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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, 1994
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)-388-2200
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 whether the registrant (1) has filed all
reports required to be filed by Section 13 or 15(d) of the
Securities Exchange Act of 1934 during the preceding 12 months
(or for such shorter period that the registrant was required to
file such reports), and (2) has been subject to such filing
requirements for the past 90 days.
Yes X No
Indicate by check mark if disclosure of delinquent filers
pursuant to Item 405 of Regulation S-K is not contained herein,
and will not be contained, to the best of registrant's knowledge,
in definitive proxy or information statements incorporated by
reference in Part III of this Form 10-K or any amendment to this
Form 10-K.
Aggregate market value of voting stock
held by nonaffiliates (January 31, 1995) $948,028,200
Number of shares of common stock outstanding at February 28, 1995
37,612,351
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 1995 Annual Meeting of
Item 13 Shareowners to be held on May 3, 1995.
The exhibit index is located on page 92. This document contains
140 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 695,000 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
implementation of a power cost adjustment mechanism (PCA) 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, temperature
conditions, and management decisions and less on precipitation
and streamflow conditions. As of December 31, 1994, the Company
supplied electric energy to 330,308 general business customers
and employed 1,703 people in its operations (1,609 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, 1994, 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 19 percent, commercial
and industrial customers with 750 kW demand and over accounted
for 19 percent and irrigation customers accounted for 12 percent.
Public utilities and interchange arrangements accounted for 11
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 four large special contract customers in its
Idaho retail jurisdiction - the Idaho National Engineering
Laboratory (INEL), the J. R. Simplot Company, FMC Corporation
(FMC) and Micron Technology, Inc. (Micron). 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, up to 38 megawatts of
capacity and energy to the J. R. Simplot Company for its chemical
fertilizer operations plant near Pocatello, Idaho and up to 37
megawatts of capacity and energy to Micron located in Boise.
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 by FMC 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 $30.5 million for 1.4 million megawatt-
hours (MWH) of energy supplied during the twelve months ended
December 31, 1994.
Competition -
Competition is increasing in the electric utility industry, due
to a variety of developments (National Energy Policy Act of 1992,
utility mergers surrounding our service territory, large
cogeneration and small power projects, customer demands, etc.).
In response to increasing competition, the Company continues to
proceed with a strategic planning process. The goal of this
process is to anticipate and fully integrate into Company
operations any legislative, regulatory, environmental,
competitive, or technological changes. With its low average
energy production costs, the Company is ready to enter a more
competitive environment and is taking action to preserve its low-
cost competitive advantage. (see Part II, Item 7. Management's
Discussion and Analysis of Financial Condition and Results of
Operations - Competition and Strategic Planning.)
With its predominantly hydro base and low-cost thermal plants,
the Company is one of the lowest cost producers of electric
energy among the nation's investor-owned utilities. Through its
interconnections with BPA, PacifiCorp and other utilities, the
Company has access to all the major electric systems in the West.
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 Rates). The Company's rates for its
large (750 kW and over) industrial customers, excluding special
contracts, averaged approximately 2.8 cents per kilowatt hour (see
Power Supply). Some of these customers are converting waste
heat to electricity for sale to the Company while purchasing
their entire power needs at the Company's lower rates. The
Company's rates for its small (under 750 kW) commercial and
industrial customers average approximately 4.3 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 what was the
utility's 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 the
service area they are located or from any other electric utility
or independent power supplier.
The Idaho Legislature and the IPUC have not yet addressed retail
wheeling. However, the Company believes with its low-cost energy
production it is positioned 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 five wholly-owned subsidiary companies: Ida-West
Energy Company (Ida-West), Idaho Energy Resources Co. (IERCo),
Idaho Utility Products Company (IUPCo), IDACORP, INC., and
Stellar Dynamics.
Ida-West was formed in 1989 to participate through partnership
interests in cogeneration and small power production (CSPP)
projects. Ida-West owns, through various partnerships, 50 percent
of five Idaho hydroelectric projects with a total generating
capacity of approximately 34 megawatts (MW). Third parties
unaffiliated with Ida-West own the remaining 50 percent of these
projects, thus satisfying the "qualifying facility" status under
Public Utility Regulatory Policy Act (PURPA) guidelines. The
partnerships have obtained project financing (non-recourse to the
Company) for each of these facilities. Power purchased from these
facilities amounted to approximately $7.1 million in 1994. To
date, all power sales made by Ida-West have been to the Company.
The Company has invested $20 million in Ida-West. Ida-West
continues to actively seek to develop new projects. (see Part II,
Item 7. Management's Discussion and Analysis of Financial
Condition and Results of Operations - Subsidiaries.)
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, 1994,
the Company's total investment in IERCo was $4.5 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 1994. As of
December 31, 1994, the combined total investment in these
subsidiaries was $3.3 million.
In 1994, Idaho Power announced the formation of a fifth
subsidiary company. Stellar Dynamics hopes to commercialize the
Company's extensive expertise in control technology for electric
substations and power plants. The Company approved the new
venture after receiving a positive recommendation from a market
survey by Newton-Evans Research Company. The recommendation was
backed by strong interest from potential customers. One-third of
the companies surveyed, including several large investor-owned
utilities, requested product information. The primary opportunity
for Stellar Dynamics' design, consulting, installation, and
troubleshooting services lies in the U.S. substation controls
market. The Company expects to capitalize Stellar Dynamics during
the first half of 1995.
Research and Development and Renewable Energy Sources -
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 now called Solar
Two near Barstow, California. 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 have contributed
$630,500 by the end of 1998 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 main benefit the Company will receive by participating in
this project is valuable experience and knowledge in solar plant
design, construction and operation.
During 1994, the Company spent approximately $2.2 million on
research and development of which $1.9 million was the Company's
membership in EPRI. 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.
As a member of EPRI, the Company participates in collaborative
research projects with other EPRI-member utilities. This type of
research project is known as Tailored Collaboration. It is
tailored in that EPRI members invest additional funds to support
research projects of specific value to their operations. In turn,
EPRI provides matching funds from the Institute's base budget.
Another aspect of the Company's research and development efforts
is an internal program called the Emerging Technology (ET)
Program. The ET program was established to maintain an active and
coordinated response to new technology and the ongoing industry
research program and initiatives that are of interest to the
Company.
Parts of the Company's service territory show a strong potential
for solar power. The Company has just completed designing and
constructing the nation's largest hybrid solar-powered
photovoltaic (PV) system in the Mountain Home Air Force Base
project. (see Part II, Item 7. Management's Discussion and
Analysis of Financial Condition and Results of Operations - Solar
and Solar Photovoltaic Projects.)
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 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 1994, the Company expended
$7.0 million cash 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 in 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. In 1994, drought
conditions again returned to the Company's service area. These
conditions have hampered the Company's hydroelectric operations
six of the last eight years. The system peak demand for 1994 was
2,392 megawatts set on June 23, 1994, which was 11.0 percent
above the 1993 peak demand and 5.5 percent above the 1992 demand.
The following table sets forth the total energy sources of the
Company for the last five years:
Total Energy Sources
(000's of MWH)
1994 1993 1992 1991 1990
Generation - net
station output -
Hydro 6,213.2 8,361.7 4,990.3 5,819.2 6,108.8
Coal-fired 7,221.8 6,485.5 7,295.6 5,833.7 5,957.0
Purchased and
interchange 2,287.0 1,273.8 2,102.8 2,583.1 1,936.7
Total 15,722.0 16,121.0 14,388.7 14,236.0 14,002.5
Purchased power expenses were high and fluctuated during the last
three years reflecting necessity purchases from neighboring
utilities during the drought years. The Company increases
utilization of its thermal facilities by operating at high
capacity factors during drought periods which increases fuel
expense. Conversely, it relies more on hydro facilities to meet
customer demand during good water years thereby reducing fuel
expense.
During 1994, approximately 40 percent of the Company's load
requirements were met with the Company's hydroelectric generating
plants, 46 percent from the thermal generating plants and the
remaining 14 percent was purchased from or exchanged with
neighboring utilities or from CSPP facilities. By comparison,
hydroelectric generation met 52 percent of load requirements in
1993, 35 percent in 1992, 41 percent in 1991 and 44 percent in
1990. In a normal water year the hydro system contributes
approximately 58 percent, thermal generation accounts for 33
percent and purchased power and other interchanges contributes
the remaining 9 percent of total system requirements. Although it
is too early to predict with certainty what hydroelectric
conditions will be during 1995, preliminary reports indicate the
mountain snowpack is approximately normal for this time of year.
However, the carryover reservoir storage throughout the Snake
River Basin is below average. 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 opportunities to purchase, sell, exchange and
transmit energy.
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 (BPA), 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 most of the electric systems in the West.
The Company is a member of the Intercompany Pool, the Western
Systems Coordinating Council, the Western Systems Power Pool, and
the Northwest 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 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 a detailed position
paper to its state regulators and other interested parties. In
December 1993 the Company filed with the IPUC for permission to
approve lower published prices for new CSPP contracts. In
response to the Company's filing, on January 31, 1995 the IPUC
issued an order approving lower published CSPP rates. (see Rates
and Part II, Item 7. Management's Discussion
and Analysis of Financial Condition and Results of Operations -
Regulatory Issues.)
New Projects -
In response to increased customers and demand, the Company
periodically updates its load and resource projections and now
expects total Company energy requirements over the next 20 years
to grow at an annual rate of 1.1 percent.
The Company's current projects include the expansion from 10 to
53 megawatts of the Twin Falls hydro plant (1995) (see
Construction Program).
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 path for regional transfers of
power between the northwest and southwest. The Southwest Intertie
Project (SWIP) is a proposed 500-mile, 500-Kv transmission line
that would interconnect the Company's system with utilities in
the Southwest. The Bureau of Land Management (BLM) completed the
Final Environmental Impact Statement/Proposed Plan Amendment for
the SWIP with a Record of Decision and Right of Way issued in
December 1994. The utility and BLM will begin to prepare a
detailed site-specific construction, operation and maintenance
plan aimed at mitigating the environmental impact of the project.
Detailed engineering work could begin in 1995. The Company has
received preliminary commitments from various utility and non-
utility entities 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 1999 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)
1995 1996 1997 1998 1999
Generation capability 2,686 2,691 2,691 2,691 2,691
Contracts:
Exchange (b) 175 175 175 175 175
Cogeneration and small
power production 134 158 158 158 158
Firm peak load less
interruptible (2,276) (2,307) (2,392) (2,473) (2,510)
Peak capability margin 719 717 632 551 514
Percent 31.6% 31.1% 26.4% 22.3% 20.5%
(a) Based upon median hydro conditions.
(b) Net summer-winter exchange.
Annual Energy Capability
(000's of MWH)(a)
1995 1996 1997 1998 1999
Generation capability 15,270 15,396 15,472 15,688 15,997
Contracts:
Cogeneration and
small power
production 764 1,107 1,107 1,107 1,107
Annual firm load (b) (15,370) (15,446) (15,602) (16,179) (16,243)
Energy capability
margin 664 1,057 977 616 861
Percent 4.3% 6.8% 6.3% 3.8% 5.3%
(a) Forecast based upon average of 66 historical water
conditions.
(b) The growth in retail load is being offset by termination of
some large short-term firm contracts.
During the 1995-1999 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 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 62 CSPP projects on-line as of December
31, 1994, is currently $40.7 million. During 1994, the Company
purchased 543.3 million kilowatt-hours of power from these
private developers at a blended price of 5.7 cents per kilowatt-
hour (see Rates).
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 are presently scheduled to expire between
1996 and 2009. As these contracts expire the Company will use the
energy to meet current retail load, re-negotiate a new contract with
the existing customer or contract with new wholesale customers for
the sale of energy.
Transmission Service -
The Company has long had an open access transmission policy and
is experienced in providing reliable, high quality, economical
transmission service. The Company presently provides transmission
service to BPA for their sales of electricity to certain
irrigation districts in southern Idaho for irrigation pumping and
their 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 wheeling agreements with various surrounding utilities. Most
recently, the Company has agreed to provide transmission service
required by Sierra Pacific Power Company and the Washington Water
Power Company to complete their proposed merger.
The Company's system lies between and is interconnected to the
winter peaking northern and summer peaking southern regions of
the western interconnected power system. This position should be
advantageous both in providing transmission service and reaching
a broad power sales market. To help facilitate access throughout
the power system, the Company has become a charter member of the
Western Regional Transmission Association. This association is
the first of the regional transmission groups seeking a FERC
charter to facilitate transmission access under the National
Energy Policy Act of 1992.
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 Jim Bridger Coal Mine 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: 1990 - $20.68;
1991 - $20.78; 1992 - $20.13; 1993 - $20.99 and 1994 - $19.52.
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 AMAX Coal Company
for delivery of low sulfur coal from its mines 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 up to 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.
In 1987, the Idaho Department of Water Resources filed a petition
in state district court commencing the Snake River Basin
Adjudication. This proceeding was initiated pursuant to state
statute and a determination by the Idaho Legislature that the
effective management of the Snake River basin required a
comprehensive determination of the nature, extent and priority of
all water users. The adjudication is still in its early stages,
and the process will likely continue past the turn of the
century. The Company has filed claims to its water rights within
the basin and is participating in the adjudication to insure that
its operations and water rights are not adversely impacted. The
Company does not anticipate any modification of its water rights
as a result of 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 IPUC, the OPUC 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
are not in conflict with the Federal Power Act or the Company's
FERC license (see Item 2. Properties).
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 and the modification
of system operations to accommodate such regulation.
