UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-K405
(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, 1996
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 (I.R.S. Employer
jurisdiction of Identification No.)
incorporation or
organization)
1221 W. Idaho Street, 83702-5627
Boise, Idaho
(Address of principal (Zip Code)
executive offices)
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 New York and Pacific
value)
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.
X
Aggregate market value of voting stock
held by nonaffiliates (January 31, 1997) $1,195,163,000
Number of shares of common stock outstanding at February 28, 1997
37,612,351
Documents Incorporated by Reference:
Part III, Item 10 Portions of the definitive proxy statement of
the Registrant to be filed pursuant to
Item 11 Regulation 14A for the 1996 Annual Meeting of
Shareowners to be held on May 7, 1997.
Item 12
Item 13
TABLE OF CONTENTS
PART I
Page
Item 1. Business 2
The Company 2
Power Supply 5
Fuel 10
Water Rights 10
Regulation 11
Environmental Regulation 12
Rates 13
Construction Program 15
Financing Program 16
Item 2. Properties 17
Item 3. Legal Proceedings 19
Item 4. Submission of Matters to a Vote of Security Holders 22
Executive Officers of the Registrant 22
Part II
Item 5. Market for the Registrant's Common Stock and
Related Stockholder Matters 23
Item 6. Selected Financial Data 24
Item 7. Management's Discussion and Analysis of Financial
Condition and Results of Operations 26
Item 8. Financial Statements of Supplementary Data 40
Item 9. Changes in and Disagreements with Accountants and
Financial Disclosure 63
Part III
Item 10. Directors and Executive Officers of the Registrant* 63
Item 11. Executive Compensation* 63
Item 12. Security Ownership of Certain Beneficial Owners and
Management* 63
Item 13. Certain Relationships and Related Transactions* 63
Part IV
Item 14. Exhibits, Fianancial Statement Schedule and Reports
on Form 8-K 63
Signatures 70
*Incorporated by Reference.
The exhibit index is located on Page 71. This document contains
145 pages.
PART I
ITEM 1. BUSINESS
THE COMPANY
This Form 10-K contains "forward-looking statements" intended to
qualify for safe harbor from liability established by the Private
Securities Litigation Reform Act of 1995. Forward-looking
statements should be read with the cautionary statements and
important factors included in this Form 10-K at Part II, Item 7.
Management's Discussion and Analysis of financial condition and
Results of Operations - Forward-Looking Information. Forward-
looking statements are all statements other than statements of
historical fact, including without limitation those that are
identified by the use of the words "anticipates," "estimates,"
"expects," "intends," "plans," "predicts," and similar
expressions.
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 754,000 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 changing weather, precipitation and streamflow
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 operating
results are more dependent upon general regulatory, economic,
temperature and competitive conditions and less on precipitation
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. As of December 31, 1996, the Company
supplied electric energy to 352,487 general business customers
and employed 1,645 people in its operations (1,565 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, 1996, total system
electric revenues from residential customers accounted for 35
percent of the Company's total operating revenues. Commercial
customers with less than 1,000 kW demand including street
lighting customers accounted for 19 percent, industrial customers
with 1,000 kW demand and over accounted for 19 percent and
irrigation customers accounted for 11 percent. Public utilities
and interchange arrangements accounted for 12 percent and other
operating revenues accounted for 4 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.
Subsidiaries -
The Company has six wholly-owned subsidiary companies: Ida-West
Energy Company (Ida-West), Idaho Energy Resources Co. (IERCo),
Idaho Utility Products Company (IUPCo), IDACORP, Inc., Idaho
Power Resources Corporation (IPRC) and Stellar Dynamics, Inc.
(Stellar).
Ida-West was formed in 1989 to participate through partnership
interests in cogeneration and small power production (CSPP)
projects. Ida-West holds investments in thirteen operating
hydroelectric plants with a total generating capacity of
approximately 72 megawatts (MW).
In January 1996, Ida-West made an investment by acquiring all of
the outstanding bonds that were issued to finance three
hydroelectric plants known collectively as the Friant Power
Project. This project is located at the U.S. Bureau of
Reclamation's Friant Dam on the headwaters of the San Joaquin
River in Madera and Fresno Counties, California. It has an
aggregate generating capacity of 27.4 MW. The project is owned
and operated by Friant Power Authority, a quasi-governmental
entity consisting of six irrigation districts, a water district,
and a municipal utility district.
In November 1996, Ida-West purchased an interest in five
hydroelectric projects located in Shasta County, California, with
a total generating capacity of 11.2 MW. Ida-West acquired the
projects through a limited liability company in which it holds a
50 percent interest.
In addition, Ida-West has an interest in the Hermiston Power
Project, a 460 MW, gas-fired cogeneration project to be located
near Hermiston, Oregon. Ida-West has been responsible for
managing all permitting and development activities relating to
the project since its inception in 1993, and has obtained all
permits necessary for construction and operation of the project.
The partnership is exploring various alternatives for marketing
the project's output. Project financing for construction costs
would be non-recourse to Idaho Power.
The Company has purchased all of the power from five Idaho
hydroelectric entities of Ida-West, totaling approximately $9.0
million.
Ida-West continues to actively seek to develop new projects. At
December 31,1996 the Company's total investment in Ida-West was
$21.8 million. (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 power
plant near Rock Springs, Wyoming (see "Fuel"). As of December 31,
1996, the Company's total investment in IERCo was $4.4 million.
IDACORP, Inc. was organized in 1986 to pursue a non-regulated
diversification program. At the end of 1996 IDACORP was
participating in five affordable housing programs which provide a
return primarily by reducing federal income taxes through tax
credits and tax depreciation benefits. As of December 31, 1996,
the total investment in IDACORP was $6.2 million.
IPRC, is a wholly-owned subsidiary, incorporated in March 1996 to
provide guidance, resources, and long-term strategic planning to
projects or business proposals that are not subject to regulation
by the FERC and the state regulatory commissions. IPRC's goals
are to establish, acquire, and expand business operations in
sustainable infrastructure technology and services including
energy, water, waste disposal, telecommunications, and
information systems. The Company has invested approximately $4.0
million in development and acquisition activities in IPRC.
IPRC has a Memorandum of Understanding signed by Idaho Power and
representatives from the government of Indonesia on March 6,
1996, clearing the way to conduct a detailed feasibility study on
using solar photovoltaic (PV) technology, micro hydroelectric
systems, and other renewable energy systems to provide
electricity to various locations throughout Indonesia's complex
of islands. IPRC is currently reviewing results of the completed
business plan. If the project is deemed workable and receives
the required approvals, IPRC would likely begin to develop
services in late 1997.
In October 1996, IPRC acquired a majority interest in Applied
Power Corporation (APC), a Lacey, Washington-based, company that
designs, supplies, and distributes photovoltaic (PV) systems.
Stellar was formed in 1995 to commercialize the Company's
extensive expertise in control technology for electric
substations and power plants. Today, the market focus lies in the
integration of complex control and automation systems for both
the electric utility sector and industrial applications. Stellar
also provides design and engineering for complete electric
substations. The geographic market for Stellar is mainly in the
western U.S. with some emphasis in the remaining U.S., Canada and
abroad. As of December 31, 1996, total investment in Stellar was
$0.8 million.
IUPCO was formed in 1983 to develop and market products to the
utility industry. The Company's total investment was $0.4
million in IUPCO at December 31, 1996.
Research and Development and Renewable Energy Sources -
During 1996, the Company spent approximately $1.8 million on
research and development of which $1.5 million was through the
Company's membership in Electric Power Research Institute (EPRI).
EPRI's mission is to discover, develop and deliver advances in
science and technology. Some of the projects benefits to the
Company include: electrification technologies, power quality,
electric transportation systems, EMF assessment/risk management
and air quality issues. The Company also has an internal research
and development effort called the Emerging Technology (ET)
Program. The ET program was established to maintain an active and
coordinated response to new technology of interest to the
Company.
