The Company's coal-
fired plants in Nevada and Oregon already meet the federal
emission rate standards and the Company's coal-fired plant in
Wyoming meets that state's even more stringent regulations. The
Company anticipates no material adverse effect upon its
operations.
Electric and Magnetic Fields
While scientific research has yet to establish any conclusive
link between electric and magnetic fields and human disease, the
possibility of a connection has caused public concern both
nationally and internationally. Electric and magnetic fields are
found wherever there is electric current, whether it be in a high-
voltage transmission line or the simplest of household electrical
appliances. Concern over possible health effects already has
prompted regulatory efforts to limit human exposure to electric
and magnetic fields in several areas of the nation. Depending on
what researchers ultimately discover and what regulations may be
deemed necessary, it is an issue that could impact a number of
industries, including electric utilities. At this time it is
difficult to estimate what impact, if any, the issue could have
on the Company and its operations.
Competition
The electric utility industry in general has become, and is
expected to be, increasingly competitive due to a variety of
regulatory, economic and technological developments. The Energy
Policy Act of 1992 was designed, among other things, to foster
competition in the wholesale market (a) through amendments to the
Holding Company Act, facilitating the ownership and operation of
generating facilities by "exempt wholesale generators" (which may
include independent power producers as well as affiliates of
electric utilities) and (b) through amendments to the Power Act,
authorizing the FERC under certain conditions to order utilities
which own transmission facilities to provide wholesale
transmission services to or for other utilities and other
entities generating electric energy for sale or resale.
With the passage of the Energy Policy Act and the advent of a
more competitive electric utility environment, the Company has
intensified its ongoing strategic planning process. The
Company's goal is to anticipate and fully integrate into its
operations any legislative, regulatory, environmental,
competitive and technological changes. The Company is well
positioned to succeed in a more competitive environment with its
low cost of energy production and is taking action to preserve
its competitive advantage. A major action area identified is the
Company's resource acquisition policies.
In September the Company submitted a detailed position paper to
its state regulators and other interested parties outlining
proposed resource acquisition policy changes. With the potential
deregulation of the electric utility industry and a more
competitive power supply market place, the Company believes that
current resource acquisition policies must be changed to avoid
burdening the Company and customers with unnecessary future power
supply costs. The Company wants to establish that future supply
additions are both needed at the time of development and are the
least-cost market alternative. Accordingly, in December 1993,
the Company filed with the IPUC for permission to approve new
lower prices for CSPP purchases. The Company believes existing
rates are no longer appropriate and that prices paid to CSPP
developers should be based upon need for the power and current
market conditions.
At the same time, in its position paper the Company proposes to
abandon planned development or expansion of several of its own
hydroelectric projects ahead of need. Expansion of existing
projects will only proceed if the price of the incremental
capacity is competitive within the regional marketplace or unless
required to do so under federal licensing rules. Accordingly,
the Company will forego relicense upgrades to its Shoshone Falls
and Upper Salmon hydro plants (unless necessitated by relicensing
requirements) and anticipates requesting permission from
regulators to abandon the proposed A. J. Wiley Project on the
Snake River. The remaining costs associated with the A.J. Wiley
Project to be written off will be immaterial.
Relicensing
As a result of various federal legislative actions and proposals
(such as the Electric Consumers Protection Act of 1986, Energy
Policy Act of 1992, Clean Water Act Reauthorization and
Endangered Species Act Reauthorization) a major issue facing the
Company is the relicensing of its hydro facilities. Because the
federal licenses for the majority of the Company's hydroelectric
projects expire during the next 10 to 15 years, the Company has
established an internal task force to vigorously pursue the
relicensing process. The relicensing of these projects is not
automatic under federal law. The Company must demonstrate
comprehensive usage of the facilities, that it has been a
conscientious steward of the natural resource entrusted to it and
that there is a strong public interest in the Company continuing
to hold the federal licenses. The Company can not anticipate what
type of environmental or operational requirements may be placed
on the projects in the relicensing process, nor can it estimate
what the eventual cost will be for relicensing. However, the
Company anticipates that its efforts in this matter for all of
the hydro facilities will prove to be successful.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
INDEX TO FINANCIAL STATEMENTS
AND FINANCIAL STATEMENT SCHEDULES
PAGE
Management's Responsibility for Financial Statements 57
Consolidated Financial Statements:
Consolidated Balance Sheets as of December 31, 1993,
1992 and 1991 58-59
Consolidated Statements of Income for the Years
Ended December 31, 1993, 1992 and 1991 60
Consolidated Statements of Retained Earnings for
the Years Ended December 31, 1993, 1992 and 1991 61
Consolidated Statements of Capitalization as of
December 31, 1993, 1992 and 1991 62
Consolidated Statements of Cash Flows for the Years
Ended December 31, 1993, 1992 and 1991 63
Notes to Consolidated Financial Statements 64-79
Independent Auditors' Report 80
Supplemental Financial Information (Unaudited) 81
Supplemental Schedules for the Years Ended December 31,
1993, 1992 and 1991:
Schedule V- Property, Plant and Equipment 89-91
Schedule VI- Accumulated Depreciation and
Amortization of Property, Plant and
Equipment 92-94
Schedule VIII- Valuation and Qualifying Accounts 95
Schedule X- Supplementary Income Statement Information 96
MANAGEMENT'S RESPONSIBILITY FOR FINANCIAL STATEMENTS
The management of Idaho Power Company is responsible for the
preparation and presentation of the information and
representations contained in the accompanying financial
statements. The financial statements have been prepared in
conformance with generally accepted accounting principles for a
rate regulated enterprise. Where estimates are required to be
made in preparing the financial statements, management has
applied its best judgment as to the adequacy of the estimates
based upon all available information.
The Company maintains a system of internal accounting controls
and related policies and procedures designed to provide
reasonable assurance that all assets are protected against loss
or unauthorized use and that transactions are executed in
accordance with management's authorization and properly recorded
to permit preparation of reliable financial statements. The
systems are supported by a staff of corporate accountants and
internal auditors who, among other duties, evaluate and monitor
the systems of internal accounting control in coordination with
the independent auditors. The staff of internal auditors conduct
special and operational audits in support of these accounting
controls throughout the year.
The Board of Directors, through its Audit Committee comprised
entirely of outside directors, meets periodically with
management, internal auditors and the Company's independent
auditors to discuss auditing, internal control and financial
reporting matters. To ensure their independence, both the
internal auditors and independent auditors have full and free
access to the Audit Committee.
The financial statements have been audited by Deloitte & Touche,
the Company's independent auditors, who were responsible for
conducting their audit in accordance with generally accepted
auditing standards.
By:__/s/__Joseph W. Marshall__ By:__/s/__J. LaMont Keen__
Joseph W. Marshall J. LaMont Keen
Chairman and Vice President and Chief
Chief Executive Officer Financial Officer
By:__/s/__Harold J. Hochhalter__
Harold J. Hochhalter
Controller and Chief Accounting Officer
<TABLE> IDAHO POWER COMPANY
CONSOLIDATED BALANCE SHEETS
ASSETS
<CAPTION>
December 31,
1993 1992 1991
(Thousands of Dollars)
<S> <C> <C> <C>
ELECTRIC PLANT (Notes 1 and 6):
In service (at original cost) $2,249,723 $2,198,747 $2,094,611
Less accumulated provision for
depreciation 728,979 683,332 639,238
In service - Net 1,520,744 1,515,415 1,455,373
Construction work in progress 92,682 66,997 70,841
Held for future use 2,958 3,083 3,060
Electric plant - Net 1,616,384 1,585,495 1,529,274
INVESTMENTS AND OTHER PROPERTY 20,772 11,411 9,801
CURRENT ASSETS:
Cash and cash equivalents 8,228 4,966 7,229
Receivables:
Customer 29,741 28,687 27,280
Allowance for uncollectible
accounts (1,377) (1,421) (1,300)
Notes 5,616 1,669 744
Employee notes receivable 5,909 5,970 4,283
Other 1,858 1,695 2,114
Accrued unbilled revenues (Note 1) 25,583 27,210 23,737
Materials and supplies (at average
cost) 23,372 25,762 26,423
Fuel stock (at average cost) 11,553 14,282 15,708
Prepayments (Note 9) 20,975 22,171 15,678
Regulatory assets associated with
income taxes 4,914 - -
Total current assets 136,372 130,991 121,896
DEFERRED DEBITS:
American Falls and Milner water
rights 32,755 32,890 21,315
Company-owned life insurance
(Note 9) 45,294 40,228 32,892
Regulatory assets associated with
income taxes 171,569 - -
Regulatory assets - other 35,036 - -
Other 39,235 61,292 58,496
Total deferred debits 323,889 134,410 112,703
TOTAL $2,097,417 $1,862,307 $1,773,674
<FN>
The accompanying notes are an integral part of these
statements.
</TABLE>
<TABLE>
<CAPTION>
IDAHO POWER COMPANY
CONSOLIDATED BALANCE SHEETS
CAPITALIZATION AND LIABILITIES
December 31,
1993 1992 1991
(Thousands of Dollars)
<S> <C> <C> <C>
CAPITALIZATION (See Page 62):
Common stock equity (Note 3):
Common stock - $2.50 par value
(shares authorized 50,000,000;
shares outstanding 1993 -
37,085,055; 1992 - 36,186,527;
1991 - 33,977,000) $92,713 $90,466 $84,942
Premium on capital stock 350,882 326,338 275,505
Capital stock expense (4,128) (3,806) (3,623)
Retained earnings 222,900 212,404 222,973
Total common stock equity 662,367 625,402 579,797
Preferred stock (Note 4) 132,751 107,874 108,191
Long-term debt (Note 6) 693,780 701,948 629,981
Total capitalization 1,488,898 1,435,224 1,317,969
CURRENT LIABILITIES:
Long-term debt due within one
year 466 464 350
Notes payable (Note 7) 4,000 6,000 48,500
Accounts payable 31,912 34,821 33,874
Taxes accrued 15,452 16,182 14,600
Interest accrued 14,920 18,287 17,285
Other 13,731 12,125 14,459
Total current liabilities 80,481 87,879 129,068
DEFERRED CREDITS:
Accumulated deferred investment
tax credits (Notes 1 and 2) 72,013 73,651 75,300
Accumulated deferred income
taxes (Notes 1 and 2) 358,280 210,435 202,340
Regulatory liabilities associated
with income taxes 34,968 - -
Regulatory liabilities - other 4,235 - -
Other (Note 9) 58,542 55,118 48,997
Total deferred credits 528,038 339,204 326,637
COMMITMENTS AND CONTINGENT
LIABILITIES (Note 8)
TOTAL $2,097,417 $1,862,307 $1,773,674
<FN>
The accompanying notes are an integral part of these
statements.