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 1995 and during the period 1996-1999
will total approximately $1.5 million and $5.2 million,
respectively. The Company also anticipates spending approximately
$20 million a year in operating expenses for environmental
facilities during the 1995-1999 period. 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. The Company has entered into a joint arrangement with
PacifiCorp and Black Hills Power and Light under which certain of
these companies generating units have been accepted by the
Environmental Protection Agency as "Substitution" units for the
Baldwin #2 unit owned by Illinois Power Company. In exchange for
Illinois Power naming units at the Jim Bridger Station as
"Substitution" units for Baldwin #2, the Company sold Illinois
Power a portion of the Phase I SO2 Allowances it received by
having its share of the Jim Bridger units accepted as Phase I
"Substitution" units.
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 1994, the investment in these facilities was $11.7
million and the operation of these facilities pursuant to the
FERC License 1971 cost approximately $2.5 million annually. The
Niagara Springs project is currently going through an approximate
$3.9 million expansion.
Endangered Species -
The Company continues to review and analyze the various effects
upon its operations of the listing as threatened or endangered of
several species of salmon and Snake River mollusks. The Company
is cooperating with various governmental agencies to resolve
these issues. (see Part II, Item 7. Management's Discussion and
Analysis of Financial Condition and Results of Operation -
Environmental Issues.)
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 $0.3 million, $0.1 million and $1.3 million for
1992, 1993, and 1994 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 (EMF) -
While scientific research has yet to establish any conclusive
link between EMF and human health, the possibility has caused
public concern in the United States and abroad. Electric and
magnetic fields are found wherever there is electric current,
whether the source is a high-voltage transmission line or the
simplest of electrical household appliances. Concerns over
possible health effects have prompted regulatory efforts in
several states to limit human exposure to EMF. Depending on what
researchers ultimately discover and what regulations may be
deemed necessary, it is possible that this issue could affect a
number of industries, including electric utilities. However, at
this time it is difficult to estimate what impacts, if any, the
EMF issue could have on the Company and its operations.
RATES
Idaho Jurisdiction -
Since May 1993, the Company's PCA mechanism has provided for it
to collect, or to refund, a portion of the differences between
actual net power supply costs and those allowed in the Company's
Idaho base rates. Rates are adjusted each May based on forecasted
costs for the upcoming period May-April. Deviations from
forecasted costs are deferred with interest and trued up the
following year. The Company filed its 1994 PCA application with
the IPUC on April 15, 1994, requesting an increase in addition to
base rates. The increase (in effect from May 16, 1994 through May
15, 1995) was approximately $9.8 million or 2.5 percent including
last year's true-up. At December 31, 1994, the Company had
recorded $8.6 million of power supply costs above those projected
in the 1994 forecast. This cumulative amount adjusted for any
deferrals through March 1995 will be requested to be included in
the 1995 true-up adjustment. With the IPUC's recent revenue
requirement order, beginning February 1, 1995, the PCA mechanism
increased on a prospective basis to a 90 percent payout level
from its original 60 percent.
On June 30, 1994, the Company filed a general revenue requirement
rate case with a calendar year 1993 test year, a thirteen month
average rate base (annualized for its new Swan Falls production
project) and a year end capitalization structure. The IPUC
conducted hearings commencing on October 10 and December 12,
1994.
On January 31, 1995, the Company received IPUC Order No. 25880
authorizing $17.2 million in general rate relief representing a
4.2 percent overall increase in Idaho retail rates. The relief is
based on an 11.0 percent allowed return on equity with an overall
rate of return of 9.199 percent. The Company had requested $37.1
million in general rate relief representing a 9.09 percent
increase in rates, a 12.50 percent return on equity, and a 9.88
percent overall rate of return. These increased rates are
effective February 1, 1995.
On February 21, 1995 Idaho Power filed a Petition for
Reconsideration with the IPUC in regard to Order No. 25880 issued
January 31, 1995. In the petition, the Company requested an
increase in the authorized rate of return on common equity to
11.75 percent. This would result in an additional increase in
revenues of $6,840,143 or 1.6 percent. The petition is based on
the Company's position that the rate of return determination was
based upon an erroneous application of rate of return evidence,
was unreasonable and contrary to the findings of the order, and
failed to include any added increment for rewarding management's
efforts. (see Part II - Item 7. Management's Discussion and
Analysis of Financial Condition and Results of Operations -
Regulatory Issues.)
In September 1993, the Company submitted a detailed position
paper to its state regulators and other interested parties. This
report outlined proposed changes in the Company's resource
acquisition policy. With the potential deregulation of the
electric utility industry, and a more competitive power supply
marketplace, the Company believes that current resource
acquisition policies must be changed to avoid burdening it and
its customers with unnecessary future power supply costs. The
Company believes that the appropriate criteria for adding future
supplies should be power needs at the time of development and
that the addition be the least-cost market alternative.
Therefore, in December 1993 the Company filed with the IPUC for
permission to approve lower published prices for new CSPP
contracts. In response to the Company's filing, on January 31,
1995 the IPUC issued an order approving lower published CSPP
rates. In the order, the IPUC also determined that negotiated
rates for future CSPP projects larger than one megawatt should be
more closely tied to values determined in the Company's
integrated resource planning process. In its order, the IPUC
stated, "There is a widely held expectation that there will be
increasing competition within the electric utility industry. In
light of that, we believe it is especially important that the QF
[Qualified Facilities] industry be able to demonstrate that the
energy resources offers are as cost effective as those that a
utility would construct."
Oregon Jurisdiction -
The Company presently contemplates filing a general revenue
requirement case in Oregon in 1995 using the same information
prepared for its 1994 general revenue requirement filing before
the IPUC.
The Company's PCA mechanism applies only to its Idaho
jurisdiction. As a result of 1994's high power supply costs, the
Company also filed for temporary drought rate relief with the
OPUC. The OPUC issued an accounting order that granted the
Company permission to defer with interest 60 percent of Oregon's
share of the Company's increased power supply costs incurred
between May 13, 1994 and December 31, 1994. The amount deferred
at December 31, 1994 was $1.3 million. The Company is required
and will file an application with the OPUC in early 1995 to
recover these deferred costs.
Other Jurisdictions -
In 1994 the Company did not file any applications for rate relief
before the FERC or in its Nevada retail jurisdiction.
CONSTRUCTION PROGRAM
The Company's construction program for the 1995-1999 period
includes expansion of the Twin Falls hydro facility with the
balance primarily in transmission and distribution facilities.
The total cash construction program (excluding allowance for
funds used during construction) for the five-year period 1995-
1999 is presently estimated to require cash funds of
approximately $418.7 million as follows:
1995 1996-1999(a)
(Millions of Dollars)
Generating Facilities:
Hydro $ 21.6 $ 35.4
Thermal 7.2 22.9
Total generating facilities 28.8 58.3
Transmission lines and substations 13.6 48.9
Distribution lines and substations 37.8 146.1
General 14.6 70.6
Total cash construction 94.8 323.9
AFUDC 1.7 4.5
Total construction including AFUDC (b) $ 96.5 $328.4
(a) Includes construction costs escalated at 3.25%, 2.49%, 2.61%
and 2.84% annually for the years 1996-1999, respectively.
(b) Does not include Ida-West equity investment in construction
as Ida-West develops 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.
In early spring of 1994, the Company completed testing of its new
Swan Falls Project and both units were declared available for
commercial operation. At December 31, 1994, the Company had spent
approximately $55.0 million for construction of the Swan Falls
Project, including allowance for funds used during construction.
Additional work to preserve the old power plant as an historical
site began during the year. Work to establish a museum on the
site is scheduled for completion in 1995. In May, crews completed
the federally-mandated stabilization of the dam and began the
environmental reclamation of approximately 18 acres of land
affected by construction activities.
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 $38.1 million with total construction
costs at $41.9 million including allowance for funds used during
construction. At December 31, 1994, the Company had expended
approximately $29.4 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) efficiency improvements on the
Company's generation, transmission and distribution systems,
(2) additional power purchases from CSPP facilities,
(3) purchased power and exchange agreements with other utilities
or other power suppliers and (4) customer conservation. 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 refund maturing long-
term debt. The most recent estimate of capital requirements and
sources of capital for the period is $428.5 million outlined as
follows:
1995 1996-1999
(Millions of Dollars)
Capital Requirements:
Net cash construction expenditures $ 94.8 $323.9
Conservation expenditures 7.8 16.3
Other cash expenditures (4.1) (10.2)
Total $ 98.5 $330.0
Sources of Capital:
Internal generation $ 60.3 $333.6
Short-term bank loans - Net (22.0) (31.0)
First mortgage bonds/PC bond 50.0 138.1
Debt repayment (.6) (120.7)
Common stock 12.0 14.0
Cash investments (increase) (1.2) (4.0)
Total (a) $ 98.5 $330.0
(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, 1994, net earnings were 5.89
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, 1994,
the actual preferred dividend earnings coverage was 2.61 times.
If the dividends on the shares of Auction Preferred Stock were to
reach the maximum allowed, the preferred dividend earnings
coverage would be 2.40 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 4,648 miles of high
voltage transmission lines; 21 step-up transmission substations
located at power plants; 17 transmission substations; 7
transmission switching stations; and 195 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 1,166,900 2005
Swan Falls 27,170 27,170 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 Station) 693,333 678,077
Valmy (Coal-Fired Station) 260,650 260,650
Boardman (Coal-Fired Station) 53,000 53,000
On December 31, 1994, the composite average ages of the principal
parts of the Company's system, based on dollar investment, were:
production plant, 15.8 years; transmission system and
substations, 18.0 years; and distribution lines and substations,
13.8 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
vigorously pursued 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 will
submit its first applications for license renewal to the FERC in
December 1995. These first applications will seek renewal of the
Company's licenses for its Bliss, Upper Salmon and Lower Salmon
Hydroelectric Projects. The Company cannot anticipate what type
of environmental capital investment 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 and PCB/lead
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 will supersede EPA's "Interim"
Administrative Order when it is entered by the court.
On August 30, 1993, Notice of the Lodging of the Amended Partial
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 Partial 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. Following receipt of the Company's responses,
EPA undertook further factual investigations relating to the
extent of lead contamination at the site and the nature and
extent of lead contributions to the site, including the Company's
involvement.
The Amended Partial Consent Decree was finally lodged together
with EPA's Motion to Enter with the U.S. District Court for the
District of Idaho on December 12, 1994. The Amended Partial
Consent Decree provides that the Company is protected against any
and all claims for contribution by other PRPs, both as to the PCB
and lead contamination.
On January 24, 1995, the Company was advised that the PRP group
associated with lead contamination was objecting to the proposed
entry of the Amended Partial Consent Decree on the basis that the
Company has not paid its "fair share" of the remaining lead clean-
up costs which EPA currently estimates at approximately $5
million.
It is EPA's position that the Company, as an integral part of its
clean-up of the PCB contamination and PCB/lead contamination,
removed approximately 57 percent of the total lead contamination
from the entire site, even though the Company contributed only
10.5 percent of the total lead contamination.
The Company believes that the objections filed by the PRPs are
completely without merit, and both the Company and the EPA are
responding to the objections of the PRPs.
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, March 10, 1994, 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 and
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 costs
of site remediation, and damages for the insurers' breach of the
insurance contracts based on the insurers' failure to pay such
costs.
Due to a case backlog in the Idaho District, the case was
assigned to a Federal Judge in the Eastern District of
Washington. In the action, the Company seeks reimbursement for
approximately $6,125,000 in indemnity and defense costs
associated with the remediation, together with prejudgment
interest and attorney fees and costs for the action.
The Company successfully settled its claim for coverage with the
Liquidation Trustee for the first layer insurer (which insurer is
now in liquidation) on several of the policies at issue,
resulting in a one-time payment of $827,500 to the Company last
fall. This sum is not reflected in the damages which the Company
seeks in this litigation.
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 Tribe's
claim for damages arising from precluding the Tribe's 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.
On March 21, 1994, the Federal District Judge issued an order
granting the Company's motion for summary judgment on all claims
except the Tribe's claim for compensation based on exclusion from
its usual and accustomed fishing places, which part of the motion
the District Judge denied without prejudice.
On September 28, 1994, the Federal District Judge issued an Order
rejecting the Second Report and Recommendation of the Magistrate
and granting, in its entirety, the Company's motion for summary
judgment.
On November 8, 1994, the Tribe filed its Notice of Appeal with
the Ninth Circuit Court of Appeals. No date for oral argument on
the appeal has yet been set.
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, March 10, 1994, and other reports
filed with the Commission.
On October 6, 1994, the Company brought an action, Idaho Power
Company, v. Monsanto Company, et al., in the district court of
the fourth judicial district of the State of Idaho, against
Monsanto Company, General Electric Company, Westinghouse Electric
Corporation, Schlumberger Industries, Inc., McGraw-Edison
Company, Asea Brown Boveri, Inc. and Cooper Industries, Inc. The
Complaint alleges fraudulent misrepresentation or omission of
material facts, and/or knowing failure to warn Idaho Power
Company of the hazards of polychlorinated biphenyls (PCBs), in
connection with the sale, service, replacement, maintenance,
and/or removal of electrical equipment utilizing or contaminated
with PCBs. The case has been removed to the United States
District Court for the District of Idaho and is still in an early
stage. Discovery has not yet commenced and no trial date has been
set.
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
Name, Age and Position Five (5) Years
J. W. Marshall, 56 Appointed August 18, 1989.
Chairman of the Board
and Chief Executive
Officer
L. R. Gunnoe, 59 Appointed July 12, 1990. Mr. Gunnoe
President and Chief was Vice President - Distribution
Operating Officer prior to July 12, 1990.
Daniel K. Bowers, 47 Appointed July 10, 1986.
Vice President and
Treasurer
J. LaMont Keen, 42 Appointed November 14, 1991.
Vice President and Mr. Keen was Controller prior to
Chief Financial Officer November 14, 1991.
Douglas H. Jackson, 58 Appointed July 12, 1990.
Vice President - Mr. Jackson was Senior Manager of
Distribution Corporate Services prior to
July 12, 1990.