In 1992, the Company joined Southern California Edison, the U.S.
Department of Energy and others in retrofitting an existing 10-
megawatt central receiver solar thermal experimental power plant
now called Solar Two near Barstow, California. The Company will
have contributed $630,500 through 1997 and the EPRI will
contribute an additional $630,500 of matching funds, bringing the
Company's credited contribution to approximately $1.3 million.
Solar Two was first synchronized to Southern California Edison's
system in May 1996. The main benefit the Company will receive by
participating in this project is valuable experience and
knowledge in solar plant design, construction and operation.
The Company offers Photovoltaics for basic electric service on
small loads at remote sites as an alternative to either line
extensions for grid service or the use of on-site, fossil-fuel
generators. The customer pays a monthly fee to receive electric
service from a solar PV system designed, installed, owned, and
maintained by Idaho Power. The service, 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. To
date, Idaho Power has installed 32 solar photovoltaic (PV)
systems. All of these systems are operating as designed.
In 1996, the Company's newly-formed subsidiary, IPRC, acquired a
majority interest in APC, a company that would partner with
interested electric utilities to provide energy services to
remote locations within their service territories. This company
would work on behalf of the utilities to offer solar PV energy
systems at the lowest possible cost to the consumer. While the
domestic utility market is promising in itself, IPRC is also
pursuing international opportunities for its renewable energy
expertise (see "Subsidiaries").
Energy Efficiency -
The Company continues to promote the efficient use of electrical
energy. 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
1996, the Company expended $4.4 million on its various energy-
efficiency programs.
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, below
normal precipitation created drought conditions reducing
reservoir storage. In 1995 and 1996, however, the Company's
service territory experienced above average water years. The
system peak demand for 1996 was 2,661 megawatts set on July 9,
1996. Peak demand for 1995 and 1994 were 2,393 and 2,392
megawatts respectively.
The following table sets forth the total energy sources of the
Company for the last three years:
Total Energy Sources
(000's of MWH)
1996 % 1995 % 1994 %
Generation - net
station output -
Hydro 10,713.5 58 9,277.2 58 6,213.2 40
Coal-fired 4,783.0 26 4,591.9 29 7,221.8 46
Purchased and
interchange 3,067.3 16 2,155.9 13 2,287.0 14
Total 18,563.8 100 16,025.0 100 15,722.0 100
Historically, under normal water conditions, the Company's hydro
system supplies approximately 57 percent, thermal generation
accounts for 34 percent and purchased power and other
interchanges contribute the remaining 9 percent of total system
requirements. Preliminary 1997 reports indicate the mountain
snowpack is well above normal for this time of year and the
carryover reservoir storage throughout the Snake River Basin is
close to 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.
Purchased power expenses fluctuated during the three-year period
reflecting necessity purchases from neighboring utilities due to
the 1994 drought. Purchased power expenses were lower in 1995,
reflecting better hydro conditions for the year. In 1996,
purchased power expenses were higher as the Company took
advantage of low wholesale market prices due to the abundance of
hydro generation in the West, which allowed the Company to
remarket this energy to others. Increased purchases from CSPP
projects also increased purchased power expenses in 1996.
The Company periodically updates its load and resource
projections and now expects total Company energy requirements
over the next 10 years to grow at an annual rate of 1.8 percent.
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,
PacifiCorp, The Montana Power Company and Sierra Pacific Power
Company (SPPCo). 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 Western Systems Coordinating
Council, the Western Systems Power Pool, the Northwest Power
Pool, the Western Regional Transmission Association and the
Northwest Regional Transmission Association.
Competition -
Competition is increasing in the electric utility industry. The
National Energy Policy Act of 1992, FERC rule-makings, state
initiatives, customer demands, and pending legislation at the
national and state level, all indicate increasing wholesale and
ultimately retail competition. With its low energy production
costs, the Company believes it is well-positioned to enter a more
competitive environment and is taking action to preserve its low-
cost competitive advantage.
The legislatures and/or the regulatory commissions in several
states, and at a national level, 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. While
proposals have been advanced, the Idaho Legislature has not yet
addressed retail wheeling but the Idaho Public Utilities
Commission (IPUC) has conducted an issues dialogue process and
established workshops for discussing retail wheeling issues among
affected parties in 1996 (see "Regulation").
In response to increased competition in the industry, the
potential ability of retail customers to choose their electric
provider and the apparent deregulation of the electric power
industry, the Company has adjusted 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 in the market. 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 and other
utilities, the Company has access to all the major electric
systems in the West.
Marketing Business Unit -
To accommodate its customers and allow itself to compete in the
rapidly evolving competitive market, the Company formed a
Marketing Business Unit in January 1997. This new business unit
will be responsible for all purchases and sales of electric
energy, market research and the planning and implementation of
marketing strategies.
There are three core components to the new business unit:
Product development, which is responsible for creating and
commercializing all new energy products and services; Supply and
logistics, which is responsible for energy supply aggregation,
delivery and risk management; and Sales, which is responsible
for market aggregation and sales of energy products and service
offerings to its customers.
The new business unit will offer a comprehensive program of
energy supply and management services, and will expand its
current product line to include several new energy service
options. Existing and planned product offerings include both
firm and interruptible short-term, month-to-month, and long-term
customized energy supply options and multiple pricing options
including fixed, floating, and indexed. The business unit's
service options will include energy scheduling, energy reserve
products, risk management, load shaping and following service,
summary billing and energy analysis for multiple customer
facilities, and multi-fuel management service. Fuel management
services will provide a means to partially or completely
outsource the administrative and operational duties associated
with managing all or part of our customers energy supply
requirements.
Southwest Intertie Project (SWIP) -
The Company has been investigating the feasibility of
constructing and operating a new transmission line that could
serve as a major path for regional transfers of power between the
Northwest and desert Southwest. SWIP is a proposed 500-mile, 500-
kV transmission line that would interconnect the Company's system
with utilities in California and the Southwest. In December 1994,
the US Bureau of Land Management (BLM) 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. The Company intends to retain up to a 20 percent
ownership in the 1,200 megawatt line.
The Company and interested parties have completed ownership
allocation and negotiations for the execution of the Memorandum
of Agreement (MOA). When the MOA is executed, the Company will
require each party to pay its share of the approximately $8.5
million expended for environmental permitting, right-of-way
acquisition, and related development activities. The SWIP owners
will then form an Executive Committee, with voting rights
proportional to each share of the project. The Executive
Committee will oversee development activities for the SWIP and
related projects.
As of December 31, 1996, the Company's Southwest Intertie Project
(SWIP) is on hold. At the current time, an order from the Public
Service Commission of Nevada is still pending, that would allow
Nevada Power to participate in the project.
The final development of SWIP may be impacted by regional efforts
to form an independent transmission and operator to eliminate
market control and provide improved transmission access for all
system users (see "Independent Grid Operator").
Transmission Services -
The Company has long had an informal open-access transmission
policy and is experienced in providing reliable, high quality,
economical transmission service. The Company provides various
firm and non-firm wheeling services for several surrounding
utilities. In July 1996, the Company filed an open-access tariff
with the FERC, in compliance with Order 888. The terms and
conditions of the tariff were approved for use beginning in 1997.
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 is
advantageous both in providing transmission service and reaching
a broad power sales market. The Company is a member of both the
Western Regional Transmission Association and the Northwest
Regional Transmission Association. These associations will help
facilitate transmission access and planning throughout the power
system.
Independent Grid Operator -
Recently a group of seven investor-owned Northwest electric
companies, including Idaho Power, BPA, and five public electric
entities signed a memorandum of understanding that will create an
independent transmission grid operator called "IndeGO". IndeGO
will ensure non-discriminatory, open-access to electricity
transmission facilities in compliance with recent FERC rulings.