</TABLE>
<TABLE>
<CAPTION>
IDAHO POWER COMPANY
CONSOLIDATED STATEMENTS OF INCOME
Year Ended December 31,
1993 1992 1991
(Thousands of Dollars)
<S> <C> <C> <C>
REVENUES (Note 1) $540,402 $498,092 $483,193
EXPENSES:
Operation:
Purchased power (Note 1) 45,361 58,496 51,210
Fuel expense (Note 10) 87,855 96,710 75,161
Other 121,252 101,659 107,223
Maintenance 43,136 35,888 44,370
Depreciation (Note 1) 58,724 59,823 57,597
Taxes other than income taxes 22,129 20,562 21,168
Total expenses 378,457 373,138 356,729
INCOME FROM OPERATIONS 161,945 124,954 126,464
OTHER INCOME:
Allowance for equity funds used
during construction (Note 1) 3,060 2,400 1,945
Other - Net (Note 9) 9,924 8,733 7,508
Total other income 12,984 11,133 9,453
INTEREST CHARGES:
Interest on long-term debt 53,706 53,408 54,370
Other interest (Notes 1 and 7) 2,750 2,050 4,606
Total interest charges 56,456 55,458 58,976
Allowance for borrowed funds
used during construction
(Note 1) (2,465) (2,523) (2,075)
Net interest charges 53,991 52,935 56,901
INCOME BEFORE INCOME TAXES 120,938 83,152 79,016
INCOME TAXES (Notes 1 and 2) 36,474 23,162 21,144
NET INCOME 84,464 59,990 57,872
Dividends on preferred stock
(Note 4) 6,009 5,516 4,904
EARNINGS ON COMMON STOCK $ 78,455 $ 54,474 $ 52,968
AVERAGE COMMON SHARES OUTSTANDING
(000) 36,675 35,116 33,977
EARNINGS PER SHARE OF COMMON
STOCK (Note 3) $2.14 $1.55 $1.56
<FN>
The accompanying notes are an integral part of these statements.
</TABLE>
<TABLE>
<CAPTION>
IDAHO POWER COMPANY
CONSOLIDATED STATEMENTS OF RETAINED EARNINGS
Year Ended December 31,
1993 1992 1991
(Thousands of Dollars)
<S> <C> <C> <C>
RETAINED EARNINGS
Beginning of year $212,404 $222,973 $233,241
NET INCOME 84,464 59,990 57,872
Total 296,868 282,963 291,113
DIVIDENDS:
Preferred stock (Note 4) 6,009 5,516 4,904
Common stock (per share: 1993 -
1991 - $1.86) (Note 3) 67,959 65,043 63,197
Total dividends 73,968 70,559 68,101
PREFERRED STOCK REDEMPTION - - 39
RETAINED EARNINGS
End of year $222,900 $212,404 $222,973
<FN>
The accompanying notes are an integral part of these statements.
</TABLE>
<TABLE>
<CAPTION>
IDAHO POWER COMPANY
CONSOLIDATED STATEMENTS OF CAPITALIZATION
December 31,
1993 % 1992 % 1991 %
(Thousands of Dollars)
<S> <C> <C> <C> <C> <C> <C>
COMMON STOCK EQUITY
(Note 3):
Common stock $92,713 $90,466 $84,942
Premium on capital stock 350,882 326,338 275,505
Capital stock expense (4,128) (3,806) (3,623)
Retained earnings 222,900 212,404 222,973
Total common stock
equity 662,367 44 625,402 44 579,797 44
PREFERRED STOCK (Note 4):
4% preferred stock 17,751 17,874 18,191
7.68% Series, serial
preferred stock 15,000 15,000 15,000
8.375% Series, serial
preferred stock 25,000 25,000 25,000
Auction rate preferred
stock 50,000 50,000 50,000
7.07% Series, serial
preferred stock 25,000 - -
Total preferred stock 132,751 9 107,874 7 108,191 8
LONG-TERM DEBT (Note 6):
First mortgage bonds:
5 1/4% Series due 1996 20,000 20,000 20,000
6 1/8% Series due 1996 - 30,000 30,000
5.33 % Series due 1998 30,000 - -
8.65 % Series due 2000 80,000 80,000 80,000
7 3/4% Series due 2002 - 30,000 30,000
6.40 % Series due 2003 80,000 - -
8 3/8% Series due 2004 - 35,000 35,000
8 % Series due 2004 50,000 50,000 -
10 % Series due 2004 - - 50,000
8 1/2% Series due 2006 - 30,000 30,000
9 % Series due 2008 - 60,000 60,000
9.50 % Series due 2021 75,000 75,000 75,000
7.50 % Series due 2023 80,000 - -
8 3/4% Series due 2027 50,000 50,000 -
9.52 % Series due 2031 25,000 25,000 25,000
Total first mortgage
bonds 490,000 485,000 435,000
<FN>
*Less amount due within
one year - - -
Net first mortgage
bonds 490,000 485,000 435,000
Pollution control revenue
bonds:
5.90 % Series due 2003 25,050* 25,450* 25,800*
6.0 % Series due 2007 24,000 24,000 24,000
7 1/4% Series due 2008 4,360 4,360 4,360
7 5/8% Series 1983-1984
due 2013-2014 68,100 68,100 68,100
8.30 % Series 1984
due 2014 49,800 49,800 49,800
Total pollution
control revenue bonds 171,310 171,710 172,060
<FN>
*Less amount due within
one year (400) (400) (350)
Net pollution control
Revenue bonds 170,910 171,310 171,710
Project financing -
Ida-West - 11,243 1,694
REA notes 1,834 1,899 -
Less amount due within
one year (66) (64) -
Net REA notes 1,768 1,835 -
American Falls bond
guarantee 21,055 21,190 21,315
Milner Dam note guarantee 11,700 11,700 -
Unamortized premium/
discount-Net (Note 1) (1,653) (330) 262
Total long-term debt 693,780 47 701,948 49 629,981 48
TOTAL CAPITALIZATION $1,488,898 100 $1,435,224 100 $1,317,969 100
<FN>
The accompanying notes are an integral part of these statements.
</TABLE>
<TABLE>
<CAPTION>
IDAHO POWER COMPANY
CONSOLIDATED STATEMENTS OF CASH FLOWS
Year Ended December 31,
1993 1992 1991
(Thousands of Dollars)
<S> <C> <C> <C>
OPERATING ACTIVITIES:
Cash received from operations:
Retail revenues $ 434,625 $ 432,594 $ 414,811
Wholesale revenues 84,726 42,541 52,521
Other revenues 23,411 25,531 21,652
Fuel paid (83,885) (96,839) (71,706)
Purchased power paid (50,246) (55,976) (57,930)
Other operation & maintenance paid (162,014) (145,518) (148,443)
Interest paid (include long
and short-term debt only) (56,348) (52,310) (51,901)
Income taxes paid (32,512) (14,859) (22,802)
Taxes other than income taxes paid (22,165) (21,399) (21,883)
Other operating cash receipts and
payments - Net 8,213 (5,917) (603)
Net cash provided by operating
activities 143,805 107,848 113,716
FINANCING ACTIVITIES:
First mortgage bonds issued 188,136 98,870 98,969
PC bond fund requisitions/other long- 5,594 9,583 1,694
term debt
Common stock issued 26,781 56,223 -
Preferred stock issued 24,781 - 74,031
Short-term borrowings (2,140) (42,500) 220
Long-term debt retirement (191,878) (52,346) (60,049)
Preferred stock retirement (65) (270) (25,351)
Dividends on preferred stock (5,914) (5,620) (4,599)
Dividends on common stock (67,959) (65,043) (63,197)
Net cash - financing activities (22,664) (1,103) 21,718
INVESTING ACTIVITIES:
Additions to utility plant (122,949) (118,048) (133,735)
Conservation (6,687) (5,287) (3,852)
Other 11,757 14,327 (663)
Net cash - investing activities (117,879) (109,008) (138,250)
Change in cash and cash equivalents 3,262 (2,263) (2,816)
Cash and cash equivalents beginning
of period 4,966 7,229 10,045
Cash and cash equivalents end of
period $ 8,228 $ 4,966 $ 7,229
RECONCILIATION OF NET INCOME TO NET
CASH PROVIDED BY OPERATING ACTIVITIES:
Net income $ 84,464 $ 59,990 $ 57,872
Adjustments to reconcile net income to
net cash:
CSPP-Net amortization/(deferral) (518) (3,587) (4,225)
Depreciation 58,724 59,823 57,597
Deferred income taxes 6,690 8,179 5,762
Investment tax credit - Net (1,583) (1,439) (3,177)
Allowance for funds used during
construction (5,525) (4,923) (4,020)
Postretirement benefits funding
(excl pensions) (7,481) (11,369) (8,574)
Changes in operating assets and
liabilities:
Accounts receivable 2,360 2,574 5,791
Fuel inventory 3,970 (129) 3,455
Accounts payable (4,367) 6,107 (2,494)
Taxes payable (1,141) 779 (4,927)
Interest payable (1,010) 2,841 4,227
Other - Net 9,222 (10,998) 6,429
Net cash provided by operating
activities $ 143,805 $ 107,848 $ 113,716
<FN>
The accompanying notes are an integral part of these statements.
</TABLE>
1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES:
PRINCIPLES OF CONSOLIDATION _ The consolidated financial
statements include the accounts of the Company and its wholly-
owned subsidiaries, Idaho Energy Resources Co (IERCO), Idaho
Utility Products Company (IUPCO), IDACORP, INC. and Ida-West
Energy Company (Ida-West). All significant intercompany
transactions and balances have been eliminated in
consolidation.
SYSTEM OF ACCOUNTS _ The Company is an electric utility and
its accounting records conform to the Uniform System of
Accounts prescribed by the Federal Energy Regulatory
Commission and adopted by the public utility commissions of
Idaho, Oregon, Nevada and Wyoming.
ELECTRIC PLANT _ The cost of additions to electric plant in
service represents the original cost of contracted services,
direct labor and material, allowance for funds used during
construction and indirect charges for engineering,
supervision and similar overhead items. Maintenance and
repairs of property and replacements and renewals of items
determined to be less than units of property are charged to
operations. For property replaced or renewed the original
cost plus removal cost less salvage is charged to accumulated
provision for depreciation while the cost of related
replacements and renewals is added to electric plant.
ALLOWANCE FOR FUNDS USED DURING CONSTRUCTION (AFDC) _ The
allowance, a non-cash item, represents the composite interest
costs of debt, shown as a reduction to interest charges, and
a return on equity funds, shown as an addition to other
income, used to finance construction. While cash is not
realized currently from such allowance, it is realized under
the ratemaking process over the service life of the related
property through increased revenues resulting from higher
rate base and higher depreciation expense. Based on the
uniform formula adopted by the Federal Energy Regulatory
Commission (FERC), the Company's weighted average monthly
AFDC rates for 1993, 1992 and 1991 were 9.6%, 8.7% and 9.4%,
respectively.
REVENUES _ In order to match revenues with associated
expenses, the Company accrues unbilled revenues for electric
services delivered to customers but not yet billed at month-
end.
RATE RELIEF _ On May 4, 1992, the Idaho Public Utilities
Commission (IPUC) issued an order which authorized the
Company to put in place for a twelve-month period temporary
rate relief of 3.9 percent or $15.0 million effective May 6,
1992. The Company also filed and received an accounting
order from the Oregon Public Utility Commission (OPUC) for
permission to begin deferring with interest 33.5 percent of
Oregon's share of increased power production costs starting
on March 23, 1992 and continuing through December 31, 1992.
The Company filed a request and received approval from the
OPUC for a 24 month amortization period of an annual rate
increase of $526,360 or 2.57 percent effective July 1, 1993.