Paul L. Jauregui, 53 Appointed June 4, 1988.
Vice President -
Human Resources
C. N. Olson, 45 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
and Distribution Engineering and
Construction Manager prior to
February 1, 1990.
J. B. Packwood, 51 Appointed July 13, 1989.
Vice President -
Power Supply
Robert W. Stahman, 50 Appointed July 13, 1989.
Vice President, General
Counsel and Secretary
Harold J. Hochhalter, 59 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 1992, 1993 and 1994, cash
dividends per share of common stock were $1.86. At the July 1994
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
exchanges. For years 1993 and 1994, the following table indicates
the reported high and low sales price of the Company's common
stock as reported by the Wall Street Journal as composite tape
transactions. The Company's number of common stockholders of
record at December 31, 1994 was 26,209.
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
1994 (Quarters)
Common Stock, $2.50 par value: 1st 2nd 3rd 4th
High $30 5/8 $27 5/8 $24 7/8 $24 1/8
Low 26 7/8 21 3/4 22 1/2 22
Dividends paid per share (cents) 46.5 46.5 46.5 46.5
ITEM 6. SELECTED FINANCIAL DATA
SUMMARY OF OPERATIONS 1994 1993 1992 1991
(Thousands of Dollars)
Revenues:
General business $457,354 $428,658 $431,818 $409,454
Sales to other utilities 59,923 86,525 42,000 52,563
Other revenues 26,381 25,219 24,274 21,176
Total revenues 543,658 540,402 498,092 483,193
Expenses:
Purchased power 60,216 45,361 58,496 51,210
Fuel expense 94,888 87,855 96,710 75,161
Other operation and 154,742 164,388 137,547 151,593
maintenance
Depreciation 60,202 58,724 59,823 57,597
Taxes other than income taxes 23,945 22,129 20,562 21,168
Total expenses 393,993 378,457 373,138 356,729
Income from operations 149,665 161,945 124,954 126,464
Other income and deductions - (12,160) (12,984) (11,133) (9,453)
Net
Interest charges - Net 52,652 53,991 52,935 56,901
Income taxes 34,243 36,474 23,162 21,144
Cumulative effect of accruing
unbilled revenues - - - -
Net Income 74,930 84,464 59,990 57,872
Dividends on preferred stocks 7,398 6,009 5,516 4,904
Earnings on common stock 67,532 78,455 54,474 52,968
Dividends on common stock 69,594 67,959 65,043 63,197
Net change to retained earnings $ (2,062) $ 10,496 $(10,569) $(10,229)
CAPITALIZATION (000 omitted) % % % %
First mortgage bonds $490,000} 46 $490,000} 47 $485,000} 49 $435,000} 48
Other long-term debt 203,206 203,780 216,948 194,981
Mandatory redeemable preferred
stock -} 9 -} 9 -} 7 -} 8
Preferred stock 132,456 132,751 107,874 108,191
Common stock (incl. prem. & 452,962} 45 439,467} 44 412,998} 44 356,824} 44
exp.)
Retained earnings 220,838 222,900 212,404 222,973
Total capitalization $1,499,462 100 $1,488,898 100 $1,435,224 100 $1,317,969 100
Short-term borrowings $55,000 $4,000 $6,000 $48,500
outstanding
SUMMARY OF OPERATIONS 1990 1989 1988 1987
(Thousands of Dollars) (Cont'd)
Revenues:
General business $401,350 $397,974 $362,050 $343,899
Sales to other utilities 44,368 70,749 32,175 35,447
Other revenues 19,217 27,438 18,096 15,251
Total revenues 464,935 496,161 412,321 394,597
Expenses:
Purchased power 43,923 43,845 43,723 30,234
Fuel expense 77,606 77,127 74,528 65,934
Other operation and 134,126 132,114 116,230 114,235
maintenance
Depreciation 55,114 53,092 51,691 50,929
Taxes other than income taxes 20,752 20,213 19,301 19,072
Total expenses 331,521 326,391 305,473 280,404
Income from operations 133,414 169,770 106,848 114,193
Other income and deductions - (11,666) (10,005) (6,552) (13,115)
Net
Interest charges - Net 52,605 52,997 50,762 51,843
Income taxes 23,234 42,041 13,558 27,246
Cumulative effect of accruing
unbilled revenues - - - (11,302)
Net Income 69,241 84,737 49,080 59,521
Dividends on preferred stocks 4,279 4,285 4,293 4,298
Earnings on common stock 64,962 80,452 44,787 55,223
Dividends on common stock 63,197 62,177 61,159 61,159
Net change to retained earnings $ 1,765 $ 18,275 $(16,372) $ (5,936)
CAPITALIZATION (000 omitted) % % % %
First mortgage bonds $367,500} 46 $377,000} 47 $392,000} 47 $407,000} 47
Other long-term debt 194,159 165,551 164,426 160,003
Mandatory redeemable preferred
stock -} 5 -} 5 -} 5 -} 5
Preferred stock 58,761 58,923 59,126 59,238
Common stock (incl. prem. &
exp.) 358,078} 49 357,986} 48 357,866} 48 357,797} 48
Retained earnings 233,241 231,476 213,201 229,573
Total capitalization $1,211,739 100 $1,190,936 100 $1,186,619 100 $1,213,611 100
Short-term borrowings $48,280 $31,000 $37,000 $4,000
outstanding
SUMMARY OF OPERATIONS 1986 1985 1984
(Thousands of Dollars) (Cont'd)
Revenues:
General business $336,480 $336,705 $324,701
Sales to other utilities 54,987 98,980 86,724
Other revenues 17,394 15,495 16,422
Total revenues 408,861 451,180 427,847
Expenses:
Purchased power 31,849 16,188 1,215
Fuel expense 31,260 81,961 50,850
Other operation and 114,407 125,728 119,604
maintenance
Depreciation 49,308 45,595 40,974
Taxes other than income taxes 18,539 16,790 16,363
Total expenses 245,363 286,262 229,006
Income from operations 163,498 164,918 198,841
Other income and deductions - (17,064) (20,352) (11,191)
Net
Interest charges - Net 51,206 47,891 45,579
Income taxes 50,923 52,556 64,418
Cumulative effect of accruing
unbilled revenues - - -
Net Income 78,433 84,823 100,035
Dividends on preferred stocks 10,553 12,447 13,617
Earnings on common stock 67,880 72,376 86,418
Dividends on common stock 59,755 56,277 52,221
Net change to retained earnings $ 8,125 $ 16,099 $ 34,197
CAPITALIZATION (000 omitted) % % %
First mortgage bonds $432,000} 47 $467,000} 47 $467,000} 47
Other long-term debt 153,887 149,074 138,452
Mandatory redeemable preferred
stock -} 5 63,000} 9 63,000} 10
Preferred stock 59,403 60,585 61,079
Common stock (incl. prem. &
exp.) 357,708} 48 355,007} 44 342,038} 43
Retained earnings 235,509 230,558 214,459
Total capitalization $1,238,507 100 $1,325,224 100 $1,286,028 100
Short-term borrowings
outstanding $5,000 $ - $ -
FINANCIAL STATISTICS 1994 1993 1992 1991
Income from operations as a
percent of total revenues 27.5% 30.0% 25.1% 26.2%
Times interest charges earned:
Before tax 3.01 3.14 2.50 2.34
After tax 2.38 2.50 2.08 1.98
Market-to-book ratio 131% 170% 159% 168%
Payout ratio 103% 87% 120% 119%
Return on year-end common
equity 10.02% 11.84% 8.71% 9.14%
Common stock data:
Earnings per average share
outstanding $1.80 $2.14 $1.55 $1.56
Dividends declared per share $1.86 $1.86 $1.86 $1.86
Book value per share $17.91 $17.86 $17.28 $17.07
Average shares outstanding
(000 omitted) 37,499 36,675 35,116 33,977
Common shareowners 26,209 26,870 27,834 28,069
* Includes cumulative effect
of accounting change
CUSTOMER DATA
General business data:
Energy sales - kWh
(000,000 omitted) 12,194 11,406 11,606 11,266
Number of customers 330,308 317,772 307,567 297,808
Residential customer data:
Number of customers 274,187 263,682 255,022 246,689
Average kWh use per customer 14,159 14,587 13,856 14,845
Average rate per kWh (cents) 4.83 4.82 4.80 4.72
OTHER STATISTICS
Total assets (000 omitted) $2,191,816 $2,097,417 $1,862,307 $1,773,674
Gross plant additions
(000 omitted) $107,667 $116,972 $118,920 $135,904
Number of employees (full-time) 1,609 1,654 1,638 1,626
FINANCIAL STATISTICS (Cont'd) 1990 1989 1988 1987
Income from operations as a
percent of total revenues 28.7% 34.2% 25.9% 28.9%
Times interest charges earned:
Before tax 2.72 3.30 2.18 2.76*
After tax 2.29 2.53 1.93 2.10*
Market-to-book ratio 148% 169% 138% 127%
Payout ratio 97% 77% 137% 111%
Return on year-end common
equity 10.99% 13.65% 7.84% 9.40%
Common stock data:
Earnings per average share
outstanding $1.91 $2.37 $1.32 $1.63*
Dividends declared per share $1.86 $1.83 $1.80 $1.80
Book value per share $17.40 $17.35 $16.81 $17.29
Average shares outstanding
000 omitted) 33,977 33,977 33,977 33,977
Common shareowners 29,080 30,291 32,225 33,733
* Includes cumulative effect
of accounting change
CUSTOMER DATA
General business data:
Energy sales - kWh
(000,000 omitted) 11,086 11,069 10,563 10,175
Number of customers 291,800 284,363 279,529 276,249
Residential customer data:
Number of customers 241,790 236,008 232,650 230,486
Average kWh use per customer 14,281 14,923 14,364 13,785
Average rate per kWh (cents) 4.73 4.69 4.47 4.34
OTHER STATISTICS
Total assets (000 omitted) $1,680,110 $1,625,120 $1,608,935 $1,602,311
Gross plant additions (000
omitted) $80,117 $62,094 $64,358 $38,929
Number of employees (full-time) 1,574 1,528 1,500 1,521
FINANCIAL STATISTICS (Cont'd) 1986 1985 1984
Income from operations as a
percent of total revenues 40.0% 36.6% 46.5%
Times interest charges earned:
Before tax 3.40 3.61 4.12
After tax 2.46 2.61 2.90
Market-to-book ratio 150% 133% 114%
Payout ratio 88% 78% 60%
Return on year-end common
equity 11.44% 12.36% 15.53%
Common stock data:
Earnings per average share
outstanding $2.00 $2.16 $2.63
Dividends declared per share $1.76 $1.68 $1.59
Book value per share $17.46 $17.29 $16.74
Average shares outstanding
(000 omitted) 33,961 33,544 32,893
Common shareowners 34,456 35,959 35,216
* Includes cumulative effect
of accounting change
CUSTOMER DATA
General business data:
Energy sales - kWh
(000,000 omitted) 9,938 10,366 10,191
Number of customers 274,129 272,155 268,974
Residential customer data:
Number of customers 228,921 227,562 225,319
Average kWh use per customer 14,541 15,432 15,342
Average rate per kWh (cents) 4.21 3.98 4.01
OTHER STATISTICS
Total assets (000 omitted) $1,621,887 $1,646,847 $1,584,874
Gross plant additions
(000 omitted) $50,257 $74,064 $99,028
Number of employees (full-time) 1,524 1,568 1,725
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
OVERVIEW
Idaho Power Company's consolidated financial statements represent
the Company and its five wholly-owned subsidiaries: Idaho Energy
Resources Company (IERCo); Ida-West Energy Company (Ida-West);
IDACORP, Inc.; Idaho Utility Products Company (IUPCo); and
Stellar Dynamics. This discussion uses the terms Idaho Power and
the Company interchangeably to refer to Idaho Power Company and
its subsidiaries.
EARNINGS PER SHARE AND BOOK VALUE
Two factors affected earnings per share in 1994. First, drought
conditions returned to the Company's service area. These
conditions have hampered the Company's hydroelectric operations
six of the last eight years. Second, the Company entered into an
agreement with a midwest utility regarding a substitution
emission allowance exchange. This agreement resulted in a $2.5
million one-time addition to pretax income. Earnings per share of
common stock were $1.80 in 1994, down from $2.14 in 1993, a year
of improved precipitation and streamflows. However, the 1994
earnings per share are an increase over 1992's drought-affected
$1.55. The 1994 earnings equate to a 10.0 percent earned return
on year-end common equity, as compared to the 11.8 percent earned
in 1993 and the 8.7 percent earned in 1992. At December 31, 1994,
the book value per share of common stock was $17.91.
RESULTS OF OPERATIONS
Energy Demand and Customer Growth
A prolonged period of high temperatures sparked sharp increases
in energy demand during the summer of 1994. Southwestern Idaho
and southeastern Oregon--the most densely populated area of the
Company's service territory--experienced a record 44 consecutive
days with temperatures of at least 90 degrees. On June 23, 1994,
the Company set a new record for system peak load at 2,392
megawatts (MW).
The Company's growth in new customers this year broke a record of
its own. By December 31, 1994, Idaho Power had connected 12,536
new general business customers to its system, far outpacing the
previous record of 11,563 set in 1978. By customer class, the
Company added 10,505 residential customers, 1,548 commercial and
industrial customers, and 483 irrigation customers.
Economy
The Company's service territory posted another outstanding year
of economic growth in 1994. Idaho's nonagricultural employment
grew by an estimated 4.6 percent, following gains of 5.0 percent
in 1993 and 4.6 percent in 1992. Across the entire service
territory, nonagricultural employment showed an estimated gain of
nearly 4.6 percent for 1994, building on gains of 4.9 percent in
1993 and 3.5 percent in 1992.
Population growth remains strong in the Company's service area.