The memorandum of understanding is an agreement to investigate
the feasibility of developing a regional transmission grid which
would be operated by an entity independent of power market
interests. It is believed that the formation of such an entity
will facilitate the operation of an evolving competitive electric
power market. Operating as one regional system, the utilities
will be able to increase the efficiency of transmission
operations and provide improved access for all system users.
IndeGo is envisioned as an independent transmission company not
controlled by any individual power market participant. It is
anticipated that IndeGO will operate as a single control area,
with pricing based on a single zonal tariff applied equally to
all users including the participating companies.
IndeGO will not own transmission facilities initially, but will
be responsible for the operation of main transmission grid
facilities 230 kilovolts (kV) or more that are owned by the
participating utilities. The area encompassed by the IndeGo has
over 20,000 miles of transmission lines accounting for about 97%
of the northwest grid.
The group plans to file the IndeGo proposal with FERC by July
1997, and anticipates operation would commence as early as 1999.
If the FERC's approval arrives by April 1998, an IndeGo Board and
Site Procurement could be expected by July 1998.
Forecast Energy and Peak Demand -
The following tables show how the Company expects to meet its
forecast energy and peak demand requirements through 2001 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)
1997 1998 1999 2000 2001
Generation capability 2,681 2,681 2,681 2,681 2,681
Less net peak load 2,438 2,493 2,541 2,590 2,635
Plus contract power(b) 313 313 313 313 313
Peak capability margin 556 501 453 404 359
Percent capability margin(c) 22.8% 20.1% 17.8% 15.6% 13.6%
(a) Based upon median hydro conditions.
(b) Sum of exchange and CSPP contracts.
(c) Capability margin divided by the net peak load.
Annual Energy Capability
(000's of MWH) (a)
1997 1998 1999 2000 2001
Generation Capability 15,097 15,220 15,279 15,313 15,471
Contracts: Cogeneration
and small power production 832 832 832 832 832
Annual firm load (15,572) (15,905) (15,965) (16,040) (16,271)
Energy capability margin 357 147 146 105 32
Percent (b) 2.3% 0.9% 0.9% 0.7% 0.2%
(a) Forecast based upon average of 68 historical water conditions.
(b) Energy capability margin divided by the generating capability.
During the 1997-2001 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 and through purchases of power from neighboring
utilities or marketing entities.
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 67 CSPP projects on-line as of December
31, 1996, is $55.9 million. During 1996, the Company purchased
776.4 million kilowatt-hours of power from these private
developers at a blended price of 5.6 cents per kilowatt-hour.
With the potential deregulation of the electric utility industry
and a more competitive power supply marketplace, the Company
believes that resource acquisition policies must avoid burdening
the Company and its customers with unnecessary future power
supply costs. In 1993, the Company requested, and in 1995
received approval, to lower published CSPP rates for new
projects. In addition, the IPUC determined that negotiated rates
for future CSPP projects larger than 1 megawatt (MW) should be
tied more closely to values determined in the Company's
integrated resource planning process. In a subsequent order
issued on September 4, 1996, the IPUC further recognized the
coming changes by limiting the contract term which a new CSPP
project larger than 1 MW could request to a maximum of five years
(see "Rates").
Firm Wholesale Power Sales -
The Company has firm wholesale power sales contracts with several
entities in the West. These contracts are for various amounts of
energy, ranging from 6 to 75 average megawatts, and are of
various lengths presently scheduled to expire between 1997 and
2009. The Company is actively marketing this power to other
entities as it becomes available.
FUEL
The Company, through Idaho Energy Resources Co., owns a one-third
interest in the Bridger Coal Company which owns 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 and provides for
delivery of coal over a 51-year period that began in 1974. The
original contract of 41 years was extended for 10 years on
January 1, 1996. (See Item 2 "Properties".) The Jim Bridger Coal
Mine has sufficient reserves to provide coal deliveries pursuant
to the sales agreement. 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 (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.
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 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 acquired under applicable provisions of state law for all
waters used in its hydroelectric generating facilities. In
addition, the Company holds water rights for domestic,
irrigation, commercial and other necessary purposes related to
other land and facility holdings within the state. The exercise
and use of all of these water rights are subject to prior rights
and, with respect to certain hydroelectric facilities, the
Company's water rights for power generation are subordinated to
future upstream diversions of water for irrigation and other
recognized consumptive uses.
Over time, increased irrigation development and other consumptive
diversions have resulted in some reduction in the stream flows
available to fulfill the Company's water rights at certain
hydroelectric generating facilities. In reaction to these
reductions, the Company initiated and continues to pursue a
course of action to determine and protect its water rights. As
part of this process, the Company and the state of Idaho signed
the Swan Falls agreement on October 25, 1984 which provided a
level of protection for the Company's hydropower water rights at
specified plants by setting minimum stream flows and establishing
an administrative process governing the future development of
water rights that may affect the Company's hydroelectric
generation. In 1987, Congress passed and the President signed
into law House Bill 519. This legislation permitted
implementation of the Swan Falls agreement and further provided
that during the remaining term of certain of the Company's
project licenses that the relationship established by the
agreement would not be considered by the FERC as being
inconsistent with the terms of the Company's project licenses or
imprudent for the purposes of determining rates under Section 205
of the Federal Power Act. The FERC entered an order implementing
the legislation on March 25, 1988.
In addition to providing for the protection of the Company's
hydropower water rights, the Swan Falls agreement contemplated
the initiation of a general adjudication of all water uses within
the Snake River basin. In 1987, the director of the Idaho
Department of Water Resources filed a petition in state district
court asking that the court adjudicate all claims to water
rights, whether based on state or federal law, within the Snake
River basin. A commencement order initiating the Snake River
Basin Adjudication was signed by the court on November 19, 1987.
This legal proceeding was authorized by state statute based upon
a determination by the Idaho Legislature that the effective
management of the waters of the Snake River basin required a
comprehensive determination of the nature, extent and priority of
all water uses within the basin. The adjudication is expected to
continue past the turn of the century. The Company has filed
claims to its water rights within the basin and is actively
participating in the adjudication to ensure that its water rights
and the operation of its hydroelectric facilities 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 under the regulatory jurisdiction (as to rates,
service, accounting and other general matters of utility
operation) of the FERC, the IPUC, the Oregon Public Utilities
Commission (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 1997 and during the period 1998-2001
will total approximately $0.7 million and $29.1 million,
respectively. Mitigation of environmental concerns due to
relicensing of hydro facilities will be a major portion of these
expenditures. The Company also anticipates spending approximately
$21 million a year in operating expenses for environmental
facilities during the 1997-2001 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's legislation and its
effects upon the Company and its rate payers. The Company's coal-
fired plants in Nevada and Oregon already meet the federal
emission rate standards for sulfur dioxide (SO2) and the
Company's coal-fired plant in Wyoming meets that state's even
more stringent SO2 regulations. The Company anticipates no
material adverse effect upon its operations. The Company has
entered into a joint arrangement with PacifiCorp and Black Hills
Corporation 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 super saturating 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 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 has also
installed and operates water quality monitors at the Milner and
Twin Falls hydroelectric projects, in order to meet compliance
standards for water quality.
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 1996, the investment in these facilities was $12.2
million and the operation of these facilities pursuant to the
FERC License 1971 cost approximately $2.2 million annually.
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, 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
TSCA for the continued use of equipment containing PCBs. The
Company has a program to make the 200-plus substations on its
system non-PCB. While the Company's use of equipment containing
PCBs falls well within the federal 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. Total Company costs for the disposal of PCBs
from the Company's system were $1.3 million, $0.4 million and
$0.9 million for 1994, 1995 and 1996 respectively.