The Company also submitted a rate increase request to the
FERC for approval to increase rates to its wholesale
customers. The FERC granted a $547,900 rate increase for a
twelve-month period effective November 10, 1992. All of
these rate actions were requested due to drought related
effects during 1991 and 1992, which reduced water flows and
increased net power supply costs.
On October 9, 1992, the Company filed an application with the
IPUC which would allow the Company to suspend the deferral of
certain revenue items to partially offset the increase in
1992 power supply costs. On January 8, 1993, the IPUC
authorized the Company to suspend five and one-half months
(January 1, 1993 through June 15, 1993) of the revenue
deferral associated with the Afton cogeneration facility for
a total of $1,225,707. This allowed the Company to defer
additional 1992 reserve capacity costs of $1,225,707 against
this suspension of revenue deferrals in 1993.
On March 29, 1993, the IPUC approved a power cost adjustment
(PCA) mechanism for the Company, pursuant to the Company's
application requesting authority to implement a PCA. Under
the PCA, customer's rates will be adjusted annually to
reflect the Company's forecasted net power supply costs.
Deviations from predicted costs are deferred with interest
and then adjusted (trued-up) in the subsequent year. A
transition period was established providing for inclusion of
60% of power cost deviations from normalized rates in the PCA
until conclusion of the Company's next general rate case when
the allowed percentage will increase to 90%.
On May 16, 1993, the Company implemented its first PCA after
the IPUC approved a $5.0 million revenue increase to base
rates for the period May 16, 1993 through May 15, 1994. At
the same time the one-year temporary rate relief granted in
May 1992 ceased and the combined effect was a decrease of
$10.0 million in rates.
DEPRECIATION _ Effective April 1, 1993, the Company revised
its depreciation methodology on certain generation plants
from the five percent present worth method to the straight-
line method. This change and the extention of the service
lives of certain plants resulted in a minimal change in
depreciation expense. All electric plant is now depreciated
using the straight-line method. Annual depreciation
provisions as a percent of average depreciable electric plant
in service approximated 2.92% in 1993, 2.91% in 1992 and
2.93% in 1991 and are considered adequate to amortize the
original cost over the estimated service lives of the
properties.
INCOME TAXES _ Consistent with orders and directives of the
IPUC, the regulatory authority having principal jurisdiction,
deferred income taxes (commonly referred to as normalized
accounting) are provided for the difference between income
tax depreciation and straight-line depreciation on coal-fired
generation facilities and properties acquired after 1980. On
other facilities, deferred income taxes are provided for the
difference between accelerated income tax depreciation and
straight-line depreciation using tax guideline lives on
assets acquired prior to 1981. Deferred income taxes are not
provided for those income tax timing differences where the
prescribed regulatory accounting methods do not provide for
current recovery in rates. The Company adopted SFAS No. 109
"Accounting for Income Taxes" on January 1, 1993 which had no
material effect on the earnings of the Company (see Note 2).
The state of Idaho allows a three percent investment tax
credit upon certain plant additions. Investment tax credits
are deferred and amortized to income over the estimated
service lives of the related properties.
PURCHASED POWER _ The Company has contracts to purchase the
energy from five PURPA Qualified Facilities which are 50
percent owned by Ida-West (a wholly-owned subsidiary of the
Company). Power purchased from these facilities amounted to
$5,975,093 in 1993.
CASH AND CASH EQUIVALENTS _ For purposes of reporting cash
flows, cash and cash equivalents include cash on hand and
highly liquid temporary investments with original maturity
dates of three months or less. The Company has changed the
Statements of Cash Flows from the indirect method to the
direct method. Previous year's presentations have been
restated to conform with the new method.
OTHER ACCOUNTING POLICIES _ Debt discount, expense and
premium are being amortized over the terms of the respective
debt issues.
RECLASSIFICATIONS _ Certain items previously reported for
years prior to 1993 have been reclassified to conform with
the current year's presentation. Net income was not affected
by these reclassifications.
2. INCOME TAXES:
A reconciliation between the statutory federal income tax rate and the
effective rate for the years 1993, 1992 and 1991 is as follows:
<TABLE>
<CAPTION>
1993 1992 1991
Amount Rates Amount Rates Amount Rates
(Thousands of Dollars)
<S> <C> <C> <C> <C> <C> <C>
Computed income taxes
based on statutory
federal income
tax rate $42,328 35.0% $28,272 34.0% $26,898 34.0%
Change in taxes resulting
from:
AFUDC (1,798) (1.5) (1,508) (1.8) (1,349) (1.7)
Investment tax credit
restored (2,898) (2.4) (3,446) (4.1) (3,936) (5.0)
Repair allowance (2,975) (2.5) (2,278) (2.7) (2,278) (2.9)
Elimination of amounts
provided in prior
years (4,686) (3.9) (1,601) (1.9) - -
Current state income
taxes 2,693 2.2 973 1.2 1,507 1.9
Depreciation 4,116 3.4 1,738 2.1 658 0.8
Other (306) (0.1) 1,012 1.1 (356) (0.3)
Total provision for
federal and state
income taxes $36,474 30.2% $23,162 27.9% $21,144 26.8%
The provision for income taxes consists of the following:
Income taxes currently
payable:
Federal $27,199 $16,366 $16,394
State 4,168 56 2,165
Total 31,367 16,422 18,559
Income taxes deferred -
Net of
Amortization:
Federal 6,621 7,688 6,302
State 69 491 (540)
Total 6,690 8,179 5,762
Investment and other tax
credits:
Deferred 1,315 2,007 759
Restored (2,898) (3,446) (3,936)
Total (1,583) (1,439) (3,177)
Total provision for
income taxes $36,474 $23,162 $21,144
The provision for deferred income taxes consists of the following:
Deferred:
Excess of tax over book
depreciation normalized $14,044 $12,474 $10,582
Other 6,384 6,743 2,986
Total 20,428 19,217 13,568
Restored (13,738) (11,038) (7,806)
Total $ 6,690 $ 8,179 $ 5,762
</TABLE>
During 1993, the Company settled federal tax liabilities on the
1987 through 1990 tax years except for immaterial amounts that
relate to a partnership. Federal income tax returns for years
1991 and 1992 are under examination by the Internal Revenue
Service and the Company believes that a final settlement of its
federal income tax liabilities for these years will not have a
material effect on its results of operation or financial
position.
The Company adopted SFAS No. 109 "Accounting for Income Taxes" on
January 1, 1993 which had no material effect on the earnings of
the Company. SFAS 109, among other things, (i) requires the
liability method be used in computing deferred taxes on all
temporary differences between book and tax basis of assets and
liabilities; (ii) requires that deferred tax liabilities and
assets be adjusted for an enacted change in tax laws or rates;
and (iii) prohibits net-of-tax accounting and reporting.
Regulated enterprises are required to recognize such adjustments
as regulatory assets or liabilities if it is probable that such
amounts will be recovered from or returned to customers in future
rates. As of December 31, 1993, the Company has recorded
regulatory assets of $176.5 million and regulatory liabilities in
the amount of $35.0 million which were offset by an equal amount
of accumulated deferred income tax provision. The regulatory
asset is primarily based upon differences between the book and
tax basis of the electric plant in service and the accumulated
reserve for depreciation.
In August 1993, Congress passed the Revenue Reconciliation Act of
1993 which retroactively to January 1, 1993 increased the Federal
tax rate from 34% to 35%. The Company requested and received
from the IPUC permission to recover the higher taxes by realizing
a portion of the gain on the sale of the Wood River Turbine as
income in 1993.
3. COMMON STOCK:
Changes in shares of the common stock of the Company for 1993,
1992 and 1991 were as follows:
Common Stock
Premium
$2.50 on
Shares Par Capital
Value Stock
(Thousands of Dollars)
Balance at December 31, 1990 33,977,000 $84,942 $275,802
Gain on reacquired 4% preferred
stock (Note 4) - - 283
Preferred stock redemption
(Note 4) - - (580)
Balance at December 31, 1991 33,977,000 84,942 275,505
Gain on reacquired 4% preferred
stock (Note 4) - - 152
Stock purchase plans 959,527 2,399 23,101
Public offering (July 1992) 1,250,000 3,125 27,580
Balance at December 31, 1992 36,186,527 90,466 326,338
Gain on reacquired 4% preferred
stock (Note 4) - - 50
Stock purchase plans 898,528 2,247 24,494
Balance at December 31, 1993 37,085,055 $92,713 $350,882
During the first quarter of 1992 the Company reinstated issuing
original issue shares of common stock for its Dividend
Reinvestment and Stock Purchase Plan, the Employee Savings Plan
and the Employee Stock Ownership Plan. During 1993 and 1992,
common shares totaling 898,528 and 959,527, respectively, have
been issued to these plans.
On July 8, 1992, the Company issued 1,250,000 shares of its
common stock. The net proceeds of $30,706,250 were received and
used for the payment of $4.0 million of short-term debt with the
remainder used for the Company's ongoing construction program.
As of December 31, 1993, the Company had 2,151,078 of its
authorized but unissued shares of common stock reserved for
future issuance under its Dividend Reinvestment and Stock
Purchase Plan, Employee Savings Plan and Employee Stock Ownership
Plan.
On January 11, 1990, the Board of Directors adopted a Shareowner
Rights Plan (Plan). Under the Plan, the Company declared a
distribution of one Preferred Stock Right (Right) for each of the
Company's outstanding Common shares held on January 29, 1990 or
issued thereafter. The Rights are currently not exercisable and
will be exercisable only if a person or group (Acquiring Person)
either acquires ownership of 20 percent or more of the Company's
Voting Stock or commences a tender offer that would result in
ownership of 20 percent or more. The Company may redeem the
Rights at a price of $0.01 per Right anytime prior to acquisition
by an Acquiring Person of a 20 percent position.
Following the acquisition of a 20 percent position, each Right
will entitle its holder, subject to regulatory approval, to
purchase for $85 that number of shares of Common Stock or
Preferred Stock having a market value of $170.
If after the Rights become exercisable, the Company is acquired
in a merger or other business combination, 50 percent or more of
its consolidated assets or earnings power are sold or the
Acquiring Person engages in certain acts of self-dealing, each
Right entitles the holder to purchase for $85, shares of the
acquiring company's Common Stock having a market value of $170.
Any Rights that are or were held by an Acquiring Person become
void if either of these events occurs. The Rights expire on
January 11, 2000.
4. PREFERRED STOCK:
The number of shares of preferred stock outstanding at December
31, 1993, 1992 and 1991 was as follows:
Shares Outstanding at
December 31, Call Price
1993 1992 1991 Per Share
Preferred stock:
Cumulative, $100 par
value:
4% preferred stock
(authorized
215,000 shares) 177,506 178,735 181,913 $104.00
Serial preferred stock,
7.68% Series
(authorized
150,000 shares) 150,000 150,000 150,000 $102.97
Serial preferred stock,
cumulative, without
par value; total of
3,000,000
shares authorized:
8.375% Series, $100
stated value,
(authorized 250,000
shares)(a) 250,000 250,000 250,000 $105.58 to
$100.37
7.07% Series, $100
stated value,
(authorized 250,000
shares)(b) 250,000 - - $103.535
to
$100.354
Auction rate preferred
stock, $100,000
stated value,
(authorized 500
shares)(c) 500 500 500 $100,000.00
Total 828,006 579,235 582,413
[FN]
(a) The preferred stock is not redeemable prior to October 1,
1996.