The number of residential customers grew by 3.4 percent in both
1992 and 1993, and by 4.0 percent in 1994. Over the next five
years, the Company projects that the number of new households in
its service area will grow by an average rate of 3.0 percent per
year, while population growth over the same period will exceed
2.2 percent.
Revenues
For the three-year period 1992-1994, the Company received an
average 86 percent of its operating revenues from electric sales
in Idaho, 5 percent in Oregon, less than 1 percent in Nevada, and
9 percent from the wholesale market. For the same three-year
period, the average percentages of total operating revenues by
category were as follows:
- - 34 percent from residential customers;
- - 30 percent from a combination of irrigation customers, street
lighting customers, and commercial and industrial customers
with less than 750 kW demand;
- - 19 percent from commercial and industrial customers with
demand of 750 kW or greater;
- - 12 percent from sales to other utilities and interchange
arrangements;
- - 5 percent miscellaneous revenue.
The Company's energy sales to general business customers rose 3.0
percent in 1992, fell 1.7 percent in 1993, then increased 6.9
percent in 1994. The sales increases in 1992 and 1994 reflect the
strong economic growth in Idaho Power's service territory,
increases in new customers served, and varied temperature,
streamflow, and energy usage patterns. The decline in 1993 can be
traced to two factors: (1) wet spring weather that reduced
irrigation kilowatt-hour sales by 28.8 percent; and (2) temporary
operational changes made by two of the Company's large industrial
customers that lowered energy consumption. FMC Corporation
periodically curtailed 1993 operations at its elemental
phosphorous production plant in response to market conditions for
its product. Also, the Idaho National Engineering Laboratory
(INEL) reduced its 1993 electrical usage. Both FMC and INEL
returned to a higher level of operation during 1994.
Record growth in new customers contributed to the 1994 increase
in energy sales. In addition, a long, hot, dry summer boosted the
Company's irrigation load by 34.5 percent.
General business revenues constitute approximately 83 percent of
the Company's total operating revenues. For 1992, general
business revenues were $431.8 million, for 1993 $428.7 million,
and for 1994 $457.4 million. The decrease in 1993 is a result of
that year's wet spring, which reduced irrigation revenues by 27.9
percent. The decrease was partially offset by increases in
residential revenues (9.3 percent) and small commercial revenues
(4.0 percent). The 1994 increase reflects above-normal summer
temperatures that increased irrigation revenues by 33.2 percent,
or $16.2 million. The number of general business customers served
increased by 32,500, or 10.9 percent during the three-year
period. Energy usage per average residential customer was 13,856
kilowatt hours (kWh) in 1992, 14,587 kWh in 1993, and 14,159 kWh
in 1994.
Total operating revenues increased by $14.9 million (3.1 percent)
in 1992, $42.3 million (8.5 percent) in 1993, and $3.3 million
(0.6 percent) in 1994. Increased opportunity sales to other
utilities created the 1993 increase in total operating revenue.
Customer growth, coupled with above-normal summer temperatures,
accounted for the 1994 increase. However, the increase was offset
by a decline in opportunity sales caused by reduced streamflows.
Off-System Sales
Revenues from sales to other utilities fell $10.6 million in
1992, rose $44.5 million in 1993, and decreased by $26.6 million
in 1994. These are composed of firm sales (long-term contractual
agreements) and opportunity sales made on a when-available basis.
The volume and price of these sales depend on the Company's firm
energy demand, hydroelectric generation conditions in its service
territory, and market conditions throughout the West. Revenues
from firm sales to other utilities were $37.5 million in 1992,
$45.4 million in 1993, and $53.6 million in 1994. Revenues from
opportunity sales to other utilities were $4.5 million in 1992,
$41.1 million in 1993, and $6.3 million in 1994. Drought
conditions reduced opportunity sales in 1992 and 1994, while the
return to more normal hydro conditions in 1993 increased the
volume of sales and revenue dramatically.
Expenses
Total operating expenses grew $16.4 million in 1992, $5.3 million
in 1993, and $15.5 million in 1994. The added expense for 1992
and 1994 are a result of drought conditions that elevated the
Company's reliance on thermal generation and purchased power. The
1993 rise in operating expenses reflects the deferral of certain
1992 drought-related net power supply costs to 1993 authorized by
the Idaho Public Utilities Commission (IPUC). Maintenance expense
also increased in 1993 with that year's return to improved
hydroelectric operating conditions.
Purchased power expenses have been high and fluctuating during
the last three years. This situation reflects both necessity
purchases from neighboring utilities during drought periods and
increased 1993 purchases from cogeneration and small power
production (CSPP) projects as a result of improved hydro
conditions. The current estimated annualized cost for the 62 CSPP
projects on-line at December 31, 1994 is $40.7 million. The
Company relies on its thermal generation facilities to operate at
high-capacity factors during periods of drought. Increased
thermal generation raised fuel expenses by $21.5 million in 1992
and $7.0 million in 1994. In 1993, fuel expenses declined by $8.9
million as a direct result of the increased availability of hydro
generation to meet customer demand.
All other operation and maintenance expenses fluctuated during
the three-year period, with a cumulative increase of $3.1
million. These variations are due, in part, to increases in
payroll and benefits, and changes in operation and maintenance
due to drought conditions.
Depreciation expense was up for the three-year period by $2.6
million, or 4.5 percent, due to a greater plant investment base.
Taxes other than income taxes grew $2.8 million, or 13.1 percent,
as a result of additional property taxes and taxes on the
increased generation and sale of hydroelectric power.
Interest Charges
Interest charges on long-term debt fluctuated during the three-
year period. Ultimately, they were down by $3.2 million,
reflecting the maturity, early redemption, and issuance of
several series of first mortgage bonds. The Company took
advantage of declining interest rates to refinance several higher-
cost bond issues. These refinancings reduced the overall cost of
debt and annual interest expense by an amount that largely offset
the cost of additional financing (see Note 5 of Notes to
Consolidated Financial Statements).
Interest on short-term debt rose due to varying interest rates
during the period, as well as to a larger level of short-term
borrowings. At December 31, 1994, the Company's short-term
borrowings were $55.0 million (see Note 7 of Notes to
Consolidated Financial Statements).
Income Taxes
In August 1993, Congress enacted the Omnibus Budget
Reconciliation Act. Among other things, the Act raised 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 higher rate. Also in 1993,
the Company settled with the Internal Revenue Service (IRS)
federal income tax liabilities for the 1987-1990 tax years and in
1994 the Company settled federal income tax liabilities for the
1991-1992 tax years, except for immaterial amounts relating to a
partnership.
Precipitation and Streamflows
After experiencing an above-average water year in 1993, Idaho
Power's service territory experienced below-normal precipitation
and above-normal temperatures throughout much of 1994. Between
April and July, the Company recorded 2.75 million acre feet (MAF)
of water flowing into Brownlee Reservoir (water source for the
three-dam Hells Canyon hydroelectric complex). This figure is 46
percent of 1993's 6.0 MAF, 153 percent of 1992's 1.8 MAF, and 57
percent of the 66-year median of 4.8 MAF.
The early indications for l995 are somewhat better. As of
February 1, l995, reservoir storage above Brownlee Reservoir was
at 37 percent of capacity. However, the average snow water
equivalent for the Snake River above Brownlee Reservoir was at
114 percent of the 30-year average, compared to 56 percent of the
average at this time last year. Based on current hydrologic
conditions and projected meteorological conditions, the Company
estimates that approximately 4.5 MAF of water will flow into
Brownlee Reservoir between April and July 1995. If the estimate
holds true, it would be a 64 percent increase over 1994's
streamflow, but still 6 percent below the 66-year median inflow.
Energy Requirements
With drought conditions returning in 1994, hydroelectric
generation accounted for only 40 percent of the Company's total
energy requirements. This figure is a substantial decrease from
52 percent in 1993, but higher than 1992's 35 percent. Thermal
generation accounted for 46 percent of total energy requirements
in 1994, while purchased power and other exchanges supplied 14
percent. Under normal conditions, the Company's hydro system
supplies approximately 58 percent of its total energy
requirements, with thermal generation accounting for 33 percent
and purchased power and other interchanges contributing the
remaining 9 percent.
The Company expects to meet l995's projected energy loads by
using its hydro and coal-fired facilities and strategic
geographic location-which presents excellent opportunities to
purchase, sell, exchange, and transmit Northwest energy-even if
stream flow conditions are below normal.
Regulatory Issues
Power Cost Adjustment (PCA)
Since 1993, the Company's PCA mechanism has allowed it to
collect, or to refund, the differences between actual net power
supply costs and those allowed in the Company's Idaho base rates.
Deviations from forecasted costs are deferred with interest and
trued up the following year. The Company filed its 1994 PCA
application with the IPUC on April 15, 1994, requesting an
increase in base rates for the Idaho jurisdiction. The increase
(in effect from May 16, 1994 through May 15, 1995) was
approximately $9.8 million, or 2.5 percent including last year's
true-up. At December 31, 1994, the Company had recorded $8.6
million of power supply costs above those projected in the 1994
forecast. This cumulative amount will be requested to be included
in the 1995 true-up adjustment. With the IPUC's revenue
requirement order on February 1, 1995, the PCA mechanism
increased to a 90 percent recovery level from its original 60
percent.
General Revenue Requirement Case
On June 30, 1994, the Company filed its application based upon
calendar year 1993, using a thirteen month average rate base
(annualized for its new Swan Falls production project) and a year
end capitalization structure. The IPUC conducted ten days of
hearings commencing on October 10 and December 12, 1994. Public
hearings were also held in Pocatello, Idaho on December 5 and in
Caldwell, Idaho on December 7, 1994. Throughout the proceeding,
including the interim rate hearing, documentary and oral evidence
was presented by a number of parties.
On January 31, 1995, the Company received IPUC Order No. 25880
authorizing $17.2 million in general rate relief from the IPUC
representing a 4.2 percent overall increase in Idaho retail
rates. The relief is based on an 11.0 percent allowed return on
equity with an overall rate of return of 9.199 percent. The
Company had requested $37.1 million in general rate relief
representing a 9.09 percent increase in rates, a 12.50 percent
return on equity, and a 9.88 percent overall rate of return.
These increased rates are effective February 1, 1995.
The Company is disappointed with the allowed return on common
equity granted in the Order and believes it does not adequately
reflect today's financial conditions and the returns investors
expect to receive on their investment. An allowed return on
common equity of 11.0 percent only marginally exceeds the
Company's dividend payout ratio of 10.4 percent on year-end book
value. This makes it difficult for the Company to meet dividend
requirements because of the implied constraint the return allowed
places on the Company's earnings potential. The Company has
petitioned the IPUC for reconsideration of its decision with
regard to the allowed return on common equity seeking an
authorized return on common equity which, if earned, would be
sufficient to safely cover the current dividend. However, the
Company cannot predict the final outcome of this request for
reconsideration.
The Company will file a general revenue requirement case in
Oregon in early l995. This filing will utilize the same
information used in the 1994 filing in Idaho.
Cogeneration and Small Power Production Contracts
In September 1993, the Company submitted a detailed position
paper to its state regulators and other interested parties. This
report outlined proposed changes in the Company' s resource
acquisition policy. With the potential deregulation of the
electric utility industry, and a more competitive power supply
marketplace, the Company believes that current resource
acquisition policies must be changed to avoid burdening it and
its customers with unnecessary future power supply costs. Idaho
Power believes that the appropriate criteria for adding future
supplies should be power needs at the time of development and
that the addition be the least-cost market alternative.
Therefore, in December 1993 the Company filed with the IPUC for
permission to approve lower published prices for new CSPP
contracts. In response to the Company's filing, on January 31,
1995 the IPUC issued an order approving lower published CSPP
rates. In the order, the IPUC also determined that negotiated
rates for future CSPP projects larger than 1 megawatt should be
more closely tied to values determined in the Company's
integrated resource planning (IRP) process. In its January 31,
l995 order, the IPUC stated, "There is a widely held expectation
that there will be increasing competition within the electric
utility industry. In light of that, we believe it is especially
important that the QF [Qualified Facilities] industry be able to
demonstrate that the energy resources offers are as cost
effective as those that a utility would construct."
Rosebud Enterprises, Inc. (Rosebud) filed a Complaint against the
Company with the IPUC, alleging that the Company refused to sign
a contract to purchase the output of a 40 MW petroleum waste-
fired generating plant that Rosebud proposes to build near
Mountain Home, Idaho. Because this facility, known as the
Mountain Home Project, was larger than l0 MW, the IPUC's
established rates for small CSPP projects were not available to
Rosebud. On September 16, 1994, the IPUC issued an order
directing the Company to recalculate and offer avoided cost rates
as described in the order. In October 1994, the Company
transmitted a purchase offer to Rosebud conforming to the IPUC's
final order. Rosebud rejected that purchase offer and has
appealed the IPUC's final order to the Idaho Supreme Court.
Oregon Drought Rate Relief
The Company's PCA mechanism applies only to its Idaho
jurisdiction. As a result of 1994's high power supply costs, the
Company also filed for temporary drought rate relief with the
Oregon Public Utility Commission (OPUC). The OPUC issued an
accounting order that granted the Company permission to defer
with interest 60 percent of Oregon's share of the Company's
increased power supply costs incurred between May 13, 1994 and
December 31, 1994. The amount deferred at December 31, 1994 was
$1.3 million. The Company is required to file a request with the
OPUC in early 1995 to recover these deferred costs.
Subsidiaries
Ida-West Energy Company
This wholly-owned subsidiary of the Company owns, through various
partnerships, 50 percent of five Idaho hydroelectric projects
with a total generating capacity of approximately 34 megawatts
(MW). Third parties unaffiliated with Ida-West own the remaining
50 percent of these projects, thus satisfying the "qualifying
facility" status under PURPA guidelines. The partnerships have
obtained project financing (non-recourse to the Company) for each
of these facilities.