RATES
Idaho Jurisdiction
Since 1993, the IPUC has permitted Idaho Power to use a PCA
mechanism in its Idaho jurisdiction. The PCA enables the Company
to collect or to refund a portion of the difference between net
power supply costs actually incurred and those allowed in the
Company's base rates. The current balance is adjusted monthly as
actual conditions are compared to the PCA forecasted net power
supply costs. For the period May 1996 through May 1997, the IPUC
approved tariffs, reducing Idaho jurisdictional PCA rates by
$25.7 million (5.9 percent), including the true-up for the PCA
period May 1995 through May 1996. The reduction reflects
anticipated lower power supply costs in the coming year due to
above-average hydroelectric generating conditions. The 1996 PCA
forecast reflects power supply costs below those established for
PCA expenses in the Company's last general rate proceeding. At
December 31, 1996, the Company had recorded as a deferred asset
and reduction in operating expenses $11.4 million of power supply
costs above those projected in the 1996 forecast.
On January 31, 1995, the Company received IPUC Order No. 25880,
which authorized $17.2 million in general rate relief,
representing a 4.2 percent overall increase in Idaho retail
rates. The relief was based on an 11.0 percent allowed return on
equity and an overall rate of return of 9.2 percent. The increase
in Idaho retail rates went into effect on February 1, 1995. It
also allows Idaho Power to realign its overall rate structure to
a price, more closely associated with the cost of serving the
different customer classes.
On May 24, 1995, Idaho Power filed another application with the
IPUC to increase rates in its Idaho jurisdiction. In August 1995,
the IPUC issued an order authorizing the Company to increase its
Idaho retail rates on an annual basis by $3.8 million (0.9
percent). This increase was uniform to all customer classes, as
well as to special contract customers. The Company originally
applied for a $6.3 million (l.5 percent) increase to recover
capital costs and related expenses associated with the
construction of a new 43.5 megawatt (MW) power plant at its Twin
Falls hydro facility, along with additional plant investments at
the Swan Falls hydro facility since the filing of its last
general rate case. The major issue in this case was whether the
reduced power supply costs resulting from the inclusion of the
Twin Falls hydro expansion would be recognized explicitly through
a reduction in base energy rates or implicitly through the PCA.
The Company reached a compromise with the IPUC staff on the
overall revenue requirement and agreed to recognize benefits up
front in base rates, instead of flowing the benefits through the
PCA. As a result, the Company's original $6.3 million request was
reduced by $1.9 million. The effect on projected Company
earnings is only 10 percent of this amount ($190,000), since all
but 10 percent of the power supply cost reduction would have been
passed through to Idaho customers in the next PCA adjustment. The
IPUC action enabled the Company to begin recovering the capital
costs of a plant addition within weeks of the plant becoming
operational.
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, the IPUC issued an order on
January 31, 1995, approving lower published CSPP rates for new
projects. In addition, the IPUC determined that negotiated rates
for future CSPP projects larger than 1 MW should be tied more
closely to values determined in the Company's integrated resource
planning process. In a subsequent order issued on September 4,
1996, the IPUC further recognized the coming changes by limiting
the contract term which a new CSPP project larger than 1 MW could
request to a maximum of five years.
On August 3, 1995, Idaho Power filed a proposal with the IPUC to
support the Company's organizational redesign. In response to
the Company's proposal, the IPUC approved a Settlement that
authorizes the Company to defer and amortize costs related to
reorganization in return for a general rate freeze through the
end of 1999. In addition, the Settlement allows for the
accelerated amortization of regulatory liabilities associated
with accumulated deferred investment tax credits (ADITCs) to
provide a minimum 11.50 percent return on actual year-end common
equity for the Idaho jurisdiction. The new rate freeze and the
accelerated amortization of regulatory liabilities associated
with ADITCs gives the Company time to pursue and to implement its
efficiency and growth initiatives with the assurance of at least
a reasonable level of financial performance apart from the need
to change customer prices.
The terms and conditions of the Settlement will remain in effect
through 1999. Under the Settlement, when the Company's actual
earnings in a given year exceed an 11.75 percent return on year-
end common equity, the Company will refund 50 percent of the
excess to its Idaho retail customers. In 1996 the Company set
aside approximately $4.9 million for refund to its Idaho
customers.
Other important points in the Settlement are: (1) the Company
may accelerate a maximum of $30 million of regulatory liabilities
associated with ADITCs over the five-year period; (2) the Company
will not be allowed to increase its Idaho general rates prior to
January 1, 2000, except under special conditions as defined in
the Settlement; and (3) Idaho Power agrees that its quality of
service will not decline as a result of corporate reorganization.
The Company has received approval from the Idaho State Tax
Commission and the Internal Revenue Service on the accounting
treatment for the tax credits. No accelerated ADITC was
recognized in 1995 or 1996.
Oregon Jurisdiction -
In response to the Company's April 1995 application, the OPUC
granted $1.5 million in drought-related rate relief. The OPUC
order allows recovery of the $1.5 million through the continued
application of an existing increase authorized in July 1993 (for
1992 drought relief). The rate increase will remain in effect for
approximately 34 months beginning in July 1995. The Company had
deferred, with interest, increased power supply costs between May
1994 and December 31, 1994.
In May 1995, Idaho Power filed an application with the OPUC
seeking general rate relief of approximately $3.4 million, or a
16.65 percent increase. The Company later negotiated a Settlement
Stipulation with the OPUC staff, the Company's Oregon industrial
customers, and the Citizens Utility Board of Oregon. The
Settlement grants Idaho Power a $1.3 million general rate
increase for its Oregon retail customers. The OPUC Settlement
became effective December 5, 1995.
Other Jurisdictions -
In 1996, the Company did not file any applications for rate
relief before the FERC or in its Nevada retail jurisdiction. In
July 1996, the Company filed an open-access tariff with the FERC,
in compliance with Order 888. The terms and conditions of the
tariff were approved for use beginning in 1997 (see "Transmission
Services").
CONSTRUCTION PROGRAM
The Company's construction program for the 1997-2001 period
(excluding allowances for funds used during construction) is
presently estimated to require cash funds of approximately $421.7
million as follows:
1997 1998-2001 (a)
(Millions of Dollars)
Generating Facilities:
Hydro $3.9 $32.0
Thermal 8.2 38.2
Total generating facilities 12.1 70.2
Transmission lines and
substations 12.0 55.4
Distribution lines and
substations 37.8 160.0
General 22.4 51.8
Total cash construction 84.3 337.4
AFUDC 1.1 4.1
Total construction
including AFUDC (b) $85.4 $341.5
(a) Escalation rates were not applied to construction
expenditures because the level of expenditures has
been capped.
(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.
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 and (2)
purchased power and exchange agreements with other utilities or
other power suppliers. 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 estimate of capital requirements and
sources of capital is $412.7 million outlined as follows:
1997 1998-2001
(Millions of Dollars)
Capital Requirements:
Net cash construction expenditures $84.3 $337.4
Conservation expenditures 1.3 -
Other cash expenditures (0.3) (10.0)
Total $85.3 $327.4
Sources of Capital:
Internal generation $72.4 $359.6
Short-term bank loans - Net 13.3 29.3
First mortgage bonds - (60.7)
Debt repayment (0.1) (0.3)
Common stock - -
Cash investments (increase) (0.3) (0.5)
Total (a) $85.3 $327.4
(a) Does not include subsidiary financings.
These estimates are subject to constant revision in light of
changing economic, regulatory and environmental factors and
patterns of 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, 5 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.
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, 1996, net earnings were 6.52
times. Additional preferred stock may be issued when earnings for
twelve consecutive months within the preceding fifteen months are
at least equal to l.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, 1996,
the actual preferred dividend earnings coverage was 3.11 times.
If the dividends on the shares of Auction Preferred Stock were to
reach the maximum allowed, the preferred dividend earnings
coverage would be 2.84 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 4,642 miles of high
voltage transmission lines; 21 step-up transmission substations
located at power plants; 17 transmission substations; 7
transmission switching stations; and 194 energized distribution
substations (excludes mobile substations and dispatch centers).