(b) The preferred stock is not redeemable prior to July 1, 2003.
(c) Dividend rate at December 31, 1993 was 3.04% and ranged
between 2.62% and 3.21% during the year.
During 1993, 1992 and 1991 the Company reacquired and retired
1,229; 3,178 and 5,697 shares of 4% preferred stock resulting in
a net addition to premium on capital stock of $50,151; $151,891
and $282,431, respectively. As of December 31, 1993 the overall
effective cost of all outstanding preferred stock was 5.70
percent.
On July 1, 1993 the Company utilized the remaining preferred
stock shelf registration and issued $25,000,000 of 7.07% Series,
Serial Preferred Stock ($100 stated value). The net proceeds of
the issuance were used for the Company's ongoing construction
program.
5. FAIR VALUE OF FINANCIAL INSTRUMENTS:
The estimated fair value of the Company's financial instruments
have been determined by the Company using available market
information and appropriate valuation methodologies. The use of
different market assumptions and/or estimation methodologies may
have a material effect on the estimated fair value amounts.
Cash and cash equivalents, customer and other receivables, notes
payable, accounts payable, interest accrued, and taxes accrued
are reported at their carrying value as these are a reasonable
estimate of their fair value. The total estimated fair value of
long-term debt was approximately $733,251,000 for 1992 and
$762,575,000 for 1993. The estimated fair values for long-term
debt are based upon quoted market prices of the same or similar
issues.
6. LONG-TERM DEBT:
The amount of first mortgage bonds issuable by the Company is
limited to a maximum of $900,000,000 and by property, earnings
and other provisions of the mortgage and supplemental indentures
thereto. Substantially all of the electric utility plant is
subject to the lien of the indenture. Pollution Control Revenue
Bonds, Series 1984, due December 1, 2014, are secured by First
Mortgage Bonds, Pollution Control Series A, which were issued by
the Company and are held by a Trustee for the benefit of the
bondholders.
On March 25, 1992, the Company issued $50,000,000 principal
amount of First Mortgage Bonds, 8% Series, due 2004, and
$50,000,000 principal amount of First Mortgage Bonds, 8 3/4%
Series, due 2027. The net proceeds were used initially to pay
down $36,000,000 of outstanding commercial paper notes and the
remainder was used for the early redemption of $50,000,000 First
Mortgage Bonds, 10% Series, due 2004, and for the Company's
ongoing construction program.
On April 28, 1993 the Company issued $80,000,000 principal amount
of Secured Medium Term Notes, Series A, 6.40% Series due 2003 and
$80,000,000 principal amount of Secured Medium Term Notes, Series
A, 7.50% Series due 2023. In May, the net proceeds were used to
retire early four series (7 3/4% Series due 2002, 8 3/8% Series
due 2004, 8 1/2% Series due 2006 and 9% Series due 2008) of first
mortgage bonds totaling $155,000,000 plus premiums and accrued
interest. On September 1, 1993 the Company issued $30,000,000
principal amount of Secured Medium Term Notes, Series A, 5.33%
Series due 1998. On October 1, 1993, the net proceeds were used
to retire early the 6 1/8% Series, First Mortgage Bonds of
$30,000,000 plus premiums and accrued interest. The early
redemption of these first mortgage bonds reduced the Company's
overall cost of long-term debt and reduced the Company's annual
interest expense by approximately $2.3 million.
The only first mortgage bonds maturing during the five-year
period ending 1998 are $20,000,000 in 1996 and $30,000,000 in
1998. Sinking fund requirements for the first mortgage bonds
outstanding at December 31, 1993 are $5,398,000 per year. These
requirements may be met by the deposit of cash, deposit of bonds,
or by certification of property additions at the rate of 167% of
requirements. The Company's practice is to certify additional
property to meet the sinking fund requirements. In September
1991, 1992 and 1993, $350,000, $350,000, and $400,000
respectively, of the 5.90% Series, Pollution Control Revenue
Bonds, were retired pursuant to sinking fund requirements for
those years. Sinking fund requirements during the five-year
period ending 1998 for pollution control bonds outstanding at
December 31, 1993 are $400,000 in 1994, $450,000 in 1995 and
1996, and $500,000 in 1997 and 1998. As of December 31, 1993,
the overall effective cost of all outstanding first mortgage
bonds and pollution control revenue bonds was 8.02 percent in
comparison to 8.33 percent in 1992 and 8.43 percent in 1991.
On February 10, 1992, $11,700,000 principal amount of 8.95%
Guaranteed Notes due 2017 were issued by Milner Dam, Inc., an
Idaho Corporation, in which the Twin Falls Canal Company and the
North Side Canal Company have assigned their interest in the
Milner Dam Rehabilitation Project. The Company, pursuant to an
agreement signed with Milner Dam. Inc., executed a guarantee of
these notes and agreed to make royalty (falling water) payments
to Milner Dam, Inc. for use of water released from the Milner Dam
Rehabilitation Project beginning in 1993.
7. NOTES PAYABLE:
At January 1, 1994, the Company had regulatory authority to incur
up to $150,000,000 of short-term indebtedness. Under this
authority, total lines of credit maintained with various banks
amounted to $70,000,000. Under annual borrowing arrangements
with these banks, the Company is required to pay a fee of 3/16 of
1% on the available and committed lines of credit. Commercial
paper may be issued in an amount not to exceed 25% of revenues
for the latest twelve-month period and are supported by bank
lines of credit of an equal amount.
Balances and interest rates of short-term borrowings were as
follows:
Year Ended December 31,
1993 1992 1991
(Thousands of Dollars)
Balance at end of period:
Banks $4,000 $2,000 $10,500
Commercial paper - 4,000 38,000
Effective annual interest rate
at end of period:
Banks 6.9% (a) 5.9% 5.3%
Commercial paper - 5.9 5.3
Maximum balance during period:
Banks $10,500 $37,500 $25,000
Commercial paper 14,000 47,400 48,280
Average daily balance during period:
Banks $1,800 $3,600 $6,700
Commercial paper 900 8,300 7,200
Effective annual interest rate during
period:
Banks 7.6% (a) 5.5% 6.5%
Commercial paper 9.1 (a) 5.4 6.9
[FN]
(a) Effective rates have been inflated by the commitment
fees being larger than the interest paid for the
year. If the commitment fees were excluded the
effective annual interest rate at end of period
would have been 3.6%. The effective annual interest
rate during period for banks and commercial paper
would have been 3.1% and 3.5%, respectively.
8. COMMITMENTS AND CONTINGENT LIABILITIES:
Commitments under contracts and purchase orders relating to the
Company's program for construction and operation of facilities
amounted to approximately $25,300,000 at December 31, 1993. The
commitments are generally revocable by the Company subject to
reimbursement of manufacturers' expenditures incurred and/or
other termination charges.
The Company is party 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, based upon the advice of legal
counsel, management presently believes that disposition of these
matters will not have a material adverse effect on the Company's
results of operations.
9. BENEFIT PLANS:
Pension Plan - The Company maintains a trusteed noncontributory
defined benefit pension plan for all employees who work 1,000
hours or more during a calendar year. The benefits under the
plan are based on years of service and the employee's final
average earnings. The Company's policy is to fund with an
independent corporate trustee at least the minimum required under
the Employee Retirement Income Security Act of 1974 but not more
than the maximum amount deductible for income tax purposes. The
Company funded $5.0 million in 1993, and $5.1 million in 1992.
The plan's assets held by the trustee consist primarily of listed
stocks (both U.S. and foreign), fixed income securities and
investment grade real estate.
Deferred Compensation Plan - The Company has a nonqualified,
deferred compensation plan for certain senior management
employees and directors that provides for benefit payments over a
fifteen-year period to the participant and his or her family upon
retirement or death. The plan is being funded by life insurance
policies, of which the Company is the beneficiary, with premiums
being paid by the Company and each participant. These policies
have accumulated cash values of $42.4 million and $36.4 million
at December 31, 1993 and 1992, respectively, which do not qualify
as plan assets in the actuarial computation of the funded status.
Based upon SFAS No. 87, Paragraphs 36-38, the Company has
recorded an additional liability of $10.8 million.
The following tables set forth the amounts recognized in the
Company's financial statements and the funded status of both
plans in accordance with accounting standard SFAS No. 87,
"Employers' Accounting for Pensions."
Plan Costs for the Year 1993 1992 1991
(Thousands of Dollars)
Pension plan:
Service cost $ 4,496 $ 3,762 $ 3,440
Interest cost 11,688 10,926 9,848
Actual return on plan assets (23,322) (10,877) (31,871)
Deferred gain (loss) on plan assets 9,848 (1,861) 21,715
Net cost $ 2,710 $ 1,950 $ 3,132
Approximate percentage included in
operating expenses 66% 64% 64%
Net deferred compensation plan costs
charged to other income (including
life insurance and SFAS No. 87
liability accrual)(a) $ 1,372 $ 1,276 $ 959
[FN]
(a) These charges to the Income Statement have been
reduced by gains from the Company-Owned Life
Insurance (COLI) of $1,638,000; $1,607,000; and
$1,663,000 for 1993, 1992 and 1991, respectively.
<TABLE>
<CAPTION>
Funded status and significant assumptions as of December 31:
Deferred
Pension Plan Compensation Plan
1993 1992 1993 1992
(Thousands of Dollars)
<S> <C> <C> <C> <C>
Actuarial present value of benefit
obligations:
Vested benefit obligation $134,292 $113,255 $ 24,024 $ 20,992
Accumulated benefit obligation 139,270 113,601 24,027 20,993
Projected benefit obligation 179,895 145,844 30,114 26,240
Plan assets at fair value 169,920 150,006 - -
Plan assets in excess of (or less
than) projected benefit obligation (9,975) 4,162 (30,114) (26,240)
Unrecognized net (gain) loss from
past experience different from
that assumed 17,295 803 7,295 3,872
Unrecognized prior service cost 1,460 1,788 2,546 2,689
Unrecognized net (asset) obligation
existing at date of initial
adoption (19.5 year straight-line
amortization) (3,019) (3,282) 7,053 7,666
Minimum liability adjustment - - (10,807) (8,980)
Net asset (liability) included in
the balance sheet $ 5,761 $ 3,471 $(24,027) $(20,993)
Discount rate to compute projected
benefit obligation 7.0% 8.25% 7.0% 8.25%
Rate for future compensation
increases 4.5 5.0 4.5 5.0
Expected long-term rate of return
on plan assets 9.0 9.0 - -
</TABLE>
Savings Plan _ The Company has an Employee Savings Plan whereby,
for each $1 of employee contribution up to 6% of their salary the
Company will match 100% of the first 2% employee contribution and
50% of the next 4% employee contribution, all such amounts to be
invested by a trustee to any or all of seven investment options.
The Company's contribution amounted to $2,283,200 in 1993,
$2,046,100 in 1992 and $1,733,300 in 1991. As of December 31,
1993, a total of 3,078,663 common shares were held in this plan.
An additional 955,969 common shares were held by an Employee
Stock Ownership Plan as of December 31, 1993.