As a 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 MW gas-fired
cogeneration project to be located near Hermiston, Oregon. On
June 4, 1993, BPA selected three projects--including that of the
partnership--for participation in the program. The partnership
and BPA signed an option development agreement granting BPA an
option to acquire energy and capacity from the project any time
during a five-year option hold period after all option
development period tasks, including permitting, have been
completed. The option also entitles the partnership to BPA
reimbursement for certain development costs, based on the
achievement of certain milestones. This option includes an
exclusive right to acquire energy and capacity from a second
233 MW unit at the site during the same five-year option hold
period. In March 1994, BPA and the partnership reached an
additional agreement on the power purchase contract, setting
forth the terms and conditions on which BPA will purchase energy
and capacity from the project upon exercise of the option. The
partnership expects to complete development period tasks by the
end of l995. Project financing for construction costs would be
non-recourse to the Company.
The Company has invested $20 million in Ida-West. Ida-West
continues an active search for new projects.
Stellar Dynamics
In 1994, Idaho Power announced the formation of a fifth
subsidiary company. Stellar Dynamics will commercialize the
Company's extensive expertise in control technology for electric
substations and power plants. The Company approved the new
venture after receiving a positive recommendation from Newton-
Evans Research Company. The recommendation, based on a market
survey conducted by Newton-Evans, was backed by strong interest
from potential customers. One-third of the companies surveyed,
including several large investor-owned utilities, requested
product information. The primary opportunity for Stellar
Dynamics' design, consulting, installation, and troubleshooting
services lies in the U.S. substation controls market. The Company
expects to capitalize Stellar Dynamics in early 1995.
LIQUIDITY AND CAPITAL RESOURCES
Cash Flow
Net cash generation from operations totaled $377.3 million for
the three-year period 1992-1994. After deducting common and
preferred dividends of $221.7 million, net cash generation from
operations provided approximately $155.6 million for the
Company's construction program and other capital requirements.
Internal cash generation after dividends provided 30 percent of
total capital requirements in 1992, 54 percent in 1993, and 41
percent in 1994. Idaho Power expects to continue financing its
construction program with both internally generated funds and, to
the extent necessary, externally financed capital. Drought
conditions hurt the Company's internal cash generation two of the
last three years. The Company has first mortgage bond refundings
of $20.0 million in 1996 and $30.0 million in 1998. At January 1,
1995, the Company's lines of credit maintained with various banks
totaled $70.0 million. The total lines of credit maintained with
various banks will increase to $90.0 million at March 1, l995
(see Note 7 of Notes to Consolidated Financial Statements).
Construction Program
The Company's consolidated cash construction expenditures were
$118.0 million in 1992, $122.9 million in 1993, and $110.5
million in 1994. Approximately 42 percent of these expenditures
were for generation facilities, 8 percent for transmission
facilities, 38 percent for distribution facilities, and 12
percent for general plant and equipment. After completion of the
Swan Falls and Twin Falls projects, the Company does not
anticipate any new major generation construction projects.
Swan Falls Project
In early spring of 1994, the Company completed testing of the
Swan Falls Project and both units were declared available for
commercial operation. At December 31, 1994, the Company had spent
approximately $55.0 million for construction of the Swan Falls
Project, including allowance for funds used during construction.
Additional work to preserve the old power plant as an historical
site began during the year, while work to establish a museum on
the site is scheduled for completion in 1995. In May, crews
completed the federally-mandated stabilization of the dam and
began the environmental reclamation of approximately 18 acres of
land affected by construction activities.
Twin Falls Project
Expansion of the Twin Falls Project recently passed the halfway
point, with completion estimated for mid-1995. 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. Revised total cash
expenditures for the Twin Falls expansion are currently estimated
at $38.1 million, with total construction costs at $41.9 million,
including an allowance for funds used during construction. At
December 31, 1994, the Company had spent approximately $29.4
million on the Twin Falls Project. When completed, it will add 43
MW of new capacity to the Company's generation system.
Southwest Intertie Project (SWIP)
Idaho Power is continuing to study the economic feasibility of
constructing the SWIP to capitalize on its strategic location
between the Intermountain West and the Pacific Northwest. The
SWIP would serve as a major north-south transmission artery for
regional transfers of electric power. The Company's SWIP proposal
calls for a 500-mile, 500 kV transmission line that would
interconnect the Company's system with those of utilities in
California and the Southwest. In December 1994, the U.S. Bureau
of Land Management issued a favorable record of decision on the
Company's environmental impact statement and granted the project
a right-of-way across public lands in Idaho, Nevada, and Utah. At
present, the Company is conducting financial and contractual
discussions with potential partners in the project. Idaho Power
intends to retain up to 20 percent of ownership and capacity in
the 1,200 MW project. The SWIP may be built in segments as
warranted by demand for its transmission services.
Solar and Solar Photovoltaic Projects
Solar Two
Idaho Power is a member of a consortium supporting the upgrade of
an existing solar thermal power plant near Barstow, California.
The Company has committed $630,500 in direct support to improve
the plant's ability to store the sun's heat and use it later to
generate electricity. The Electric Power Research Institute
(EPRI), of which the Company is also a member, will contribute an
additional $630,500, bringing the Company's credited contribution
to approximately $1.3 million. Workers have completed over one-
third of the retrofitting to date. When finished, Solar Two will
use 1,900 mirrors to track the sun and focus its energy on a
central receiving tower. The project will use a molten-salt fluid
to store and transfer the collected heat. The main benefit the
Company will receive by participating in this 10 MW project, is
valuable experience and knowledge in solar power plant design,
construction, and operation.
Mountain Home Air Force Base
The U.S. Air Force retained Idaho Power to design, build, and
maintain one of the nation's largest hybrid solar-powered
photovoltaic (PV) systems. The $1.2 million project, completed in
February 1995, provides electricity to a remote Mountain Home AFB
radar training installation near Grasmere, Idaho. Under optimal
solar conditions, the PV system produces a peak capacity of
80,000 watts, reducing both the need for combustion generators
and the emissions they produce. Under the terms of the contract,
the federal government owns the system and pays the Company a
monthly maintenance fee.
International Photovoltaics Conference
The Company has been selected to host an international conference
on the emerging global business opportunities associated with
photovoltaic power applications. The Executive Conference on
Strategic Photovoltaic Business opportunities for Utilities is
scheduled for September 17-20, 1995 in Sun Valley, Idaho.
Representatives of the utility and PV industries and government
agencies will discuss how they and their organizations can plan
for and shape the influence of photovoltaics in developing and
changing utility markets.
Photovoltaic Service Tariff (PST)
The PST offers basic electric service for small loads at remote
sites as an alternative to either line extensions for grid
service or the use of on-site, fossil-fuel generators. In many
cases, PV technology offers a cost-effective solution for both
the customer and the Company. Idaho Power benefits by reducing
the number of costly line extensions to serve small loads that
produce little revenue. Under the PST, the customer pays a
monthly fee to receive electric service from a PV system
designed, installed, owned, and maintained by Idaho Power. The
program, which the Company launched in January 1993, is a pilot
offering with a $5,000,000 program limit and a $50,000 limit for
individual systems.
In 1994, the Company made significant operational and technical
improvements to its PST systems based on feedback from early PV
customers. Customer comments helped to identify obstacles to
customer acceptance of PV systems. To date, seven systems have
been installed and are operating as designed.
Financing Program
Capital Structure
The Company's capital structure (as illustrated in Selected
Financial Data) fluctuated during the three-year period, with
common equity growing to 45 percent, preferred rising to 9
percent, and debt falling to 46 percent. The Company's objective
is to maintain capitalization ratios of approximately 45 percent
common equity, 8-10 percent preferred stock, and the balance in
long-term debt. The Company's strategy for achieving this target
is through the use of accumulated retained earnings and the
issuance of new equity. The Company's pre-tax interest coverage
ratios were 2.50 times in 1992, 3.14 times in 1993, and 3.01
times in 1994. The Company has on file a shelf registration
statement for the issuance of first mortgage bonds and/or
preferred stock, with an aggregate principal amount not to exceed
$200.0 million. The Company's primary financial commitments at
year-end 1994 were related to contracts for the Company's
facility construction and maintenance program.
Common Stock
During the period of January 1992 through May 1994, the Company
issued original issue shares of common stock for its Dividend
Reinvestment and Stock Purchase Plan and the Employee Savings
Plan. During 1992, 1993, and 1994, common shares totaling
959,527; 898,528 and 527,296, respectively, were issued to these
plans. The net proceeds from these issues were used for the
Company's ongoing construction program.
Preferred Stock
On July 1, 1993, Idaho Power issued $25 million of serial
preferred stock. The Company used the net proceeds of this
issuance for its ongoing construction program.
Long-Term Debt
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 of that year, the Company used
the net proceeds 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 Company used the net proceeds to retire early first mortgage
bonds totaling $30,000,000, plus premiums and accrued interest.
Environmental Issues
Salmon Recovery Plan
Work continues on the development of a comprehensive and
scientifically credible plan to ensure the long-term survival of
anadromous fish runs on the Columbia and Lower Snake Rivers.
In mid-August 1994, the federal government changed its
designation of the Snake River Fall Chinook Salmon from
Threatened to Endangered. The Company does not anticipate that
the new designation will have any additional effects on its
operations. In September 1991, the Company modified operations at
its three-dam Hells Canyon Hydroelectric Complex to protect the
Fall Chinook downstream during spawning and juvenile emergence.
From its start, the Company's Fall Chinook program has exceeded
the protection requirements for threatened species, affording the
fish the same high level of protection due an endangered species.
Pending completion of a final recovery plan by the National
Marine Fisheries Service (NMFS), the U.S. Army Corps of Engineers
and other governmental agencies operating federally-owned dams
and reservoirs on the Snake and Columbia Rivers have consulted
the NMFS each year regarding federal system operations. On March
28, 1994, Judge Malcolm Marsh of the U.S. District Court for the
District of Oregon ordered the federal agencies to reinitiate the
consultation completed for 1993 operations of the federal system.
Judge Marsh concluded that the consultations and subsequent
operations were "...too heavily geared towards a status quo that
has allowed all forms of river activity to proceed..." at the
expense of fish. On September 9, 1994, the Ninth Circuit Court of
Appeals echoed Judge Marsh's decision when it found that the 1993
Strategy for Salmon proposed by the Northwest Power Planning
Council (NWPPC) was in violation of the 1980 Northwest Power
Planning Act. The appeals court ordered the NWPPC to focus on
saving young salmon and to defer to the expertise of state,
federal and tribal fisheries management agencies in developing
its salmon recovery program. Pursuant to the Ninth Circuit's
opinion, the NWPPC adopted amendments to its Strategy for Salmon
on December 15, 1994. The amended Strategy calls for a
substantial increase in water from the Snake River to aid
juvenile fish in their downstream migration to the sea. The Plan
requires the Bureau of Reclamation to acquire 500,000 acre-feet
of additional water by 1996 and another 500,000 acre-feet by 1998
for a total of 1,000,000 acre-feet in addition to the present
contribution of 427,000 acre-feet. This water is to be acquired
from willing sellers and could have a material impact on the
Company's power supply costs. The Plan also calls for an
additional 237,000 acre-foot contribution from the Company's
Brownlee Reservoir for which the Company is to be reimbursed for
by the BPA.
The Company expects a draft of the final Salmon Recovery Plan
from the NMFS by March 1, 1995. It is possible this recovery plan
could also have a material impact on the Company. The Company
hopes that anadromous fish runs can be restored without placing
undue hardship on either the Company or 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 U.S. District Court for the District
of Idaho. The Tribe alleged that the Company's construction,
operation, and maintenance of the three-dam Hells Canyon Project
prevented anadromous fish from reaching their traditional
spawning areas, destroyed certain fish runs, and prevented access
to certain of the Tribe's usual and accustomed fishing places.
These actions allegedly deprived the Nez Perce Tribe of its
treaty rights to take fish from the Columbia and Snake Rivers.
The Tribe is seeking compensatory and punitive damages, each in
an amount to be proven at trial.
Idaho Power maintains that the suit is without merit and asked
the federal court to issue a summary judgment dismissing the
action. The Company believes that the responsibility for concerns
expressed by the Nez Perce Tribe lies with the United States. The
Hells Canyon Project was licensed by the federal government, was
built in accordance with federally approved plans, and is
operated subject to federal regulation. The Company has complied
with all governmental requirements to mitigate any effects the
Project may have had on the fisheries.
On January 19, 1993, the Court took the Company's motion for
summary judgment under advisement. On July 30, 1993, U.S.
Magistrate Judge Larry Boyle issued a Report and Recommendation
to the District Judge. Judge Boyle recommended that the District
Judge grant that portion of the Company's motion for summary
judgment regarding the loss of fish and deny the portion of its
motion dealing with the Tribe's claim to compensation for
exclusion from its usual and accustomed fishing sites. On March
21, 1994, U.S. District Judge Harold L. Ryan upheld Judge Boyle's
recommendation regarding fish losses and took the question of
compensation for exclusion from fishing sites under advisement.
On September 28, 1994, after reviewing responses and objections
on that issue, Judge Ryan rejected the Tribe's claim and granted
the final portion of the Company's motion for summary judgment.
The Tribe has appealed Judge Ryan's decision to the Ninth Circuit
Court of Appeals. No date has been set for oral argument on the
appeal.
Snake River Mollusk
In mid-December, 1992, the U.S. Fish and Wildlife Service (USFWS)
listed the Snake River Mollusk as a Threatened and Endangered
Species. Since that time, the Company has included this
possibility in all of its discussions regarding relicensing and
new hydro development.