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
Capacity kW Capacity kW Expiration
kW
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 1,398,000 1,166,900 2005
Swan Falls 25,547 25,000 2010
American Falls 112,420 92,340 2025
Cascade 14,000 12,420 2031
Twin Falls 54,300 52,737 2041
Milner 59,448 59,448 2038
Other Generating Plants:
Other Hydroelectric 10,400 11,300
Jim Bridger (Coal-Fired 693,333 678,077
Valmy (Coal-Fired Station) 260,650 260,650
Boardman (Coal-Fired Station) 53,000 53,000
At December 31, 1996, the composite average ages of the principal
parts of the Company's system, based on dollar investment, were:
production plant, 17.1 years; transmission system and
substations, 18.2 years; and distribution lines and substations,
13.9 years. The Company considers its properties to be well
maintained and in good operating condition.
The Company owns in fee all of its principle 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. 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. Idaho
Power is actively pursuing the relicensing of its hydroelectric projects,
a process that will continue for the next 10 to 15 years. The
Company submitted its first applications for license renewal to
the FERC in December 1995. These first applications seek renewal
of the Company's licenses for its Bliss, Upper Salmon Falls, and
Lower Salmon Falls Hydroelectric Projects. The Company is also
in the process of submitting a draft application for license
renewal for its Shoshone Falls Hydroelectric Project. Although
various federal requirements and issues must be resolved through
the licensing reviewing 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 licensing renewal.
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 holds investments in thirteen operating hydroelectric
plants with a total generating capacity of 72 MW.
ITEM 3. LEGAL PROCEEDINGS
On December 6, 1991, a complaint entitled Nez Perce Tribe,
Plaintiff, vs. 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.
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
sought through its Amended Complaint to secure actual,
incidental, consequential and punitive damages in amounts to be
proven at trial.
On September 18, 1992, the Company filed a motion for summary
judgment in the hope of securing dismissal of the Tribe's action.
The District Court issued an Order of Reference sending the case
to a Federal Magistrate. On July 30, 1993, the Magistrate issued
a Report and Recommendation that the District Judge granted that
portion of the Company's motion for summary judgment regarding
the loss of fish.
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. 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 dated July 30, 1993, to grant the Company's
motion for summary judgment as to all other claims.
On September 28, 1994, the Federal District Judge issued an Order
rejecting the Second Report and Recommendation of the Magistrate
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.
The Company and the Tribe have reached agreement on a settlement
of this case (Settlement Agreement). The Settlement Agreement
has been approved by the Nez Perce Tribal Executive Committee and
the Company's Board of Directors. Under the terms of the
Settlement Agreement, the Company will pay the Nez Perce Tribe
$11.5 million in the following manner:
- $5 million at which time the Tribe would move for
the dismissal of, with prejudice, their legal action
against the Company.
- $1,625,000 each year for the next four years
beginning in 1998.
All payments under the Settlement Agreement will be made in 1996
dollars, which allows for adjusted future inflation within a
minimum range of 3 percent and a maximum of 7 percent. The first
payment of $5.0 million plus inflation adjustment will be paid
sometime in 1997.
On July 12, 1996 the IPUC issued Order No 26513, and on August 5,
1996, the OPUC issued Order No. 96-207 approving capitalization
of their respective jurisdictional share of the $11.5 million.
The parties requested Bureau of Indian Affairs (BIA) approval of
the Settlement Agreement. However, on November 21, 1996, the
Portland Area Director of the BIA issued a decision stating that
the Settlement Agreement did not have to be approved by the BIA.
On December 19, 1996, the Company filed an administrative appeal
of the BIA's decision and have since requested and been granted a
stay of said appeal pending pursuit of an alternate federal
approval. As a result of the BIA decision, the Tribe and the
Company explored alternatives to BIA approval that would help
assure the ultimate enforceability of the Settlement Agreement.
The parties agreed to request that the Federal District Court for
the District of Idaho approve the Settlement Agreement. The
Tribe and the Company, by motion, stipulated that the Ninth
Circuit Court of Appeals remand the case to the Federal District
Court for the District of Idaho, which motion was granted by the
Ninth Circuit on February 6, 1997. The parties will now seek
Federal District Court approval of the Settlement Agreement.
This matter has been previously reported in Form 10-K dated
March 16, 1992, March 12, 1993, March 10, 1994, March 9, 1995,
March 14, 1996 and other reports filed with the Commission.
On November 30, 1995, a complaint entitled Idaho Power Company
vs. Cogeneration, Inc., Case No. 98467, was filed by the Company
in the District Court of the Fourth Judicial District of the
State of Idaho. The proceeding involves an effort by the Company
to terminate a firm energy sales agreement (FESA) for a small
hydroelectric generating plant.
As required by PURPA and the orders of the IPUC, on January 7,
1992, the Company entered into a 35-year FESA with Cogeneration,
Inc., to purchase the output of a 43-megawatt hydroelectric
generating project known as the Auger Falls Project. The FESA
for the Auger Falls Project was approved by the IPUC on January
27, 1992. The FESA required that on or before January 1, 1994,
Cogeneration, Inc., post cash or cash equivalent security in the
amount of approximately $1.9 million to assure performance of the
FESA. Cogeneration, Inc., failed to provide the security amount.
Consistent with the FESA, the Company filed a petition for
declaratory order with the IPUC requesting that the FESA be
terminated as a result of Cogeneration, Inc.'s breach.
Cogeneration, Inc., cross petitioned claiming that its failure to
perform was excused by the occurrence of an event of force
majeure. On April 17, 1995, the IPUC issued its order finding
that Cogeneration, Inc.'s failure to post the cash security on
January 1, 1994, was a default under the FESA and further finding
that the posting of the liquid security was required by the
public interest. Based upon those findings, the IPUC ordered
Cogeneration, Inc., to post the cash security prior to May 1,
1995. Cogeneration, Inc., failed to comply with the Commission's
order and has never posted the $1.9 million amount required by
the FESA.
After the IPUC's order became final and non-appealable, the
Company filed a complaint for declaratory relief in the District
Court of the Fourth Judicial District. The Complaint sought a
determination by the district court that Cogeneration, Inc.'s
failure to provide the cash security and its violation of the
IPUC's orders requiring that it expeditiously provide the cash
security constituted material breaches of the FESA. The Company
asked the district court to find that as a matter of law Idaho
Power was entitled to either terminate or rescind the FESA.
In response to the Company's complaint, Cogeneration, Inc., filed
counterclaims alleging that the Company, by seeking to terminate
the FESA, had breached the FESA and was attempting to monopolize
the electric generation market and drive Cogeneration, Inc., out
of business. Cogeneration, Inc., alleged damages for breach in
excess of $50 million and requested that any damages be trebled
under the anti-trust laws.
On November 30, 1995, the district judge, by memorandum decision
found that Cogeneration, Inc., had materially breached the FESA
and the Company was entitled to either rescind or terminate the
FESA.
On February 16, 1996, Cogeneration, Inc., dismissed its anti-
trust claims against the Company, and on February 23, 1996, the
Idaho Supreme Court granted Cogeneration, Inc.'s request for an
expedited appeal of the district court's decision establishing an
accelerated briefing schedule and scheduling oral argument for
May 10, 1996.
On August 12, 1996, the Idaho Supreme Court determined that the
District Court's decision that Cogeneration, Inc., had breached
the FESA was premature.
On February 10, 1997, Cogeneration, Inc. filed an amended
Complaint restating its previous claims, requesting a jury trial
rather than the court trial it had previously requested and
raising several new allegations and claims.
While the outcome of litigation is never certain, Idaho Power
believes that Cogeneration, Inc.'s counterclaims are without
merit.
This matter has been previously reported in Form 10-K dated March
14, 1996 and other reports filed with the Commission.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
None
EXECUTIVE OFFICERS OF THE REGISTRANT
The names, ages and positions of all of the executive
officers of the Company are listed below along with their
business experience during the past five years. Officers are
elected annually by the Board of Directors. There are no family
relationships among these officers, nor any arrangement or
understanding between any officer and any other person pursuant
to which the officer was elected.