Postretirement Benefits _ The Company maintains a defined benefit
postretirement plan (consisting of health care and life
insurance) that covers all employees who were enrolled in the
active group plan at the time of retirement, their spouses and
qualifying dependents. The plan provides for payment of hospital
services, physician services, prescription drugs, dental services
and various other health services, some of which have annual or
lifetime limits, after subtracting payments by Medicare or other
providers and after a stated deductible and co-payments have been
met. Participants become eligible for the benefits if they
retire from the Company after reaching age 55 with 15 years of
service or after 30 years of service. The plan is contributory
with retiree contributions adjusted annually. For those retirees
that were age 65 or older at December 31, 1992 the plan is
noncontributory. The Company also provides life insurance of one
times salary for pre-65 retirees and $20,000 for post-65 retirees
with the retirees paying a portion of the cost.
The Company adopted SFAS No. 106, "Employers' Accounting for
Postretirement Benefits Other Than Pensions" as of January 1,
1993. This new standard requires that the expected costs of
postretirement benefits be charged to expense during the years
that the employees render service. The Company has elected to
amortize the transition obligation of $41.4 million that was
measured as of January 1, 1993 over a period of 20 years.
The following tables set forth the amounts to be recognized in
the Company's financial statements for year-end 1993 and the
funded status of the plan in accordance with accounting standard
SFAS No. 106 as of January 1, 1993 and December 31, 1993
(thousands of dollars).
Postretirement Benefit Cost for
1993:
Service cost $ 750
Interest cost 3,610
Actual return on plan assets (860)
Amortization of transition
obligation 2,040
Net amortization and deferral -
Regulatory asset (3,548)
Net cost $ 1,992 (a)
[FN]
(a) Postretirement benefit costs charged to expense in 1992 and 1991
were $2,622,300 and $2,449,800
December 31, 1993 January 1, 1993
Funded Status:
Accumulated postretirement
benefit obligation (APBO) $(48,290) $(41,400)
Plan assets at fair value 11,840 8,200
APBO in excess of plan assets (36,450) (33,200)
Unrecognized gain/losses 4,670 -
Unrecognized transition obligaton 38,760 40,800
Prepaid postretirement benefit cost $ 6,980 $ 7,600
Discount rate 7.25% 8.5%
Medical and dental inflation rate 6.75 8.0
Long-term plan assets expected 9.0 9.0
return
A one percent change in the medical inflation rate would change
the APBO by five percent and the postretirement expense for 1993
by seven percent.
The Company established a retiree medical benefits funding
program in 1990. This program consists of life insurance
policies on active employees of which the Company is the
beneficiary, and a qualified Voluntary Employees Beneficiary
Association (VEBA) Trust. The net charge to other income for the
life insurance policies was $632,500 in 1993, $1,733,000 in 1992,
and $768,000 in 1991. The funding to the VEBA was $2,692,000 in
1993, $2,977,400 in 1992, and $3,295,400 in 1991 and recorded as
a prepayment. The VEBA trust represents plan assets which are
invested in variable life insurance policies, Trust Owned Life
Insurance (TOLI), on active employees. Inside buildup in the
TOLI policies is tax deferred and tax free if the policy proceeds
are paid to the Trust as death benefits. The investment return
assumption reflects an expectation that investment income in the
VEBA will be substantially tax free.
The IPUC issued an order approving the appropriateness of
applying accrual accounting to postretirement benefit expense for
ratemaking and revenue requirement purposes. The IPUC also
approved the deferral of the difference between the accrual
amount and the pay-as-you-go amount until the Company's next
general rate case subject to an earnings test, but not to exceed
two years or $6,000,000. The Public Utility Commission of Oregon
and the FERC have also approved accrual accounting to
postretirement benefit expense for ratemaking, and FERC has
approved the deferral of the difference between accrual and pay-
as-you-go not to exceed three years. The amount deferred, as a
regulatory asset, at December 31, 1993 is $3.5 million.
Preliminary indications are that the Company will meet the
earnings test prescribed by the IPUC and will be allowed the full
deferral for 1993.
Postemployment Benefits _ The Company provides certain benefits
to former or inactive employees, their beneficiaries, and covered
dependents after employment but before retirement. The Company
has recognized its portion of the cost of providing these
benefits as an expense during the period in which the costs were
incurred.
The Company adopted SFAS No. 112, "Employers' Accounting for
Postemployment Benefits" as of January 1, 1993. The statement
requires accrual of postemployment benefits. These benefits
include salary continuation and related heath care and life
insurance for both long and short-term disability plans,
workmen's compensation and healthcare for surviving spouse and
dependent plan. The adoption of SFAS 112 is a change of
accounting principal; but since the Company is a regulated
utility, a deferred asset was established which represents future
revenue expected to be realized at the time the postemployment
benefits are included in the Company's rates. The Company
recorded a liability and a regulatory asset of $3.9 million which
represents the costs associated with postemployment benefits at
December 31, 1993.
10. JOINTLY-OWNED PROJECTS:
The Company is involved in the ownership and operation of three
jointly-owned generating facilities. The Consolidated Statements
of Income include the Company's proportionate share of direct
operations and maintenance expenses applicable to the projects.
Each facility and extent of Company participation as of December
31, 1993 are as follows:
Company Ownership
Electric Accumulated
Plant In Provision For
Name of Plant Location Service Depreciation % MW
(Thousands of Dollars)
Jim Bridger Rock Springs,
Units 1-4 WY $370,653 $141,515 33 693
Boardman Boardman, OR 58,690 22,233 10 53
Valmy Units 1 & 2 Winnemucca, NV 298,265 90,224 50 261
The Company's wholly-owned subsidiary, IERCO, is a joint venturer
in Bridger Coal Company, which operates the mine supplying coal
for the Jim Bridger steam generation plant. Coal purchased by
the Company from the joint venture amounted to $45,424,000 in
1993, $42,291,000 in 1992 and $40,988,500 in 1991.
INDEPENDENT AUDITORS' REPORT
To the Board of Directors and Shareowners
Idaho Power Company
Boise, Idaho
We have audited the accompanying consolidated financial
statements of Idaho Power Company and its subsidiaries listed
in the accompanying index to financial statements and
financial statement schedules at Item 8. These financial
statements and financial statement schedules are the
responsibility of the Company's management. Our
responsibility is to express an opinion on the financial
statements and financial statement schedules 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 consolidated financial statements present
fairly, in all material respects, the financial position of
Idaho Power Company and subsidiaries at December 31, 1993,
1992 and 1991, and the results of their operations and their
cash flows for each of the years then ended, in conformity
with generally accepted accounting principles. Also, in our
opinion, such financial statement schedules, when considered
in relation to the basic consolidated financial statements
taken as a whole, present fairly in all material respects the
information set forth therein.
As discussed in Notes 2 and 9 to the consolidated financial
statements, the Company changed its method of accounting for
income taxes and postretirement benefits in the year ended
December 31, 1993.
DELOITTE & TOUCHE
Portland, Oregon
January 31, 1994
IDAHO POWER COMPANY
SUPPLEMENTAL FINANCIAL INFORMATION, UNAUDITED
QUARTERLY FINANCIAL DATA:
The following unaudited information is presented for each quarter of
1993, 1992 and 1991 (in thousands of dollars, except for per share
amounts). In the opinion of the Company, all adjustments necessary
for a fair statement of such amounts for such periods have been
included. The results of operation for the interim periods are not
necessarily indicative of the results to be expected for the full
year. Accordingly, earnings information for any three month period
should not be considered as a basis for estimating operating results
for a full fiscal year. Amounts are based upon quarterly statements
and the sum of the quarters may not equal the annual amount
reported.
<TABLE>
<CAPTION>
Quarter Ended
March 31 June 30 September 30 December 31
<S> <C> <C> <C> <C>
1993
Revenues $140,809 $129,471 $134,577 $135,545
Income from operations 41,479 38,980 34,286 47,201
Income taxes 10,610 9,270 9,108 7,486
Net income 21,347 18,524 16,427 28,166
Dividends on preferred stock 1,345 1,318 1,565 1,781
Earnings on common stock 20,002 17,206 14,862 26,385
Earnings per share of common stock 0.55 0.47 0.40 0.71
1992
Revenues 114,453 124,656 129,050 129,934
Income from operations 31,024 30,376 29,593 33,962
Income taxes 7,396 6,670 4,353 4,743
Net income 13,378 12,394 15,067 19,152
Dividends on preferred stock 1,424 1,400 1,346 1,347
Earnings on common stock 11,954 10,994 13,721 17,805
Earnings per share of common stock 0.35 0.32 0.38 0.49
1991
Revenues 120,589 110,877 129,584 122,142
Income from operations 34,855 25,526 35,234 30,849
Income taxes 7,935 4,002 8,231 977
Net income 15,781 9,980 16,729 15,381
Dividends on preferred stock 1,069 1,067 1,067 1,700
Earnings on common stock 14,712 8,913 15,662 13,681
Earnings per share of common stock 0.43 0.26 0.46 0.40
</TABLE>
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON
ACCOUNTING AND FINANCIAL DISCLOSURE
None
PART III
Part III has been omitted because the registrant will file a
definitive proxy statement pursuant to Regulation 14A, which
involves the election of Directors, with the Commission within
120 days after the close of the fiscal year portions of which are
hereby incorporated by reference (except for information with
respect to executive officers which is set forth in Part I
hereof).
PART IV
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES
AND REPORTS ON FORM 8-K
(a) Please refer to Item 8, "Financial Statements and
Supplementary Data" for a complete listing of all
consolidated financial statements and financial statement
schedules.
(b) Reports on SEC Form 8-K. The following report on Form 8-K
was filed during the three months ended December 31, 1993.
Items Reported Date of Report
1. Item 7, Financial Statements and Exhibits December 17, 1993
(Exhibits)
(c) Exhibits.
* Previously Filed and Incorporated Herein by Reference
File As
Exhibit Number Exhibit
*3(a) 33-00440 4(a)(xiii) Restated Articles of
Incorporation of the Company as
filed with the Secretary of State
of Idaho on June 30, 1989.
*3(a)(i) 33-65720 4(a)(i) Statement of Resolution
Establishing Terms of 8.375%
Serial Preferred Stock, Without
Par Value (cumulative stated
value of $100 per share), as
filed with the Secretary of State
of Idaho on September 23, 1991.
*3(a)(ii) 33-65720 4(a)(ii) Statement of Resolution
Establishing Terms of Flexible
Auction Series A, Serial
Preferred Stock, Without Par
Value (cumulative stated value of
$100,000 per share), as filed
with the Secretary of State of
Idaho on November 5, 1991.
*3(a)(iii) 33-65720 4(a)(iii) Statement of Resolution
Establishing Terms of 7.07%
Serial Preferred Stock, Without
Par Value (cumulative stated
value of $100 per share), as
filed with the Secretary of State
of Idaho on June 30, 1993.
*3(b) 33-41166 4(b) Waiver resolution to Restated
Articles of Incorporation adopted
by Shareholders on May 1, 1991.
*3(c) 33-00440 4(a)(xiv) By-laws of the Company amended on
June 30, 1989, and presently in
effect.
*4(a)(i) 2-3413 B-2 Mortgage and Deed of Trust, dated
as of October 1, 1937, between
the Company and Bankers Trust
Company and R. G. Page, as
Trustees.