The listing specifically mentions the impact that fluctuating
water levels related to hydroelectric operations may have on the
snails' habitat. While most of the hydro facilities on that reach
of the Snake River are baseload facilities, some of them do
provide limited load-following capability. At present, there is
no certainty as to the impacts, if any, that water fluctuations
caused by these facilities may have on the snails. Idaho Power
intends to testify to the USFWS that there is little scientific
data in this area and that the Company proposes to study these
operations. While it is possible that the listing could affect
how Idaho Power operates its existing hydroelectric facilities on
the middle reach of the Snake River, the Company believes that
such changes will be minor and will not present any undue
hardship.
Mountaineer
In May 1993, the Company was notified that Bridger Coal Company
(BCC) was a potential contributor to a Superfund site involving
waste motor oil delivered to Mountaineer Refinery in Wyoming.
Idaho Energy Resources Company (IERCo), a wholly-owned subsidiary
of the Company, owns one-third of BCC. In November 1993, BCC
agreed to be included on the list of parties potentially
responsible for this site. The current estimated cleanup costs
are between $2.6 million and $5.0 million. During the past year,
more contributors were added to the list of potentially
responsible parties for cleanup of this site. Therefore, BCC's
portion of these costs, based on the amount of oil delivered to
the site, is estimated now to be approximately 5.0 percent, or
between $130,000 and $250,000. IERCo would be liable for one-
third of the BCC portion, or between $42,900 and $82,500. In 1994
BCC recorded expenses of $129,450 of which one-third flowed
through to the Company's consolidated financials. Of this amount,
$42,750 remains on BCC's books as an unfunded liability at
December 31, 1994.
Clean Air
Idaho Power has analyzed the Clean Air Act legislation's effects
on the Company and its ratepayers. The Company's coal-fired
plants in Oregon and Nevada already meet the federal sulfur
dioxide (SO2) emission rate standards. The Company's coal-fired
plant in Wyoming meets that state's even more stringent SO2
regulations. Therefore, the Company anticipates no adverse
effects on its operations with regard to SO2 emissions.
The Company, together with PacifiCorp and Black Hills
Corporation, entered into Phase I substitution agreements with
Illinois Power Company. The agreements designate Units 1, 2, 3,
and 4 of the Company's Jim Bridger thermal facility and
facilities owned by PacifiCorp and Black Hills Corporation as
substitution units for Baldwin #2, owned by Illinois Power. The
substitution agreements will allow the Company to grandfather in
less restrictive Phase I nitrous oxide emission requirements at
the Jim Bridger units. As part of the agreements, the Company
negotiated the sale of a number of its Phase I SO2 emission
allowances to Illinois Power.
Electric and Magnetic Fields (EMF)
While scientific research has yet to establish any conclusive
link between EMF and human health, the possibility has caused
public concern in the United States and abroad. Electric and
magnetic fields are found wherever there is electric current,
whether the source is a high-voltage transmission line or the
simplest of electrical household appliances. Concerns over
possible health effects have prompted regulatory efforts in
several states to limit human exposure to EMF. Depending on what
researchers ultimately discover and what regulations may be
deemed necessary, it is possible that this issue could affect a
number of industries, including electric utilities. However, at
this time it is difficult to estimate what impacts, if any, the
EMF issue could have on the Company and its operations.
Competition and Strategic Planning
Competition is increasing in the electric utility industry, due
to a variety of developments. In response, the Company continues
to proceed with a strategic planning process. The goal of this
process is to anticipate and fully integrate into Company
operations any legislative, regulatory, environmental,
competitive, or technological changes. With its low energy
production costs, Idaho Power is well-positioned to enter a more
competitive environment and is taking action to preserve its low-
cost competitive advantage (see Regulatory Issues - Cogeneration
and Small Power Production Contracts for a discussion of the
Company's revised resource acquisition policy).
On June 3, 1994 the IPUC approved the buyout and cancellation of
a January 22, 1993 Firm Energy Sales Agreement (FESA) with
Meridian Generating Company, L. P. (MGC). The FESA was a 25-year
agreement with MGC for a 54 MW natural gas-fired combined cycle
cogeneration facility located in Meridian, Idaho. The Company
estimates that the revenue requirement savings, including
cancellation charges paid to MGC, are between $130 and $170
million.
On June 28, 1994, Washington Water Power and Sierra Pacific
Resources announced that their respective boards of directors had
approved a merger agreement between the two companies. Idaho
Power is intervening in the approval process to ensure that the
proposed merger has no adverse effects on its operations. In
addition, the Company is actively identifying and responding to
business opportunities presented by the proposed merger.
Internally, the Company continues its commitment to refining its
business processes to ensure its ability to offer the greatest
possible value to its customers and its shareowners. Among these
strategic initiatives are:
- - the examination and refinement of the Company's distribution
function, work order, and line extension processes;
- - the initiation of a four-year, $3 million project to automate
and consolidate the operation of the Company's 17
hydroelectric power plants;
- - the formation of a Technical Advisory Panel, composed of
representatives from public and private interest groups, to
advise the Company on such matters as competition, alternative
resources, and conservation. The Company will use the panel's
advice as it reviews its IRP, due for publication in mid 1995.
- - the implementation of a Restricted Stock Plan and Employee
Incentive Plan to focus employees' attention on achieving
annual financial and operational goals, to promote and
reinforce teamwork, and to encourage employee accountability
for business results and the Company's responsiveness to a
competitive environment.
Relicensing of Hydroelectric Projects
Idaho Power is vigorously pursuing the relicensing of its
hydroelectric projects, a process that will continue for the next
10 to 15 years. The Company will submit its first applications
for license renewal to the Federal Energy Regulatory Commission
in December 1995. These first applications will seek renewal of
the Company's licenses for its Bliss, Upper Salmon Falls, and
Lower Salmon Falls Hydroelectric Projects. Although various
federal requirements and issues must be resolved through the
relicensing process, the Company anticipates that its efforts
will be successful. At this point, however, the Company cannot
predict what type of environmental or operational requirements it
may face, nor can it estimate the eventual cost of relicensing.
BOARD OF DIRECTORS
On January 12, 1995, the Company welcomed two new members to its
Board of Directors. Jack K. Lemley, 59, was Chief Executive
officer of Transmanche-Ling, the Anglo-French construction firm
that built the motor and rail transportation tunnel beneath the
English Channel. A former senior vice president of Morrison-
Knudsen Corporation, Mr. Lemley is currently President of Lemley
& Associates, Inc. Peter S. O'Neill, 56, is President of Boise-
based O'Neill Enterprises, Inc., a real estate development firm.
Mr. O'Neill served as a senior vice president of Boise Cascade
Corporation and as President of the Columbia-Willamette
Development Co.
Three directors retired from the board in accordance with the
Company's Restated Articles of Incorporation and By-Laws. The
articles and by-laws require directors to retire by age 70.
Former U.S. Senator James A. McClure and retired plumbing and
heating wholesaler Richard T. Norman left the board in December,
the same month as their 70th birthdays. Rancher George Coiner
retired at the January 12 board meeting. Mr. Coiner turns 70 in
February 1995.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
INDEX TO FINANCIAL STATEMENTS
AND FINANCIAL STATEMENT SCHEDULES
PAGE
Management's Responsibility for Financial Statements 58
Consolidated Financial Statements:
Consolidated Balance Sheets as of December 31, 1994,
1993 and 1992 59-60
Consolidated Statements of Income for the Years
Ended December 31, 1994, 1993 and 1992 61
Consolidated Statements of Retained Earnings for
the Years Ended December 31, 1994, 1993 and 1992 62
Consolidated Statements of Capitalization as of
December 31, 1994, 1993 and 1992 63
Consolidated Statements of Cash Flows for the Years
Ended December 31, 1994, 1993 and 1992 64
Notes to Consolidated Financial Statements 65-79
Independent Auditors' Report 80
Supplemental Financial Information (Unaudited) 81
Supplemental Schedule for the Years Ended December 31,
1994, 1993 and 1992:
Schedule II- Consolidated Valuation and
Qualifying Accounts 90
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 systems of internal accounting controls and
related policies and procedures. The systems are designed to
provide reasonable assurance that all assets are protected
against loss or unauthorized use. Also, the systems provide 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
LLP, 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
IDAHO POWER COMPANY
CONSOLIDATED BALANCE SHEETS
ASSETS
December 31,
1994 1993
1992
(Thousands of Dollars)
ELECTRIC PLANT (Notes 1, 5 and 10):
In service (at original cost) $2,383,898 $2,249,723 $2,198,747
Less accumulated provision for
depreciation 775,033 728,979 683,332
In service - Net 1,608,865 1,520,744 1,515,415
Construction work in progress 46,628 92,682 66,997
Held for future use 1,150 2,958 3,083
Electric plant - Net 1,656,643 1,616,384 1,585,495
INVESTMENTS AND OTHER PROPERTY 18,034 20,772 11,411
CURRENT ASSETS:
Cash and cash equivalents 7,748 8,228 4,966
Receivables:
Customer 31,889 29,741 28,687
Allowance for uncollectible
accounts (1,377) (1,377) (1,421)
Notes 4,962 5,616 1,669
Employee notes receivable 5,444 5,909 5,970
Other 4,316 1,858 1,695
Accrued unbilled revenues (Note 1) 29,115 25,583 27,210
Materials and supplies (at average
cost) 24,141 23,372 25,762
Fuel stock (at average cost) 11,310 11,553 14,282
Prepayments (Note 9) 21,398 20,975 22,171
Regulatory assets associated with
income taxes (Note 1) 5,674 4,914 -
Total current assets 144,620 136,372 130,991
DEFERRED DEBITS:
American Falls and Milner water
rights 32,605 32,755 32,890
Company-owned life insurance
(Note 9) 49,510 45,294 40,228
Regulatory assets associated with
income taxes (Note 1) 179,311 171,569 -
Regulatory assets - other (Note 1) 67,713 35,036 -
Other 43,380 39,235 61,292
Total deferred debits 372,519 323,889 134,410
TOTAL $2,191,816 $2,097,417 $1,862,307
The accompanying notes are an integral part of these statements.
IDAHO POWER COMPANY
CONSOLIDATED BALANCE SHEETS
CAPITALIZATION AND LIABILITIES
December 31,
1994 1993 1992
(Thousands of Dollars)
CAPITALIZATION (see Page 63):
Common stock equity (Note 3):
Common stock - $2.50 par value
(shares authorized 50,000,000;
shares outstanding 1994 -
37,612,351; 1993 - 37,085,055;
1992 - 36,186,527) $94,031 $92,713 $90,466
Premium on capital stock 363,063 350,882 326,338
Capital stock expense (4,132) (4,128) (3,806)
Retained earnings 220,838 222,900 212,404
Total common stock equity 673,800 662,367 625,402
Preferred stock (Note 4) 132,456 132,751 107,874
Long-term debt (Note 5) 693,206 693,780 701,948
Total capitalization 1,499,462 1,488,898 1,435,224
CURRENT LIABILITIES:
Long-term debt due within one
year 517 466 464
Notes payable (Note 7) 55,000 4,000 6,000
Accounts payable 32,063 31,912 34,821
Taxes accrued 16,394 15,452 16,182
Interest accrued 14,755 14,920 18,287
Other 12,574 13,731 12,125
Total current liabilities 131,303 80,481 87,879
DEFERRED CREDITS:
Accumulated deferred investment
tax credits (Notes 1 and 2) 71,593 72,013 73,651
Accumulated deferred income
taxes (Notes 1 and 2) 380,926 358,280 210,435
Regulatory liabilities associated
with income taxes (Note 1) 35,090 34,968 -
Regulatory liabilities - other
(Note 1) 626 4,235 -
Other (Note 9) 72,816 58,542 55,118
Total deferred credits 561,051 528,038 339,204
COMMITMENTS AND CONTINGENT
LIABILITIES (Note 8)
TOTAL $2,191,816 $2,097,417 $1,862,307
The accompanying notes are an integral part of these statements.
IDAHO POWER COMPANY
CONSOLIDATED STATEMENTS OF INCOME
Year Ended December 31,
1994 1993 1992
(Thousands of Dollars)
REVENUES (Note 1) $543,658 $540,402 $498,092
EXPENSES:
Operation:
Purchased power (Notes 8 and 10) 60,216 45,361 58,496
Fuel expense (Note 10) 94,888 87,855 96,710
Other 111,252 121,252 101,659
Maintenance 43,490 43,136 35,888
Depreciation (Note 1) 60,202 58,724 59,823
Taxes other than income taxes 23,945 22,129 20,562
Total expenses 393,993 378,457 373,138
INCOME FROM OPERATIONS 149,665 161,945 124,954
OTHER INCOME:
Allowance for equity funds used
during construction (Note 1) 1,680 3,060 2,400
Other - Net (Note 9) 10,480 9,924 8,733
Total other income 12,160 12,984 11,133
INTEREST CHARGES:
Interest on long-term debt 51,172 53,706 53,408
Other interest (Notes 1 and 7) 3,261 2,750 2,050
Total interest charges 54,433 56,456 55,458
Allowance for borrowed funds
used during construction
(Note 1) (1,781) (2,465) (2,523)
Net interest charges 52,652 53,991 52,935
INCOME BEFORE INCOME TAXES 109,173 120,938 83,152
INCOME TAXES (Notes 1 and 2) 34,243 36,474 23,162
NET INCOME 74,930 84,464 59,990
Dividends on preferred stock
(Note 4) 7,398 6,009 5,516
EARNINGS ON COMMON STOCK $ 67,532 $ 78,455 $ 54,474
AVERAGE COMMON SHARES OUTSTANDING
(000) 37,499 36,675 35,116
EARNINGS PER SHARE OF COMMON
STOCK (Note 3) $ 1.80 $ 2.14 $ 1.55
The accompanying notes are an integral part of these statements.