Name, Age and Position Business Experience During Past Five (5) Years
J. W. Marshall, 58 Appointed August 18, 1989.
Chairman of the Board and
Chief Executive Officer
L. R. Gunnoe, 61 Appointed July 12, 1990.
President and Chief
Operating Officer
J. LaMont Keen, 44 Appointed March 14, 1996. Mr. Keen
Vice President, Chief was Vice President and Chief
Financial Officer Financial Officer prior to March 14,
and Treasurer 1996.
Douglas H. Jackson, 60 Appointed July 12, 1990.
Vice President - Retail
Services
C. N. Olson, 47 Appointed July 11, 1991.
Vice President -Corporate
Services
J. B. Packwood, 53 Appointed July 11, 1996. Mr.
Executive Vice President Packwood was Vice President-Power
Supply prior to July 11, 1996.
Richard Riazzi, 42 Appointed January 9, 1997. Mr.
Vice President - Riazzi was Vice President, Corporate
Marketing and Sales Marketing (1995-1996) and was Vice
President of the Energy Group (1991-
1995) for Equitable Resources, Inc.
Robert W. Stahman, 52 Appointed July 13, 1989.
Vice President, General
Counsel and Secretary
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 year ended December 31, 1994, 1995 and
1996, cash dividends per share of common stock were $1.86. At
the July 1996 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 Company's common stock is listed on the New York and Pacific
Stock Exchanges. The following table indicates the reported high
and low sales price of the Company's common stock for the years
1995 and 1996, as reported by The Wall Street Journal as
composite tape transactions. The Company's year-end common stock
price was $31 1/8 per share and the number of stockholders of
record at December 31, 1996, was 29,333.
1995 Quarters
Common Stock, $2.50 par 1st 2nd 3rd 4th
value:
High $26 $26 3/4 $27 7/8 $30
Low 23 3/8 23 5/8 23 7/8 27 1/4
Dividends paid per share
(cents) 46.5 46.5 46.5 46.5
______________________________
1996 Quarters
Common Stock, $2.50 par 1st 2nd 3rd 4th
value:
High $31 1/4 $31 1/8 $34 1/4 $32
Low 27 1/4 27 5/8 29 3/4 29 7/8
Dividends paid per share
(cents) 46.5 46.5 46.5 46.5
ITEM 6. SELECTED FINANCIAL DATA
SUMMARY OF OPERATIONS 1996 1995 1994
(Thousands of Dollars)
Revenues:
General business $ 484,145 $ 461,594 $ 457,354
Sales to other utilities 70,222 57,418 59,923
Other revenues 24,078 26,609 26,381
Total revenues 578,445 545,621 543,658
Expenses:
Purchased power 69,038 54,586 60,216
Fuel expense 63,334 54,691 94,888
Other operation and
maintenance 168,539 169,959 154,742
Depreciation 69,705 67,415 60,202
Taxes other than
income taxes 20,658 22,979 23,945
Total expenses 391,274 369,630 393,993
Income from operations 187,171 175,991 149,665
Other income and
deductions - Net (12,534) (14,356) (12,160)
Interest charges - Net 56,995 55,014 52,652
Income taxes 52,092 48,412 34,243
Cumulative effect of
accruing unbilled
revenues - - -
Net Income 90,618 86,921 74,930
Dividends on preferred
stocks 7,463 7,991 7,398
Earnings on common stock 83,155 78,930 67,532
Dividends on common
stock 69,924 69,941 69,594
Net change to retained
earnings $ 13,231 $ 8,989 $ (2,062)
CAPITALIZATION (000 ommitted) % % %
First mortgage bonds $ 527,000} $ 470,000} $ 490,000}
Other long-term debt 211,550} 48 202,618} 45 203,206} 46
Preferred stock 106,975 7 132,181 9 132,456 9
Common stock (incl.
prem. & exp.) 452,486} 452,948} 452,962}
Retained earnings 242,088} 45 229,827} 46 220,838} 45
Total capitalization $1,540,099 100 $ 1,487,574 100 $ 1,499,462 100
Short-term borrowings
outstanding $ 54,016 $ 53,020 $ 55,000
FINANCIAL STATISTICS
Income from operations
as a percent of
total revenues 32.4% 32.3% 27.5%
Times interest charges
earned:
Before tax 3.49 3.40 3.01
After tax 2.58 2.54 2.38
Market-to-book ratio 169% 165% 131%
Payout ratio 84% 89% 103%
Return on year-end 11.97% 11.56% 10.02%
common equity
Common stock data:
Earnings per average
share outstanding $ 2.21 $ 2.10 $ 1.80
Dividends declared per $ 1.86 $ 1.86 $ 1.86
share
Book value per share $ 18.47 $ 18.15 $ 17.91
Average shares
outstanding (000
ommitted) 37,612 37,612 37,499
Common shareowners 29,333 30,795 26,209
*Includes cumulative
effect of accounting
change
CUSTOMER DATA
General business data:
Energy sales - kwh
(000,000 omitted) 13,035 11,983 12,194
Number of customers 352,487 340,708 330,308
Residential customer
data:
Number of customers 292,145 282,797 274,187
Average kwh use per
customer 13,828 13,475 14,159
Average rate per kwh (cents) 5.07 5.16 4.83
OTHER STATISTICS
Total assets (000
omitted) $2,295,337 $ 2,241,753 $2,191,816
Gross plant additions
(000 omitted) $ 94,120 $ 87,297 $ 107,667
Number of employees
(full-time) 1,565 1,522 1,609
1993 1992 1991
Revenues:
General Business $ 428,658 $ 431,818 $ 409,454
Sales to other utilities 86,525 42,000 52,563
Other revenues 25,219 24,274 21,176
Total Revenues 540,402 498,092 483,193
Expenses:
Purchased power 45,361 58,496 51,210
Fuel expense 87,855 96,710 75,161
Other operation and
maintenance 164,388 137,547 151,593
Depreciation 58,724 59,823 57,597
Taxes other than
income taxes 22,129 20,562 21,168
Total expenses 378,457 373,138 356,729
Income from operations 161,945 124,954 126,464
Other income and
deductions - Net (12,984) (11,133) (9,453)
Interest charges - Net 53,991 52,935 56,901
Income taxes 36,474 23,162 21,144
Cumulative effect of
accruing unbilled
revenues - - -
Net Income: 84,464 59,990 57,872
Dividends of preferred
stocks 6,009 5,516 4,904
Earnings on common stock 78,455 54,474 52,968
Dividends on common stock 67,959 65,043 63,197
Net change to retained
earnings $ 10,496 (10,569) (10,229)
CAPITALIZATION
(000 omitted) % % %
First mortgage bonds $ 490,000} $ 485,000} $ 435,000} 48
Other long-term debt 203,780} 47 216,948} 49 194,981}
Preferred stock 132,751 9 107,874 7 108,191 8
Common stock (incl.