*4(a)(ii) Supplemental Indentures to
Mortgage and Deed of Trust:
Number Dated
1-MD B-2-a First July 1, 1939
2-5395 7-a-3 Second November 15, 1943
2-7237 7-a-4 Third February 1, 1947
2-7502 7-a-5 Fourth May 1, 1948
2-8398 7-a-6 Fifth November 1, 1949
2-8973 7-a-7 Sixth October 1, 1951
2-12941 2-C-8 Seventh January 1, 1957
2-13688 4-J Eighth July 15, 1957
2-13689 4-K Ninth November 15, 1957
2-14245 4-L Tenth April 1, 1958
2-14366 2-L Eleventh October 15, 1958
2-14935 4-N Twelfth May 15, 1959
2-18976 4-O Thirteenth November 15, 1960
2-18977 4-Q Fourteenth November 1, 1961
2-22988 4-B-16 Fifteenth September 15, 1964
2-24578 4-B-17 Sixteenth April 1, 1966
2-25479 4-B-18 Seventeenth October 1, 1966
2-45260 2(c) Eighteenth September 1, 1972
2-49854 2(c) Nineteenth January 15, 1974
2-51722 2(c)(i) Twentieth August 1, 1974
2-51722 2(c)(ii) Twenty-first October 15, 1974
2-57374 2(c) Twenty-second November 15, 1976
2-62035 2(c) Twenty-third August 15, 1978
33-34222 4(d)(iii) Twenty-fourth September 1, 1979
33-34222 4(d)(iv) Twenty-fifth November 1, 1981
33-34222 4(d)(v) Twenty-sixth May 1, 1982
33-34222 4(d)(vi) Twenty-seventh May 1, 1986
33-00440 4(c)(iv) Twenty-eighth June 30, 1989
33-34222 4(d)(vii) Twenty-ninth January 1, 1990
33-65720 4(d)(iii) Thirtieth January 1, 1991
33-65720 4(d)(iv) Thirty-first August 15, 1991
33-65720 4(d)(v) Thirty-second March 15, 1992
33-65720 4(d)(vi) Thirty-third April 16, 1993
1-3198 4 Thirty-fourth December 1, 1993
Form 8-K
Dated
12/17/93
*4(b) Instruments relating to American
Falls bond guarantee. (See
Exhibits 10(f) and 10(f)(i)).
*4(c) 33-65720 4(f) Agreement to furnish certain debt
instruments.
*4(d) 33-00440 2(a)(iii) Agreement and Plan of Merger
dated March 10, 1989, between
Idaho Power Company, a Maine
Corporation, and Idaho Power
Migrating Corporation.
*4(e) 33-65720 4(e) Rights Agreement dated
January 11, 1990, between the
Company and First Chicago Trust
Company of New York, as Rights
Agent (The Bank of New York,
successor Rights Agent).
*10(a) 2-51762 5(a) Agreement, dated April 20, 1973,
between the Company and FMC
Corporation.
*10(a)(i) 2-57374 5(b) Letter Agreement, dated
October 22, 1975, relating to
agreement filed as Exhibit 10(a).
*10(a)(ii) 2-62034 5(b)(i) Letter Agreement, dated
December 22, 1976, relating to
agreement filed as Exhibit 10(a).
*10(a)(iii) 33-65720 10(a) Letter Agreement, dated
December 11, 1981, relating to
agreement filed as Exhibit 10(a).
*10(b) 2-49584 5(b) Agreements, dated September 22,
1969, between the Company and
Pacific Power & Light Company
relating to the operation,
construction and ownership of the
Jim Bridger Project.
*10(b)(i) 2-51762 5(c) Amendment, dated February 1,
1974, relating to operation
agreement filed as Exhibit 10(b).
*10(c) 2-49584 5(c) Agreement, dated as of
October 11, 1973, between the
Company and Pacific Power & Light
Company.
*10(d) 2-49584 5(d) Agreement, dated as of
October 24, 1973, between the
Company and Utah Power & Light
Company.
*10(d)(i) 2-62034 5(f)(i) Amendment, dated January 25,
1978, relating to agreement filed
as Exhibit 10(d).
*10(e) 33-65720 10(b) Coal Purchase Contract, dated as
of June 19, 1986, among the
Company, Sierra Pacific Power
Company and Black Butte Coal
Company.
*10(f) 2-57374 5(k) Contract, dated March 31, 1976,
between the United States of
America and American Falls
Reservoir District, and related
Exhibits.
*10(f)(i) 33-65720 10(c) Guaranty Agreement, dated
March 1, 1990, between the
Company and West One Bank, as
Trustee, relating to $21,425,000
American Falls Replacement Dam
Bonds of the American Falls
Reservoir District, Idaho.
*10(g) 2-57374 5(m) Agreement, effective April 15,
1975, between the Company and The
Washington Water Power Company.
*10(h) 2-62034 5(p) Bridger Coal Company Agreement,
dated February 1, 1974, between
Pacific Minerals, Inc., and Idaho
Energy Resources Co.
*10(i) 2-62034 5(q) Coal Sales Agreement, dated
February 1, 1974, between Bridger
Coal Company and Pacific Power &
Light Company and the Company.
*10(i)(i) 33-65720 10(d) Second Restated and Amended Coal
Sales Agreement, dated March 7,
1988, among Bridger Coal Company
and PacifiCorp (dba Pacific
Power & Light Company) and the
Company.
*10(j) 2-62034 5(r) Guaranty Agreement, dated as of
August 30, 1974, with Pacific
Power & Light Company.
*10(k) 2-56513 5(i) Letter Agreement, dated January
23, 1976, between the Company and
Portland General Electric
Company.
*10(k)(i) 2-62034 5(s) Agreement for Construction,
Ownership and Operation of the
Number One Boardman Station on
Carty Reservoir, dated as of
October 15, 1976, between
Portland General Electric Company
and the Company.
*10(k)(ii) 2-62034 5(t) Amendment, dated September 30,
1977, relating to agreement filed
as Exhibit 10(k).
*10(k)(iii) 2-62034 5(u) Amendment, dated October 31,
1977, relating to agreement filed
as Exhibit 10(k).
*10(k)(iv) 2-62034 5(v) Amendment, dated January 23,
1978, relating to agreement filed
as Exhibit 10(k).
*10(k)(v) 2-62034 5(w) Amendment, dated February 15,
1978, relating to agreement filed
as Exhibit 10(k).
*10(k)(vi) 2-68574 5(x) Amendment, dated September 1,
1979, relating to agreement filed
as Exhibit 10(k).
*10(l) 2-68574 5(z) Participation Agreement, dated
September 1, 1979, relating to
the sale and leaseback of coal
handling facilities at the Number
One Boardman Station on Carty
Reservoir.
*10(m) 2-64910 5(y) Agreements for the Operation,
Construction and Ownership of the
North Valmy Power Plant Project,
dated December 12, 1978, between
Sierra Pacific Power Company and
the Company.
*10(n)1 33-65720 10(e) Nonqualified, deferred,
compensation plan for certain
senior management employees and
directors of the Company.
*10(o) 33-65720 10(f) Residential Purchase and Sale
Agreement, dated August 22, 1981,
among the United Stated of
America Department of Energy
acting by and through the
Bonneville Power Administration,
and the Company.
*10(p) 33-65720 10(g) Power Sales Contact, dated
August 25, 1981, including
amendments, among the United
States of America Department of
Energy acting by and through the
Bonneville Power Administration,
and the Company.
*10(q) 33-65720 10(h) Framework Agreement, dated
October 1, 1984, between the
State of Idaho and the Company
relating to the Company's Swan
Falls and Snake River water
rights.
*10(q)(i) 33-65720 10(h)(i) Agreement, dated October 25,
1984, between the State of Idaho
and the Company relating to the
agreement filed as Exhibit 10(q).
*10(q)(ii) 33-65720 10(h)(ii) Contract to Implement, dated
October 25, 1984, between the
State of Idaho and the Company
relating to the agreement filed
as Exhibit 10(q).
*10(r) 33-65720 10(i) Agreement for Supply of Power and
Energy, dated February 10, 1988,
between the Utah Associated
Municipal Power Systems and the
Company.
*10(s) 33-65720 10(j) Agreement Respecting Transmission
Facilities and Services, dated
March 21, 1988 among PC/UP&L
Merging Corp. and the Company
including a Settlement Agreement
between PacifiCorp and the
Company.
*10(s)(i) 33-65720 10(j)(i) Restated Transmission Services
Agreement, dated February 6,
1992, between Idaho Power Company
and PacifiCorp.
[FN]
___________________
1 Compensatory Plan
*10(t) 33-65720 10(k) Agreement for Supply of Power and
Energy, dated February 23, 1989,
between Sierra Pacific Power
Company and the Company.
*10(u) 33-65720 10(l) Transmission Services Agreement,
dated May 18, 1989, between the
Company and the Bonneville Power
Administration.
*10(v) 33-65720 10(m) Agreement Regarding the
Ownership, Construction,
Operation and Maintenance of the
Milner Hydroelectric Project
(FERC No. 2899), dated January
22, 1990, between the Company and
the Twin Falls Canal Company and
the Northside Canal Company
Limited.
*10(v)(i) 33-65720 10(m)(i) Guaranty Agreement, dated
February 10, 1992, between the
Company and New York Life
Insurance Company, as Note
Purchaser, relating to
$11,700,000 Guaranteed Notes due
2017 of Milner Dam Inc.
*10(w) 33-65720 10(n) Agreement for the Purchase and
Sale of Power and Energy, dated
October 16, 1990, between the
Company and The Montana Power
Company.
12 Statement Re: Computation of
Ratio of Earnings to Fixed
Charges.
12(a) Statement Re: Computation of
Supplemental Ratio of Earnings to
Fixed Charges.
12(b) Statement Re: Computation of
Ratio of Earnings to Combined
Fixed Charges and Preferred
Dividend Requirements.
12(c) Statement Re: Computation of
Supplemental Ratio of Earnings to
Combined Fixed Charges and
Preferred Dividend Requirements.
21 Subsidiaries of Registrant.
23 Independent Auditors' Consent.
<TABLE> IDAHO POWER COMPANY
<CAPTION> SCHEDULE V - CONSOLIDATED PROPERTY, PLANT AND EQUIPMENT
Column A Column B Column C Column D Column E Column F
Balance at Balance at
Beginning Additions End
of at Other Changes of Period
Classification Period Cost (1) Retirements Transfers Other (2)
<S> <C> <C> <C> <C> <C> <C>
Year Ended December 31, 1993 (Thousands of Dollars)
Electric utility plant
classified by prescribed
accounts, at original cost:
Intangible plant $ 4,930 $ 1,863 $ 234 $ (24) $ - $ 6,535
Production plant:
Straight line 1,006,956 15,426 10,498 (17) - 1,011,867
5% present worth 187,192 129 - - - 187,321
Total 1,194,148 15,555 10,498 (17) - 1,199,188
Transmission plant:
Straight line 315,972 4,269 1,287 1,017 - 319,971
5% present worth 8,250 28 - - - 8,278
Total 324,222 4,297 1,287 1,017 - 328,249
Distribution plant 545,490 43,294 5,137 (1,043) - 582,604
General plant:
Straight line 130,154 6,626 3,519 67 - 133,328
5% present worth 257 16 - - - 273
Total 130,411 6,642 3,519 67 - 133,601
Plant held for future use 3,083 (125) - - - 2,958
Construction work in progress 66,997 25,685 - - - 92,682
Acquisition Adjustment
(Prairie Power) (454) - - - - (454)
Total electric utility plant $2,268,827 $97,211 $20,675 $ - $ - $2,345,363
<FN>
Note (1): Additions at cost include completed projects
transferred from construction work in progress
and the amount of construction work in progress
additions (deductions) represents the net
changes for that account.