IDAHO POWER COMPANY
CONSOLIDATED STATEMENTS OF RETAINED EARNINGS
Year Ended December 31,
1994 1993 1992
(Thousands of Dollars)
RETAINED EARNINGS
Beginning of year $222,900 $212,404 $222,973
NET INCOME 74,930 84,464 59,990
Total 297,830 296,868 282,963
DIVIDENDS:
Preferred stock (Note 4) 7,398 6,009 5,516
Common stock (per share: 1994 -
1992 - $1.86) (Note 3) 69,594 67,959 65,043
Total dividends 76,992 73,968 70,559
RETAINED EARNINGS
End of year $220,838 $222,900 $212,404
The accompanying notes are an integral part of these statements.
IDAHO POWER COMPANY
CONSOLIDATED STATEMENTS OF CAPITALIZATION
December 31,
1994 % 1993 % 1992 %
(Thousands of Dollars)
COMMON STOCK EQUITY
(Note 3):
Common stock $94,031 $92,713 $90,466
Premium on capital stock 363,063 350,882 326,338
Capital stock expense (4,132) (4,128) (3,806)
Retained earnings 220,838 222,900 212,404
Total common stock
equity 673,800 45 662,367 44 625,402 44
PREFERRED STOCK (Note 4):
4% preferred stock 17,456 17,751 17,874
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 25,000 -
Total preferred stock 132,456 9 132,751 9 107,874 7
LONG-TERM DEBT (Note 5):
First mortgage bonds:
5 1/4% Series due 1996 20,000 20,000 20,000
6 1/8% Series due 1996 - - 30,000
5.33 % Series due 1998 30,000 30,000 -
8.65 % Series due 2000 80,000 80,000 80,000
7 3/4% Series due 2002 - - 30,000
6.40 % Series due 2003 80,000 80,000 -
8 3/8% Series due 2004 - - 35,000
8 % Series due 2004 50,000 50,000 50,000
8 1/2% Series due 2006 - - 30,000
9 % Series due 2008 - - 60,000
9.50 % Series due 2021 75,000 75,000 75,000
7.50 % Series due 2023 80,000 80,000 -
8 3/4% Series due 2027 50,000 50,000 50,000
9.52 % Series due 2031 25,000 25,000 25,000
Total first mortgage
bonds 490,000 490,000 485,000
Amount due within one year - - -
Net first mortgage
bonds 490,000 490,000 485,000
Pollution control revenue
bonds:
5.90 % Series due 2003 24,650* 25,050* 25,450*
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 170,910 171,310 171,710
*Amount due within one
year (450) (400) (400)
Net pollution control
revenue bonds 170,460 170,910 171,310
Project financing -
Ida-West - - 11,243
REA notes 1,768 1,834 1,899
Amount due within one year (67) (66) (64)
Net REA notes 1,701 1,768 1,835
American Falls bond
guarantee 20,905 21,055 21,190
Milner Dam note guarantee 11,700 11,700 11,700
Unamortized premium/
discount-Net (Note 1) (1,560) (1,653) (330)
Total long-term debt 693,206 46 693,780 47 701,948 49
TOTAL CAPITALIZATION $1,499,462 100 $1,488,898 100 $1,435,224 100
The accompanying notes are an integral part of these statements.
IDAHO POWER COMPANY
CONSOLIDATED STATEMENTS OF CASH FLOWS
Year Ended December 31,
1994 1993 1992
(Thousands of Dollars)
OPERATING ACTIVITIES:
Cash received from operations:
Retail revenues $ 457,202 $ 434,625 $ 432,594
Wholesale revenues 62,110 84,726 42,541
Other revenues 23,711 23,411 25,531
Fuel paid (94,530) (83,885) (96,839)
Purchased power paid (62,592) (50,246) (55,976)
Other operation & maintenance paid (171,774) (162,014) (145,518)
Interest paid (incl long
and short-term debt only) (52,376) (56,348) (52,310)
Income taxes paid (16,518) (32,512) (14,859)
Taxes other than income taxes paid (21,698) (22,165) (21,399)
Other operating cash receipts and
payments - Net 2,122 8,213 (5,917)
Net cash provided by operating
activities 125,657 143,805 107,848
FINANCING ACTIVITIES:
First mortgage bonds issued - 188,136 98,870
PC bond fund requisitions/other long- - 5,594 9,583
term debt
Common stock issued 13,402 26,781 56,223
Preferred stock issued - 24,781 -
Short-term borrowings - Net 51,000 (2,140) (42,500)
Long-term debt retirement (466) (191,878) (52,346)
Preferred stock retirement (166) (65) (270)
Dividends on preferred stock (7,565) (5,914) (5,620)
Dividends on common stock (69,594) (67,959) (65,043)
Net cash - financing activities (13,389) (22,664) (1,103)
INVESTING ACTIVITIES:
Additions to utility plant (110,523) (122,949) (118,048)
Conservation (6,830) (6,687) (5,287)
Other 4,605 11,757 14,327
Net cash - investing activities (112,748) (117,879) (109,008)
Change in cash and cash equivalents (480) 3,262 (2,263)
Cash and cash equivalents beginning
of year 8,228 4,966 7,229
Cash and cash equivalents end
of year $7,748 $8,228 $4,966
RECONCILIATION OF NET INCOME TO NET
CASH PROVIDED BY OPERATING ACTIVITIES:
Net income $74,930 $84,464 $59,990
Adjustments to reconcile net income to
net cash:
CSPP-Net amortization/(deferral) - (518) (3,587)
Depreciation 60,202 58,724 59,823
Deferred income taxes 13,866 6,690 8,179
Investment tax credit - Net (1,064) (1,583) (1,439)
Allowance for funds used during
construction (3,461) (5,525) (4,923)
Postretirement benefits funding
(excl pensions) (5,182) (7,481) (11,369)
Changes in operating assets and
liabilities:
Accounts receivable (635) 2,360 2,574
Fuel inventory 358 3,970 (129)
Accounts payable (2,376) (4,367) 6,107
Taxes payable 7,296 (1,141) 779
Interest payable 1,656 (1,010) 2,841
Other - Net (19,933) 9,222 (10,998)
Net cash provided by operating
activities $ 125,657 $ 143,805 $107,848
The accompanying notes are an integral part of these statements.
IDAHO POWER COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
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., Ida-West
Energy Company (Ida-West) and Stellar Dynamics. 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 (FERC) 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 FERC, the Company's weighted
average monthly AFDC rates for 1994, 1993 and 1992 were 8.2
percent, 9.6 percent and 8.7 percent, 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 March 29, 1993, the Idaho Public Utilities
Commission (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.
On January 31, 1994, the Company received an IPUC order
authorizing $17.2 million in general rate relief from the
IPUC representing a 4.2 percent overall increase in Idaho
retail rates. The relief is based on an 11.0 percent allowed
return on equity with an overall rate of return of 9.199
percent. The Company had requested $37.1 million in general
rate relief representing a 9.09 percent increase in rates, a
12.50 percent return on equity, and a 9.88 percent overall
rate of return. These increased rates are effective February
1, 1995.
In addition in May 1994, the Company filed for temporary
drought rate relief with the Oregon Public Utility Commission
(OPUC). The OPUC issued an accounting order that granted the
Company permission to defer with interest 60 percent of
Oregon's share in the Company's increased power supply costs
incurred between May 13, 1994 and December 31, 1994. After
the close of 1994, the Company is required to file with the
OPUC for an amortization proposal for the $1.3 million
deferral.
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 extension 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 2.93 percent in 1994, 2.92 percent in
1993 and 2.91 percent in 1992 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 Statement of
Financial Accounting Standards (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
earned on regulated assets are deferred and amortized to
income over the estimated service lives of the related
properties and credits earned on non-regulated assets or
investments are recognized in the year earned.
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.
REGULATION OF UTILITY OPERATIONS - The Company follows SFAS
No 71, "Accounting for the Effects of Certain Types of
Regulation", and its financial statements reflect the effects
of the different ratemaking principles followed by the
various jurisdictions regulating the Company. Pursuant to
SFAS 71 the Company capitalizes, as deferred regulatory
assets, incurred costs which are expected to be recovered in
future utility rates. The Company also records as deferred
regulatory liabilities the current recovery in utility rates
of costs which are expected to be paid in the future.
The following is a breakdown of regulatory assets and
liabilities for the years 1994 and 1993 (in millions of
dollars):
1994 1993
Millions of Dollars Assets Liabilities Assets Liabilities
Income Taxes $185.0 $35.1 $176.5 $35.0
Conservation 29.7 21.2
Postretirement Benefits 5.5 3.5
Postemployment Benefits 4.0 3.9
Other 28.5 0.6 6.4 4.2
Total $252.7 $35.7 $211.5 $39.2
The regulatory environment is becoming more complex resulting
from the expanding effects of competition. In the event that
recovery of cost through rates becomes unlikely or uncertain,
this would force the Company away from the cost of service
ratemaking and SFAS 71 would no longer apply. If the Company
were to discontinue application of SFAS 71 for some or all of
its operations then these items would represent stranded
investments. Certain regulators are currently reviewing ways
to allow the electric utilities to recover these investments
in the event the customers are allowed to choose their energy
supplier. However, if the Company was not allowed recovery of
its stranded investments it would be required to write off
the applicable portion of regulatory assets and the financial
effects could be significant.
OTHER ACCOUNTING POLICIES _ Debt discount, expense and
premium are being amortized over the terms of the respective
debt issues.
2. INCOME TAXES:
A reconciliation between the statutory federal income tax rate and the
effective rate for the years 1994, 1993 and 1992 is as follows:
1994 1993 1992
Amount Rates Amount Rates Amount Rates
(Thousands of Dollars)
Computed income taxes
based on statutory
federal income
tax rate $38,210 35.0% $42,328 35.0% $28,272 34.0%
Change in taxes resulting
from:
AFUDC (1,211) (1.1) (1,798) (1.5) (1,508) (1.8)
Investment tax credits (3,351) (3.1) (2,898) (2.4) (3,446) (4.1)
Repair allowance (1,575) (1.4) (2,975) (2.5) (2,278) (2.7)
Elimination of amounts
provided in prior
years (2,607) (2.4) (4,686) (3.9) (1,601) (1.9)
Current state income
taxes 1,496 1.4 2,693 2.2 973 1.2
Depreciation 2,812 2.6 4,116 3.4 1,738 2.1
Other 469 0.4 (306) (0.1) 1,012 1.1
Total provision for
federal and state
income taxes $34,243 31.4% $36,474 30.2% $23,162 27.9%
The provision for income taxes consists of the following:
Income taxes currently
payable:
Federal $20,016 $27,199 $16,366
State 1,425 4,168 56
Total 21,441 31,367 16,422
Income taxes deferred -
Net of amortization:
Federal 12,196 6,621 7,688
State 1,670 69 491
Total 13,866 6,690 8,179
Investment and other tax
credits:
Deferred 1,643 1,315 2,007
Restored (2,707) (2,898) (3,446)
Total (1,064) (1,583) (1,439)
Total provision for
income taxes $34,243 $36,474 $23,162
The provision for deferred income taxes consists of the following:
Deferred:
Excess of tax over book
depreciation normalized $12,813 $14,044 $12,474
Other 11,310 6,384 6,743
Total 24,123 20,428 19,217
Restored (10,257) (13,738) (11,038)
Total $13,866 $6,690 $8,179
During 1993, the Company settled federal tax liabilities on all
open years through the 1990 tax year; in 1994, it settled federal
tax liabilities on the 1991 and 1992 tax years and settled Idaho
tax liabilities on the 1987-1992 tax years except for immaterial
amounts that relate to a partnership.
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, 1994, the Company has recorded
regulatory assets of $185.0 million and regulatory liabilities in
the amount of $35.1 million which were offset by an equal amount
of accumulated deferred income tax. 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.
3. COMMON STOCK:
Changes in shares of the common stock of the Company for 1994,
1993 and 1992 were as follows:
Common Stock
Premium on
$2.50 Capital
Shares Par Stock
Value
(Thousands of Dollars)
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
Gain on reacquired 4% preferred
stock (Note 4) - - 126
Stock purchase plans 527,296 1,318 12,055
Balance at December 31, 1994 37,612,351 $94,031 $363,063
During the period of January 1992 through May 1994, the Company
issued original issue shares of common stock for its Dividend
Reinvestment and Stock Purchase Plan and the Employee Savings
Plan. During 1992, 1993, and 1994 common shares totaling 959,527;
898,528; and 527,296 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, 1994, the Company had 2,791,321 of its
authorized but unissued shares of common stock reserved for
future issuance under its Dividend Reinvestment and Stock
Purchase Plan and Employee Savings 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.
A restricted stock plan approved by shareholders at the May 1994
Annual Meeting was implemented January 1, 1995 as an equity-based
long-term incentive plan.
4. PREFERRED STOCK:
The number of shares of preferred stock outstanding at December
31, 1994, 1993 and 1992 were as follows:
Shares Outstanding at
December 31 Call Price
1994 1993 1992 Per Share
Preferred stock:
Cumulative, $100 par
value:
4% preferred stock
(authorized
215,000 shares) 174,556 177,506 178,735 $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) 250,000 250,000 - $103.535
to
$100.354
Auction rate preferred
stock, $100,000
stated value,
(authorized 500
shares)(c) 500 500 500 $100,000.0
0
Total 825,056 828,006 579,235
(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, 1994 was 5.16% and ranged
between 2.55% and 5.16% during the year.
During 1994, 1993 and 1992 the Company reacquired and retired
2,950; 1,229 and 3,178 shares of 4% preferred stock resulting in
a net addition to premium on capital stock of $126,066; $50,151
and $151,891, respectively. As of December 31, 1994 the overall
effective cost of all outstanding preferred stock was 6.55
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. 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 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 only first mortgage bonds maturing during the five-year
period ending 1999 are $20,000,000 in 1996 and $30,000,000 in
1998. Sinking fund requirements for the first mortgage bonds
outstanding at December 31, 1994 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
1992, 1993 and 1994, $350,000, $400,000, 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 1999 for pollution control bonds outstanding at
December 31, 1994 are $450,000 in 1995 and 1996, and $500,000 in
1997, 1998 and in 1999. As of December 31, 1993 and 1994, the
overall effective cost of all outstanding first mortgage bonds
and pollution control revenue bonds was 8.02 percent and
8.33 percent in 1992.