prem. & exp.) 439,467} 412,998} 356,824}
Retained earnings 222,900} 44 212,404} 44 222,973} 44
Total capitalization $1,488,898 100 $1,435,224 100 $1,317,969 100
Short-term borrowings
outstanding $ 4,000 $ 6,000 $ 48,500
FINANCIAL STATISTICS
Income from operations
as a percent of total
revenues 30.0% 25.1% 26.2%
Times interest charged earned:
Before tax 3.14 2.50 2.34
After tax 2.50 2.08 1.98
Market-to-book ratio 170% 159% 168%
Payout ratio 87% 120% 119%
Return on year-end common
equity 11.84% 8.71% 9.14%
Commmon stock data:
Earnings per average
share outstanding $ 2.14 $ 1.55 $ 1.56
Dividends declared
per share $ 1.86 $ 1.86 $ 1.86
Book value per share $ 17.86 $ 17.28 $ 17.07
Average shares
outstanding (000
ommitted) 36,675 35,116 33,977
Common Shareowners 26,870 27,834 28,069
*includes cumulative effect of accounting change
CUSTOMER DATA
General business data:
Energy sales - kwh
(000,000 ommitted) 11,406 11,606 11,266
Number of customers 317,772 307,567 297,808
Residential customer data:
Number of customers 263,682 255,022 246,689
Average kwh use per
customer 14,587 13,856 14,845
Average rate per kwh
(cents) 4.82 4.80 4.72
OTHER STATISTICS
Total assets (000
omitted) $2,097,417 $1,862,307 $1,773,674
Gross plant additions
(000 omitted) $ 116,972 $ 118,920 $ 135,904
Number of employees
(full-time) 1,654 1,638 1,626
1990 1989 1988
Revenues:
General business $ 401,350 $ 397,974 $ 362,050
Sales to other utilities 44,368 70,749 32,175
Other revenues 19,217 27,438 18,096
Total revenues 464,935 496,161 412,321
Expenses:
Purchased power 43,923 43,845 43,723
Fuel expense 77,606 77,127 74,528
Other operation and
maintenance 134,126 132,114 116,230
Depreciation 55,114 53,092 51,691
Taxes other than income
taxes 20,752 20,213 19,301
Total expenses 331,521 326,391 305,473
Income from operations 133,414 169,770 106,848
Other income and deductions
- Net (11,666) (10,005) (6,552)
Interest charges - Net 52,605 52,997 50,762
Income taxes 23,234 42,041 13,558
Cumulative effect of
accruing unbilled revenu - - -
Net Income 69,241 84,737 49,080
Dividends on preferred
stocks 4,279 4,285 4,293
Earnings on common stock 64,962 80,452 44,787
Dividends on common stock 63,197 62,177 61,159
Net change to retained
earnings 1,765 18,275 (16,372)
CAPITALIZATION
(000 omitted) % % %
First mortgage bonds $ 367,500} $ 377,000} $ 392,000}
Other long-term debt 194,159} 46 165,551} 47 164,426} 47
Preferred stock 58,761 5 58,923 5 59,126 5
Common stock (incl.
prem. & exp.) 358,078} 357,986} 357,866}
Retained earnings 233,241} 49 231,476} 48 213,201} 48
Total capitalization $1,211,739 100 $1,190,936 100 $1,186,619 100
Short-term borrowings
outstanding $ 48,280 $ 31,000 $ 37,000
FINANCIAL STATISTICS
Income from operations
as a percent of total
revenue 28.7% 34.2% 25.9%
Times interest charges earned:
Before tax 2.72 3.30 2.18
After tax 2.29 2.53 1.93
Market-to-book ratio 148% 169% 138%
Payout ratio 97% 77% 137%
Return on year-end common
equity 10.99% 13.65% 7.84%
Common stock data:
Earnings per average
share outstanding $ 1.91 $ 2.37 $ 1.32
Dividends declared
per share $ 1.86 $ 1.83 $ 1.80
Book value per share $ 17.40 $ 17.35 $ 16.81
Average shares
outstanding (000
omitted) 33,977 33,977 33,977
Common shareowners 29,080 30,291 32,225
*Includes cumulative effect of accounting change
CUSTOMER DATA
General business data:
Energy sales - kwh
(000,000 omitted) 11,086 11,069 10,563
Number of customers 291,800 284,363 279,529
Residential customer data:
Number of customers 241,790 236,008 232,650
Average kwh use per
customer 14,281 14,923 14,364
Average rate per kwh
(cents) 4.73 4.69 4.47
OTHER STATISTICS
Total assets (000 omitted) $1,680,110 $1,625,120 $1,608,935
Gross plant additions
(000 omitted) $ 80,117 $ 62,094 $ 64,358
Number of employees
(full-time) 1,574 1,528 1,500
1987 1986
Revenues:
General business $ 343,899 $ 336,480
Sales to other utilities 35,447 54,987
Other revenues 15,251 17,394
Total revenues 394,597 408,861
Expenses:
Purchased power 30,234 31,849
Fuel expense 65,934 31,260
Other operations and
maintenace 114,235 114,407
Depreciation 50,929 49,308
Taxes other than
income taxes 19,072 18,539
Total expenses 280,404 245,363
Income from operations 114,193 163,498
Other income and
deductions - Net (13,115) (17,064)
Interest charges - Net 51,843 51,206
Income taxes 27,246 50,923
Cumulative effect of
accruing unbilled
revenues (11,302) -
Net Income 59,521 78,433
Dividends on preferred
stock 4,298 10,553
Earnings on common stock 55,223 67,880
Dividends on common stock 61,159 59,755
Net change to retained
earnings (5,936) 8,125
CAPITALIZATION
(000 Omitted) % %
First mortgage bonds $ 407,000} $ 432,000}
Other long-term debt 160,003} 47 153,887} 47
Preferred stock 59,238 5 59,403 5
Common stock (incl.
prem. & exp.) 357,797} 357,708}
Retained earnings 229,573} 48 235,509} 48
Total capitalization $1,213,611 100 $1,238,507 100
Short-term borrowings
outstanding $ 4,000 $ 5,000
FINANCIAL STATISTICS
Income from operations
as a percent of total
revenues 28.9% 40.0%
Times interest charges earned:
Before tax 2.76* 3.40
After tax 2.10* 2.46
Market-to-book ratio 127% 150%
Payout ratio 111% 88%
Return on year-end common
equity 9.40% 11.44%
Common stock data:
Earnings per average
share outstanding $ 1.63* $ 2.00
Dividends declared per
share $ 1.80 $ 1.76
Book value per share $ 17.29 $ 17.46
Average shares outstanding
(000 omitted) 33,977 33,961
Common shareowners 33,733 34,456
*Includes cumulative effect of accounting change
CUSTOMER DATA
General business data:
Energy sales - kwh
(000,000 omitted) 10,175 9,938
Number of customers 276,249 274,129
Residential customer data:
Number of customers 230,486 228,921
Average kwh use per
customer 13,785 14,541
Average rate per kwh
(cents) 4.34 4.21
OTHER STATISTICS
Total assets (000 omitted) $1,602,311 $1,621,887
Gross plant additions
(000 omitted) $ 38,929 $ 50,257
Number of employees
(full-time) 1,521 1,524
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 six wholly-owned subsidiaries: Idaho Energy
Resources Company (IERCo); Ida-West Energy Company (Ida-West);
IDACORP, Inc.; Idaho Utility Products Company (IUPCo); Idaho
Power Resources Corporation (IPRC); and Stellar Dynamics, Inc.
(Stellar). This discussion uses the terms Idaho Power and the
Company interchangeably to refer to Idaho Power Company and its
subsidiaries.
FORWARD-LOOKING INFORMATION -
Certain matters discussed in this report are "forward-looking
statements" intended to qualify for the safe harbor from
liability established by the Private Securities Litigation Reform
Act of 1995. Such statements address future plans, objectives,
expectations, and events or conditions concerning various matters
such as capital expenditures, earnings, litigation, rate and
other regulatory matters, liquidity and capital resources, and
accounting matters. Actual results in each case could differ
materially from those currently anticipated in such statements,
by reason of factors such as electric utility restructuring,
including ongoing state and federal activities; future economic
conditions; legislation; regulation; competition; and other
circumstances affecting anticipated rates, revenues and costs.
EARNINGS PER SHARE AND BOOK VALUE -
Earnings per share of common stock in 1996 totaled $2.21, up from
the $2.10 earned in 1995 and the $1.80 earned in 1994. The 1996
earnings equate to a 12.0 percent earned return on year-end
common equity, as compared to the 11.6 percent earned in 1995 and
the 10.0 percent earned in 1994. At December 31, 1996, the book
value per share of common stock was $18.47.
A number of factors have affected earnings per share over the
last three years: improved hydro conditions, a strong service
territory economy, continued customer growth, and resolution of
rate cases in 1995. In 1996, under terms and conditions of the
regulatory settlement with the Idaho Public Utilities Commission
(IPUC), the Company set aside approximately $4.9 million for
refund to its Idaho customers. This provision for refund reduced
reported earnings per share by approximately eight cents (See
"Regulatory Settlement").