(2): Five percent present worth balances are as of
March 31, 1993. Effective April 1, 1993 all electric
utility plant is classified as straight-line due
to a change in depreciation methodology.
</TABLE>
<TABLE> IDAHO POWER COMPANY
<CAPTION> SCHEDULE V - CONSOLIDATED PROPERTY, PLANT AND EQUIPMENT
Column A Column B Column C Column D Column E Column F
Balance at
Beginning Additions Balance at
of at Other Changes End
Classification Period Cost (1) Retirements Transfers Other of Period
<S> <C> <C> <C> <C> <C> <C>
Year Ended December 31, 1992 (Thousands of Dollars)
Electric utility plant
classified
by prescribed accounts, at
original cost:
Intangible plant $ 3,695 $ 1,297 $ 62 $ - $ - $ 4,930
Production plant:
Straight line 956,029 55,873 4,946 - - 1,006,956
5% present worth 184,041 3,236 71 (14) - 187,192
Total 1,140,070 59,109 5,017 (14) - 1,194,148
Transmission plant:
Straight line 307,498 8,900 951 525 - 315,972
5% present worth 8,244 9 3 - - 8,250
Total 315,742 8,909 954 525 - 324,222
Distribution plant 513,467 38,401 5,829 (549) - 545,490
General plant:
Straight line 121,382 15,479 6,743 36 - 130,154
5% present worth 255 - - 2 - 257
Total 121,637 15,479 6,743 38 - 130,411
Plant held for future use 3,060 23 - - - 3,083
Construction work in progress 70,841 (3,844) - - - 66,997
Acquisition adjustment
(Prairie Power) - (454) - - - (454)
Total electric utility plant $2,168,512 $118,920 $18,605 $ - $ - $2,268,827
<FN>
Note (1): Additions at cost include completed projects
transferred from construction work in progress
and the amount of construction work in progress
additions (deductions) represents the net
changes for that account.
</TABLE>
<TABLE> IDAHO POWER COMPANY
<CAPTION> SCHEDULE V - CONSOLIDATED PROPERTY, PLANT AND EQUIPMENT
Column A Column B Column C Column D Column E Column F
Balance at
Beginning Additions Balance at
of at Other Changes End
Classification Period Cost (1) Retirements Transfers Other of Period
<S> <C> <C> <C> <C> <C> <C>
Year Ended December 31, 1991 (Thousands of Dollars)
Electric utility plant
classified by prescribed a
ccounts, at original cost:
Intangible plant $ 3,430 $ 299 $ 34 $ - $ - $ 3,695
Production plant:
Straight line 940,289 19,732 4,004 12 - 956,029
5% present worth 183,142 935 31 (5) - 184,041
Total 1,123,431 20,667 4,035 7 - 1,140,070
Transmission plant:
Straight line 297,158 11,148 637 (171) - 307,498
5% present worth 8,025 278 43 (16) - 8,244
Total 305,183 11,426 680 (187) - 315,742
Distribution plant 483,050 34,784 4,559 192 - 513,467
General plant:
Straight line 90,758 33,071 2,438 (9) - 121,382
5% present worth 259 (1) - (3) - 255
Total 91,017 33,070 2,438 (12) - 121,637
Plant held for future use 3,060 - - - - 3,060
Construction work in progress 35,192 35,658 - (9) - 70,841
Total electric utility plant $2,044,363 $135,904 $11,746 $ (9) $ - $2,168,512
<FN>
Note (1): Additions at cost include completed projects
transferred from construction work in progress
and the amount of construction work in progress
additions (deductions) represents the net
changes for that account.
</TABLE>
<TABLE> Idaho Power Company
<CAPTION> Schedule VI - Consolidated Accumulated Depreciation and Amortization of
Property, Plant and Equipment
Column A Column B Column C Column D Column E Column F
Additions
Balance At Charged Charged To Deductions Other Balance At
Beginning To Other Cost of Changes End Of
Classification Of Period Income Accounts(1) Retirements Removal Salvage (2)(3) Period
<S> <C> <C> <C> <C> <C> <C> <C> <C>
Year Ended December 31, 1993 (Thousands of Dollars)
Accumulated provision for
depreciation and amortization
of electric utility plant
shown in Schedule V:
Intangible $ 2,325 $ 532 $ - $ 234 $ - $ - $ - $ 2,623
Production:
Straight line 329,584 31,006 138 10,497 664 (8,258) (6,626) 351,199
5% present worth 39,088 601 - - 2 - - 39,687
Total 368,672 31,607 138 10,497 666 (8,258) (6,626) 390,886
Transmission:
Straight line 105,983 7,196 - 1,276 480 (27) 1,767 113,217
5% present worth 4,311 77 - - - - - 4,388
Total 110,294 7,273 - 1,276 480 (27) 1,767 117,605
Distribution 169,077 18,225 - 5,136 1,320 (491) 6,747 188,084
General:
Straight line 32,740 4,503 2,161 3,520 295 (527) (6,303) 29,813
5% present worth 233 2 - - - - (235) 0
Total 32,973 4,505 2,161 3,520 295 (527) (6,538) 29,813
Amortization of Acquistition
Adj. (Prairie Power) (9) (23) - - - - - (32)
Total $683,332 $62,119 $2,299 $20,663 $2,761 $(9,303) $(4,650) $728,979
<FN>
Note (1): Represents amounts charged to transportation and communication
clearing accounts which are distributed to other accounts on
the basis of the use of the equipment and amounts charged to
A/c 151 - Fuel Stock for Jim Bridger and Boardman coal railcars.
(2): For 1993 includes damage claims, up and down costs, relocation
costs, reserve transfers, Wood River Gas Turbine sale proceeds,
Bald Mountain Distribution Facilities sale proceeds, customer
off-street lighting conversion program undepreciated costs
and reserve allocation adjustment between all transmission,
distribution and general accounts.
(3): Five percent present worth balances are as of March 31, 1993.
Effective April 1, 1993 all accumulated depreciation and
amortization is classified as straight-line due to a change in
depreciation methodology.
</TABLE>
<TABLE> Idaho Power Company
<CAPTION> Schedule VI - Consolidated Accumulated Depreciation and Amortization of
Property, Plant and Equipment
Column A Column B Column C Column D Column E Column F
Additions
Balance At Charged Charged To Deductions Other Balance At
Beginning To Other Cost of Changes End Of
Classification Of Period Income Accounts(1) Retirements Removal Salvage (2) Period
<S> <C> <C> <C> <C> <C> <C> <C> <C>
Year Ended December 31, 1992
(Thousands of Dollars)
Accumulated provision for
depreciation and amortization
of electric utility plant
shown in Schedule V:
Intangible $ 2,071 $ 316 $ - $ 62 $ - $ - $ - $ 2,325
Production:
Straight line 305,284 29,059 140 4,745 149 (5) (10) 329,584
5% present worth 36,712 2,459 - 71 12 - - 39,088
Total 341,996 31,518 140 4,816 161 (5) (10) 368,672
Transmission:
Straight line 100,418 6,577 - 946 712 (31) 615 105,983
5% present worth 4,030 293 - 3 1 - (8) 4,311
Total 104,448 6,870 - 949 713 (31) 607 110,294
Distribution 158,420 16,596 - 5,786 1,350 (425) 772 169,077
General:
Straight line 32,077 4,589 2,054 6,715 63 (647) 151 32,740
5% present worth 226 8 - - - - (1) 233
Total 32,303 4,597 2,054 6,715 63 (647) 150 32,973
Amortization of acquisition
adjustment (Prairie Power) - (9) - - - - - (9)
Total $639,238 $59,888 $2,194 $18,328 $2,287 $(1,108) $1,519 $683,332
<FN>
Note (1): Represents amounts charged to transportation and communication
clearing accounts which are distributed to other accounts on
the basis of the use of the equipment and amounts charged to
A/c 151 - Fuel Stock for Jim Bridger and Boardman coal railcars.
(2): Includes damage claims, up & down costs, relocation
reimbursements, accumulated reserve transfers, and Prairie
Power Co-op, Inc. (purchased in 1992) accumulated depreciation.
</TABLE>
<TABLE> Idaho Power Company
<CAPTION> Schedule VI - Consolidated Accumulated Depreciation and Amortization of
Property, Plant and Equipment
Column A Column B Column C Column D Column E Column F
Additions
Balance At Charged Charged To Deductions Other Balance At
Beginning To Other Cost of Changes End Of
Classification Of Period Income Accounts (1) Retirements Removal Salvage (2) Period
<S> <C> <C> <C> <C> <C> <C> <C> <C>
Year Ended December 31, 1991
(Thousands of Dollars)
Accumulated provision for
depreciation and amortization
of electric utility plant
shown
in Schedule V:
Intangible $ 1,838 $ 267 $ - $ 34 $ - $ - $ - $ 2,071
Production:
Straight line 280,559 29,168 16 4,004 473 (20) (2) 305,284
5% present worth 34,665 2,077 - 31 2 (23) 2 36,712
Total 315,224 31,245 16 4,035 497 (43) - 341,996
Transmission:
Straight line 95,322 6,332 - 637 579 (85) (105) 100,418
5% present worth 3,787 279 - 43 (7) - - 4,030
Total 99,109 6,611 - 680 572 (85) (105) 104,448
Distribution 147,610 15,695 - 4,559 1,320 (501) 493 158,420
General:
Straight line 28,572 3,772 1,929 2,438 89 (331) - 32,077
5% present worth 219 7 - - - - - 226
Total 28,791 3,779 1,929 2,438 89 (331) - 32,303
Total $592,572 $57,597 $1,945 $11,746 $2,478 $(960) $388 $639,238
<FN>
Note (1): Represents amounts charged to transportation and communication
clearing accounts which are distributed to other accounts on
the basis of the use of the equipment.
(2): For 1991 includes damage claims, up and down costs, relocation
reimbursements and accumulated reserve transfers.
</TABLE>
<TABLE> IDAHO POWER COMPANY
<CAPTION> SCHEDULE VIII - CONSOLIDATED VALUATION AND QUALIFYING ACCOUNTS
Years Ended December 31, 1993, 1992 and 1991
Column C
Column A Column B Additions Column D Column E
Balance
Balance Charged Charged At
At to (Credited) Deductions End Of
Classification Beginning Income to Other Period
Of Period Accounts (1)
(Thousands of Dollars)
<S> <C> <C> <C> <C> <C>
1993:
Reserves Deducted From
Applicable Assets:
Reserve for
uncollectible
accounts $1,421 $1,174 $1,001(2) $2,219 $1,377
Other Reserves:
Injuries and damages
reserve $1,500 $2,820 $ - $2,820 $1,500
Miscellaneous
operating reserves $ - $ 870 $ 332 $ 454 $ 748
1992:
Reserves Deducted From
Applicable Assets:
Reserve for
uncollectible
accounts $1,300 $1,224 $ 963(2) $2,066 $1,421
Other Reserves:
Injuries and damages
reserve $1,366 $2,468 $ - $2,334 $1,500
1991:
Reserves Deducted From
Applicable Assets:
Reserve for
uncollectible
accounts $1,290 $1,217 $1,224(2) $2,431 $1,300
Other Reserves:
Injuries and damages
reserve $3,086 $3,996 $ - $5,716 $1,366
Miscellaneous
operating reserves $1,250 $ - $1,892 $3,142 $ -
<FN>
NOTES: (1) Represents deductions from the reserves for purposes
for which the reserves were created.