6. 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,
$762,575,000 for 1993, and $682,647,000 for 1994. The estimated
fair values for long-term debt are based upon quoted market
prices of the same or similar issues.
7. NOTES PAYABLE:
At January 1, 1995, 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. The total lines of credit maintained
with various banks will increase to $90,000,000 at March 1, 1995.
Under annual borrowing arrangements with these banks, the Company
is required to pay a fee of 1/10 of 1 percent on the available
and committed lines of credit. Commercial paper may be issued in
an amount not to exceed 25 percent 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,
1994 1993 1992
(Thousands of Dollars)
Balance at end of year $55,000 $4,000 $6,000
Effective annual interest rate
at end of year 6.1% 6.9%(a) 5.9%
(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%.
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 $9,500,000 at December 31, 1994. The
commitments are generally revocable by the Company subject to
reimbursement of manufacturers' expenditures incurred and/or
other termination charges.
The Company is currently purchasing energy from 62 on-line
cogeneration and small power production facilities with contracts
ranging from 1 to 33 years. Under these contracts the Company
could be required to purchase up to 692,000 (MWH) annually.
During the fiscal year ended December 31, 1994, the Company
purchased 543,000 (MWH) at a cost of $30.9 million.
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:
Incentive Plan - The Company implemented two annual incentive
plans and a long-term incentive plan effective January 1, 1995.
The Executive Annual Incentive Plan and the Employee Incentive
Plan tie a portion of each employee's compensation to achieving
annual operational and financial goals. The plans share common
goals designed to promote safety, control capital expenditures,
control operation and maintenance expenses and increase annual
earnings per share.
Restricted Stock Plan - The 1994 Restricted Stock Plan ("Plan")
approved by shareholders at the May 1994 Annual Meeting was
implemented January 1, 1995 as an equity-based long-term
incentive plan. The performance-based grant approach and
administrative guidelines for the Plan were developed by the
Compensation Committee of the Board of Directors ("Committee")
during 1994. The first grant under the Plan was made to all
officers during January 1995. For the first grant, the Committee
has selected a three-year restricted period beginning January 1,
1995, through December 31, 1997, with a single financial
performance goal of Cumulative Earnings Per Share ("CEPS"). To
receive a final share award, each officer must be employed by the
Company, as an officer, during the entire restricted period, and
the Company must achieve the CEPS performance goal established by
the Committee.
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 $5.5 million in 1994, $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 supplemental retirement
and death benefit payments to the participant and his or her
family. The plan is being financed by life insurance policies, of
which the Company is the beneficiary, with premiums being paid by
the Company. These policies have accumulated cash values of $47.1
million and $42.4 million at December 31, 1994 and 1993,
respectively, which do not qualify as plan assets in the
actuarial computation of the funded status. Based upon SFAS No.
87, the Company has recorded a liability of $4.6 million as of
December 31, 1994.
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 1994 1993 1992
(Thousands of Dollars)
Pension plan:
Service cost $ 6,049 $ 4,496 $ 3,762
Interest cost 12,263 11,688 10,926
Actual return on plan assets 312 (23,322) (10,877)
Deferred gain (loss) on plan assets (15,584) 9,848 (1,861)
Net cost $ 3,040 $ 2,710 $ 1,950
Approximate percentage included in
operating expenses 67% 66% 64%
Net deferred compensation plan costs
charged to other income (including
life insurance and SFAS No. 87
liability accrual)(a) $ 508 $ 1,372 $ 1,276
(a) These charges to the Income Statement have been
reduced by gains from the Company-Owned Life
Insurance (COLI) of $2,724,000; $1,638,000; and
$1,607,000 for 1994, 1993 and 1992, respectively.
Funded status and significant assumptions as of December 31:
Deferred
Pension Plan Compensation Plan
1994 1993 1994 1993
(Thousands of Dollars)
Actuarial present value of benefit
obligations:
Vested benefit obligation $128,162 $134,292 $19,148 $24,024
Accumulated benefit obligation $132,766 $139,270 $19,148 $24,027
Projected benefit obligation $167,103 $179,895 $19,681 $30,114
Plan assets at fair value 165,839 169,920 - -
Plan assets in excess of (or less
than) projected benefit obligation (1,264) (9,975) (19,681) (30,114)
Unrecognized net (gain) loss from
past experience different from
that assumed 6,040 17,295 2,173 7,295
Unrecognized prior service cost 6,365 1,460 (3,516) 2,546
Unrecognized net (asset) obligation
existing at date of initial
adoption (19.5 year straight-line
amortization) (2,756) (3,019) 6,440 7,053
Minimum liability adjustment - - (4,564) (10,807)
Net asset (liability) included in
the balance sheet $8,385 $5,761 $(19,148) $(24,027)
Discount rate to compute projected
benefit obligation 8.0% 7.0% 8.0% 7.0%
Rate for future compensation
increases 4.5 4.5 4.5 4.5
Expected long-term rate of return
on plan assets 9.0 9.0 - -
Supplemental Employee Retirement Plan (SERP) - The Company has a
nonqualified SERP that provides benefits in excess of Internal
Revenue Service limits (Section 401 (a)(17) of the Internal
Revenue Code) for highly paid individuals. The projected benefits
obligation of this plan was $857,000 and $525,000 at December 31,
1994 and 1993, respectively, with accrued pension costs of
$396,000 and $226,000. The Company's net periodic pension cost of
this plan was $125,000 and $36,000 for the same periods.
Savings Plan _ The Company has an Employee Savings Plan whereby,
for each $1 of employee contribution up to 6 percent of their
salary the Company will match 100 percent of the first 2 percent
employee contribution and 50 percent of the next 4 percent
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 $2,410,200 in 1994, $2,283,200 in 1993
and $2,046,100 in 1992. As of December 31, 1994, a total of
4,214,735 Idaho Power Company common shares were held in this
Plan.
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 and was
approved by IPUC Order No. 25880.
The following tables set forth the amounts to be recognized in
the Company's financial statements for year-end 1994 and 1993 and
the funded status of the plan in accordance with accounting
standard SFAS No. 106 as of December 31, 1993 and 1994.
December 31, 1994 December 31, 1993
(Thousands of Dollars)
Postretirement Benefit Cost:
Service cost $ 855 $ 750
Interest cost 3,334 3,610
Actual return on plan assets (1,114) (860)
Amortization of transition
obligation 2,040 2,040
Net amortization and deferral - -
Regulatory asset (1,907) (3,548)
Net cost (a) $ 3,208 $ 1,992
(a) Postretirement benefit costs charged to expense in 1992 was
$2,622,300
December 31, 1994 December 31, 1993
(Thousands of Dollars)
Funded Status:
Accumulated postretirement
benefit obligation (APBO) $(45,001) $(48,290)
Plan assets at fair value
12,116 11,840
APBO in excess of plan assets (32,885) (36,450)
Unrecognized gain/losses 773 4,670
Unrecognized transition obligation
36,720 38,760
Prepaid postretirement benefit cost $ 4,608 $ 6,980
Discount rate 8.25% 7.25%
Medical and dental inflation rate 7.25 6.75
Long-term plan assets expected 9.0 9.0
return
A one percent change in the medical inflation rate would change
the APBO by 7.3 percent and the postretirement expense for 1994
by 9.0 percent.
The Company has a retiree medical benefits funding program which
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 $776,400 in
1994, $632,500 in 1993, $1,733,000 in 1992. The funding to the
VEBA was $743,600 in 1994, $2,692,000 in 1993, and $2,977,400 in
1992, 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 OPUC 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
FERC deferral of $545,400 was expensed in 1994. The remaining
amount deferred, as a regulatory asset, at December 31, 1994 is
$5.5 million. The Company received IPUC Order No. 25880
authorizing the amortization of the $5.5 million over a 10-year
period.
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 has
recorded a liability and a regulatory asset of $4.0 million which
represents the costs associated with postemployment benefits at
December 31, 1994. The Company received IPUC Order No. 25880
authorizing the amortization of the regulatory asset over a 10-
year period.
10. ELECTRIC PLANT IN SERVICE AND JOINTLY-OWNED PROJECTS:
The following table sets out the major classifications of the
Company's electric plant in service and accumulated provision for
depreciation for the years 1994, 1993, and 1992.
Electric Plant in Service 1994 1993 1992
(Thousands of Dollars)
Production $1,301,525 $1,199,188 $1,194,148
Transmission 310,102 328,249 324,222
Distribution 625,149 582,604 545,490
General and Other 147,122 139,682 134,887
Total In Service 2,383,898 2,249,723 2,198,747
Less accumulated
provision for depreciation 775,033 728,979 683,332
In Service - Net $1,608,865 $1,520,744 $1,515,415
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, 1994 are as follows:
Company Ownership
Electric Accumulated
Plant In Provision For
Name of Plant Location Service Depreciation % MW
(Thousands of Dollars)
Jim Bridger Units 1-4 Rock Springs, WY $376,928 $150,599 33 693
Boardman Boardman, OR 59,488 24,112 10 53
Valmy Units 1 & 2 Winnemucca, NV 299,865 98,030 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 $46,097,000 in 1994,
$45,424,000 in 1993 and $42,291,000 in 1992.
The Company has contracts to purchase the energy from five PURPA
Qualified Facilities which are 50 percent owned by Ida-West.
Power purchased from these facilities amounted to $7,139,000 in
1994, $5,975,093 in 1993 and $1,848,904 in 1992.
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 consolidated financial
position of Idaho Power Company and subsidiaries at December
31, 1994, 1993 and 1992, and the results of their operations
and their cash flows for 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 LLP
Portland, Oregon
January 31, 1995
IDAHO POWER COMPANY
SUPPLEMENTAL FINANCIAL INFORMATION, UNAUDITED
QUARTERLY FINANCIAL DATA:
The following unaudited information is presented for each quarter of
1994, 1993 and 1992 (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.
Quarter Ended
March 31 June 30 September 30 December 31
1994
Revenues $128,810 $128,541 $151,031 $135,277
Income from operations 37,408 33,984 33,609 44,663
Income taxes 9,406 6,554 8,150 10,133
Net income 18,260 17,030 16,289 23,351
Dividends on preferred stock 1,789 1,819 1,862 1,928
Earnings on common stock 16,471 15,211 14,427 21,423
Earnings per share of common 0.44 0.41 0.38 0.57
stock
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
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 SCHEDULE
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
schedule.
(b) Reports on SEC Form 8-K. No reports on Form 8-K were filed
during the three months ended December 31, 1994.
(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
Number Dated
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)(i)1 The Revised Security Plans for
Senior Management Employees and
for Directors-a non-qualified,
deferred compensation plan
effective November 30, 1994.
10(n)(ii)1 The Executive Annual Incentive
Plan for senior management
employees effective January 1,
1995.
10(n)(iii)1 The 1994 Restricted Stock Plan
for officers and key executives
effective July 1, 1994.
*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).
___________________
1 Compensatory Plan
*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.
*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.
27 Financial Data Schedule
IDAHO POWER COMPANY
SCHEDULE II - CONSOLIDATED VALUATION AND QUALIFYING ACCOUNTS
Years Ended December 31, 1994, 1993 and 1992
Column C
Column A Column B Additions Column D Column E
Balance Charged Charged Balance
At to (Credited) At
Classification Beginning Income to Other Deductions End Of
Of Period Accounts (1) Period
(Thousands of Dollars)
1994:
Reserves Deducted From
Applicable Assets:
Reserve for
uncollectible
accounts $1,377 $1,360 $1,018(2) $2,378 $1,377
Other Reserves:
Injuries and damages
reserve $1,500 $1,804 $ - $1,804 $1,500
Miscellaneous
operating reserves $ 748 $ 429 $ (156) $ 81 $ 940
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
NOTES: (1) Represents deductions from the reserves for purposes for which
the reserves were created.
(2) Represents collections of accounts previously written off.
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 9, 1995 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 9, 1995
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/_ __ By:__/s/__Jon H. Miller ________ "
Roger L. Breezley Jon H. Miller
Director Director
By:__/s/_ John B. Carley_______ By:__/s/__Peter S. O'Neill ______ "
John B. Carley Peter S. O'Neill
Director Director
By:__/s/__Peter T. Johnson_____ By:__/s/__Gene C. Rose _______ "
Peter T. Johnson Gene C. Rose
Director Director
By:__/s/__Jack K. Lemley_____ By:__/s/__Phil Soulen _______ "
Jack K. Lemley Phil Soulen
Director Director
EXHIBIT INDEX
Exhibit Page
Number Number
10(n)(i) The Revised Security Plans for Senior 93
Management Employees and for Directors-
a non-qualified, deferred compensation
plan effective November 30, 1994.
10(n)(ii) The Executive Annual Incentive Plan for 126
senior management employees effective
January 1, 1995.
10(n)(iii) The 1994 Restricted Stock Plan for 128
officers and key executives effective
July 1, 1994.
12 Statement Re: Computation of Ratio of 133
Earnings to Fixed Charges.
12(a) Statement Re: Computation of 134
Supplemental Ratio of Earnings to Fixed
Charges.
12(b) Statement Re: Computation of Ratio of 135
Earnings to Combined Fixed Charges and
Preferred Dividend Requirements.
12(c) Statement Re: Computation of 136
Supplemental Ratio of Earnings to
Combined Fixed Charges and Preferred
Dividend Requirements.
21 Subsidiaries of Registrant. 137
23 Independent Auditors' Consent. 138
27 Financial Data Schedule 139