(2) Represents collections of accounts previously written
off.
</TABLE>
IDAHO POWER COMPANY
SCHEDULE X - CONSOLIDATED SUPPLEMENTARY INCOME
STATEMENT INFORMATION
Column A Column B
Charged to Costs
and Expenses
Year Ended December 31,
Item 1993 1992 1991
(Thousands of Dollars)
Taxes other than income taxes are as
follows:
Property $16,168 $15,467 $15,081
State kilowatt-hour 1,834 1,158 1,273
Social security and unemployment 5,814 5,564 5,197
Miscellaneous 1,129 1,793 1,807
Total $24,945 $23,982 $23,358
Charged to:
Operating expenses - taxes $22,129 $20,562 $21,170
Other income 41 54 30
Construction, clearing and sundry 2,775 3,366 2,158
Total $24,945 $23,982 $23,358
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the
Securities Exchange Act of 1934, the Registrant has duly caused
this report to be signed on its behalf by the undersigned,
thereunto duly authorized.
IDAHO POWER COMPANY
(Registrant)
March 10, 1994 By:__/s/ __Joseph W.Marshall__
Joseph W. Marshall
Chairman of the Board and
Chief Executive Officer and Director
Pursuant to the requirements of the Securities Exchange Act of
1934, this report is signed below by the following persons on
behalf of the Registrant and in the capacities and on the dates
indicated.
By:__/s/__Joseph W. Marshall__ Chairman of the Board and March 10, 1994
Joseph W. Marshall Chief Executive Officer
and Director
By:__/s/__Larry R. Gunnoe__ President and Chief Operating "
Larry R. Gunnoe Officer and Director
By:__/s/__J. LaMont Keen___ Vice President and Chief Financial "
J. LaMont Keen Officer (Principal Financial
Officer)
By:__/s/__Harold J. Hochhalter_ Controller and Chief Accounting
Officer "
Harold J. Hochhalter (Principal Accounting Officer)
By:__/s/__Robert D. Bolinder__ By:__/s/__Evelyn Loveless__ "
Robert D. Bolinder Evelyn Loveless
Director Director
By:__/s/__Roger L. Breezley__ By:__/s/__James A. McClure__ "
Roger L. Breezley James A. McClure
Director Director
By:__/s/__John B. Carley__ By:__/s/__ Jon H. Miller__ "
John B. Carley Jon H. Miller
Director Director
By:__/s/__George L. Coiner__ By:__/s/__Richard T. Norman__ "
George L. Coiner Richard T. Norman
Director Director
By:__/s/__Gene C. Rose__ By:__/s/__Phil Soulen__ "
Gene C. Rose Phil Soulen
Director Director
By:__/s/__Peter T. Johnson__ "
Peter T. Johnson
Director
EXHIBIT INDEX
Exhibit Page
Number Number
12 Statement Re: Computation of Ratio of 99
Earnings to Fixed Charges.
12(a) Statement Re: Computation of 100
Supplemental Ratio of Earnings to Fixed
Charges.
12(b) Statement Re: Computation of Ratio of 101
Earnings to Combined Fixed Charges and
Preferred Dividend Requirements.
12(c) Statement Re: Computation of 102
Supplemental Ratio of Earnings to
Combined Fixed Charges and Preferred
Dividend Requirements.
21 Subsidiaries of Registrant. 103
23 Independent Auditors' Consent. 104
<TABLE> Idaho Power Company
<CAPTION> Consolidated Financial Information
Ratio of Earnings to Fixed Charges
Twelve Months Ended December 31,
(Thousands of Dollars)
1989 1990 1991 1992 1993
<S> <C> <C> <C> <C> <C>
Computation of Ratio of Earnings to
Fixed Charges:
Consolidated net income $ 84,737 $ 69,241 $ 57,872 $ 59,990 $ 84,464
Income taxes:
Income taxes (includes amounts charged
to other income and deductions) 45,336 26,418 24,321 24,601 38,057
Investment tax credit adjustment (3,295) (3,184) (3,177) (1,439) (1,583)
Total income taxes 42,041 23,234 21,144 23,162 36,474
Income before income taxes 126,778 92,475 79,016 83,152 120,938
Fixed Charges:
Interest on long-term debt 49,629 50,119 54,370 53,408 53,706
Amortization of debt discount,
expense and premium - net 238 309 374 392 507
Interest on short-term bank loans 2,200 1,027 935 647 220
Other interest 3,164 2,259 3,297 1,011 2,023
Interest portion of rentals 757 902 884 683 1,077
Total fixed charges 55,988 54,616 59,860 56,141 57,533
Earnings - as defined $182,766 $147,091 $138,876 $139,293 $178,471
Ratio of earnings to fixed charges 3.26X 2.69X 2.32X 2.48X 3.10X
</TABLE>
<TABLE> Idaho Power Company
<CAPTION> Consolidated Financial Information
Supplemental Ratio of Earnings to Fixed Charges
Twelve Months Ended December 31,
(Thousands of Dollars)
1989 1990 1991 1992 1993
<S> <C> <C> <C> <C> <C>
Computation of Ratio of Earnings to
Fixed Charges:
Consolidated net income $ 84,737 $ 69,241 $ 57,872 $ 59,990 $ 84,464
Income taxes:
Income taxes (includes amounts charged
to other income and deductions) 45,336 26,418 24,321 24,601 38,057
Investment tax credit adjustment (3,295) (3,184) (3,177) (1,439) (1,583)
Total income taxes 42,041 23,234 21,144 23,162 36,474
Income before income taxes 126,778 92,475 79,016 83,152 120,938
Fixed Charges:
Interest on long-term debt 49,629 50,119 54,370 53,408 53,706
Amortization of debt discount,
expense and premium - net 238 309 374 392 507
Interest on short-term bank loans 2,200 1,027 935 647 220
Other interest 3,164 2,259 3,297 1,011 2,023
Interest portion of rentals 757 902 884 683 1,077
Total fixed charges 55,988 54,616 59,860 56,141 57,533
Suppl increment to fixed charges* 2,321 1,969 1,599 2,487 2,631
Total supplemental fixed charges 58,309 56,585 61,459 58,628 60,164
Supplemental earnings - as defined $185,087 $149,060 $140,475 $141,780 $181,102
Supplemental ratio of earnings to fixed
charges 3.17X 2.63X 2.29X 2.42X 3.01X
<FN>
* Explanation of increment:
Interest on the quaranty of American Falls Reservoir District Bonds
and Milner Dam Inc Notes which are already included in operating
expense.
</TABLE>
<TABLE> Idaho Power Company
<CAPTION> Consolidated Financial Information
Ratio of Earnings to Combined Fixed Charges and Preferred Dividend Requirements
Twelve Months Ended December 31,
(Thousands of Dollars)
1989 1990 1991 1992 1993
<S> <C> <C> <C> <C> <C>
Computation of Ratio of Earnings to
Fixed Charges:
Consolidated net income $ 84,737 $ 69,241 $ 57,872 $ 59,990 $ 84,464
Income taxes:
Income taxes (includes amounts charged
to other income and deductions) 45,336 26,418 24,321 24,601 38,057
Investment tax credit adjustment (3,295) (3,184) (3,177) (1,439) (1,583)
Total income taxes 42,041 23,234 21,144 23,162 36,474
Income before income taxes 126,778 92,475 79,016 83,152 120,938
Fixed Charges:
Interest on long-term debt 49,629 50,119 54,370 53,408 53,706
Amortization of debt discount,
expense and premium - net 238 309 374 392 507
Interest on short-term bank loans 2,200 1,027 935 647 220
Other interest 3,164 2,259 3,297 1,011 2,023
Interest portion of rentals 757 902 884 683 1,077
Total fixed charges 55,988 54,616 59,860 56,141 57,533
Preferred dividend requirements 6,374 5,685 6,663 7,611 8,547
Total fixed charges and
preferred dividends 62,362 60,301 66,523 63,752 66,080
Earnings - as defined $182,766 $147,091 $138,876 $139,293 $178,471
Ratio of earnings to fixed charges
preferred dividends 2.93X 2.44X 2.09X 2.18X 2.70X
</TABLE>
<TABLE> Idaho Power Company
<CAPTION> Consolidated Financial Information
Supplemental Ratio of Earnings to Combined Fixed Charges and Preferred Dividend
Requirements
Twelve Months Ended December 31,
(Thousands of Dollars)
1989 1990 1991 1992 1993
<S> <C> <C> <C> <C> <C>
Computation of Ratio of Earnings to
Fixed Charges:
Consolidated net income $ 84,737 $ 69,241 $ 57,872 $ 59,990 $ 84,464
Income taxes:
Income taxes (includes amounts charged
to other income and deductions) 45,336 26,418 24,321 24,601 38,057
Investment tax credit adjustment (3,295) (3,184) (3,177) (1,439) (1,583)
Total income taxes 42,041 23,234 21,144 23,162 36,474
Income before income taxes 126,778 92,475 79,016 83,152 120,938
Fixed Charges:
Interest on long-term debt 49,629 50,119 54,370 53,408 53,706
Amortization of debt discount,
expense and premium - net 238 309 374 392 507
Interest on short-term bank loans 2,200 1,027 935 647 220
Other interest 3,164 2,259 3,297 1,011 2,023
Interest portion of rentals 757 902 884 683 1,077
Total fixed charges 55,988 54,616 59,860 56,141 57,533
Suppl increment to fixed charges* 2,321 1,969 1,599 2,487 2,631
Supplemental fixed charges 58,309 56,585 61,459 58,628 60,164
Preferred dividend requirements 6,374 5,685 6,663 7,611 8,547
Total supplemental fixed charges
and preferred dividends 64,683 62,270 68,122 66,239 68,711
Supplemental earnings - as defined $185,087 $149,060 $140,475 $141,780 $181,102
Supplemental ratio of earnings to fixed
charges and preferred dividends 2.86X 2.39X 2.06X 2.14X 2.64X
<FN>
* Explanation of increment:
Interest on the quaranty of American Falls Reservoir District Bonds
and Milner Dam Inc Notes which are already included in operating expense.
</TABLE>
SUBSIDIARIES OF REGISTRANT
1. Idaho Energy Resources Co., a Wyoming Corporation
2. Idaho Utility Products Company, an Idaho Corporation
3. IDACORP, INC., an Idaho Corporation
4. Ida-West Energy Company, an Idaho Corporation
INDEPENDENT AUDITORS' CONSENT
We consent to the incorporation by reference in Registration
Statement Nos. 33-65720 and 33-51215 of Idaho Power Company on
Form S-3; and Post-Effective Amendment No. 1 to Registration
Statement No. 2-99567 and Registration Statement No. 33-36947 of
Idaho Power Company on Form S-8 of our report dated January 31,
1994 appearing in this Annual Report on Form 10-K of Idaho Power
Company for the year ended December 31, 1993.
DELOITTE & TOUCHE
Portland, Oregon
March 7, 1994