RESULTS OF OPERATIONS -
Customer Growth and Energy Demand -
New customer growth continued at a brisk pace with the Company
adding 11,779 new general business customers during 1996. This
increase marks 1996 as the Company's second best year in terms of
customer growth. This, added to 1994's record-setting 12,536 new
customers, and 1995's 10,400, combined for a three-year total of
34,715 (10.9 percent) new general business customers. During
1996, Idaho Power added 9,348 residential customers, 2,090
commercial customers, and 339 irrigation customers.
Higher summer temperatures led to increases in energy demand
during 1996. In contrast, 1995 had milder winter and summer
weather conditions which reduced loads for heating and cooling,
while the wet, cool spring reduced irrigation loads.
Economy -
Idaho's economy continued to outperform the nation in terms of
non-agricultural employment growth. Idaho's overall non-
agricultural employment growth advanced at a 4.1 percent annual
rate through the first eight months of 1996. This compares to
1995's 3.2 percent growth rate. Employment in the manufacturing,
construction, service and trade industries posted gains of 1.8
percent, 12.5 percent, 7.6 percent and 3.7 percent, respectively,
for the first eight months of 1996. The state's economic
performance has fluctuated during the periods presented, but
Idaho's economy continues to create jobs and attract new
companies to the state.
Revenues -
For the three-year period 1994-1996, the Company received an
average 85 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
customer category were as follows:
- - 35 percent from residential customers;
- - 30 percent from a combination of irrigation customers, street
lighting customers, and commercial customers with less than
1,000 kW demand;
- - 19 percent from industrial customers with demand of 1,000 kW or greater;
- - 11 percent from off-system sales to other utilities and interchange
arrangements; and
- - 5 percent from miscellaneous revenue
The Company's energy sales to general business customers,
increased 6.9 percent in 1994 and 8.8 percent in 1996, but
decreased 1.7 percent in 1995. In 1995, residential usage was
down l.5 percent, due to the mild weather, despite an increase in
customers during the year. Also contributing to the 1995 decline
was wet spring weather that reduced irrigation kilowatt sales in
that year by 25.2 percent.
The year 1996 saw energy sales increase in all customer classes.
Residential and commercial sales increased 6.0 percent and 9.3
percent, respectively, due to increased customers, a strong
economy, and weather factors providing more heating-and cooling-
degree days during the year. Irrigation sales increased 21.0
percent with a return to more normal weather patterns during the
summer months. Industrial sales also grew by 7.0 percent in
1996.
General business revenues represent approximately 84 percent of
the Company's total operating revenues. General business
revenues were $457.4 million in 1994, $461.6 million in 1995, and
$484.1 million in 1996. The 1995 increase reflects rate
increases during the year and increased sales to some industrial
customers. The 1996 increase comes primarily from residential,
$8.0 million (4.2 percent), commercial $5.0 million (4.9
percent), and irrigation, $6.7 million (12.1 percent). The
average residential customer used 14,159 kwh in 1994, 13,475 kwh
in 1995, and 13,828 kwh in 1996. These averages reflect changes
due to varied weather patterns.
Off-System Sales -
Off-system sales are composed of firm sales (long-term contracts)
and opportunity sales made on a when-available basis. The volume
and price of these latter sales depend on the Company's firm energy
demand, hydroelectric generating conditions in its service
territory, and market conditions throughout the West. Revenues
from off-system sales declined $26.6 million in 1994. Off-system
revenues declined an additional $2.5 million in 1995, but rose by
$12.8 million in 1996.
In 1995 and 1996, improved hydroelectric generating conditions
created an increase in off-system sales, while drought conditions
reduced sales in 1994. In 1995, improved hydroelectric
conditions created an increase in off-system sales. However,
reduced demand on the off-system market cut the prices of such
sales.
Expenses -
Total operating expenses rose $15.5 million in 1994, decreased by
$24.4 million in 1995, and increased $21.6 million in 1996. The
increase in expense for 1994 reflects drought conditions, which
increased the Company's reliance on thermal generation and
purchased power. The decrease in 1995 resulted from improved
hydroelectric operating conditions, which lowered purchased power
and fuel expense.
In 1996, purchased power expense was up $14.5 million. This
increase reflects economy purchases made to take advantage of low
wholesale market prices during the year and increased purchases
from cogeneration and small power production (CSPP) projects
which also experienced strong hydroelectric generating
conditions. The low market prices were a result of the abundance
of hydro generation in the West, which allowed the Company to
remarket this energy to others. In 1995, with the return to more
normal hydro conditions, purchased power expense was lower when
compared to 1994, a year in which drought conditions were
experienced.
Fuel expense also increased in 1996 by $8.6 million. The
largest increase came in the fourth quarter, mainly due to the
operation of the Valmy coal-fired plant. A reduction in spot
market coal prices allowed the Company to generate additional
energy and to be competitive in the off-system market. In 1995,
the Company experienced good seasonal hydroelectric conditions,
thereby reducing its reliance on thermal generation.
The Power Cost Adjustment (PCA) component of expenses was up
$19.3 million when comparing 1995 to 1994. However, for 1996,
the PCA was down $14.1 million, compared to 1995. The PCA
mechanism reduces expenses when power supply costs are above
forecast, and increases expenses when power supply costs are
below forecast (see "PCA discussion").
All other operation and maintenance expenses fluctuated during
the three-year period, with a cumulative increase of $9.5
million. These variations are due, in part, to increases in
payroll and benefits, changes in operation and maintenance due to
water conditions, as well as reconstruction of Company facilities
damaged or destroyed by natural causes.
Depreciation expense was up for the three-year period by $10.9
million (18.7 percent), due to a greater plant investment base,
while taxes other than income taxes decreased $1.5 million (6.6
percent).
Interest Charges -
Interest charges on long-term debt fluctuated during the three-
year period, with a cumulative decrease of $1.5 million. This
decrease reflects the maturity, early redemption, and issuance of
several series of first mortgage bonds at reduced or lower
interest rates. Additionally, the Company took advantage of
lower interest rates to refinance several existing higher-cost
Pollution Control Revenue Bond issues with new lower-cost
Pollution Control Revenue Bond issues. Refinancing in 1996
reduced interest requirements by $2.2 million over 1995. These
amounts will fluctuate as two series of these bonds are variable
rate, while the third is fixed. Also, this refinancing
lengthened the maturity of these bonds from those originally
issued.
During 1996, the Company redeemed the 8.375% Series of Serial
Preferred Stock and retired at maturity the 5.25% Series of First
Mortgage Bonds. This was accomplished by issuing two series of
medium term notes. This financing reduced the Company's overall
cost of capital (see Note 5 of "Notes to Consolidated Financial
Statements").
Interest on short-term debt rose during the three-year period due
to fluctuating interest rates, as well as to a higher level of
short-term borrowings. At December 31, 1996, the Company's short-
term borrowings totaled $54.0 million (see Note 7 of "Notes to
Consolidated Financial Statements").
Precipitation and Streamflows -
Idaho Power analyzes precipitation and streamflow conditions
based on the effect on Brownlee Reservoir, the primary water
source for the three Hells Canyon hydroelectric power plants. In
normal years, these three projects combine to produce about half
of the Company's generated electricity. In 1994, drought
conditions reduced the amount of water flowing into the Company's
reservoir system. However, in 1995 and 1996, Idaho Power's
service territory experienced above average water years. Between
April and July 1996, the Company recorded 8.3 million acre feet
(MAF) of water flowing into Brownlee Reservoir. This compares
with 1994's 2.8 MAF, 1995's 6.6 MAF, and the 66-year median of
4.8 MAF. The early indications for 1997 are promising. As of
February 1, 1997, reservoir storage above Brownlee Reservoir was
79 percent of capacity compared to 81 percent of 1995. The
average snow-water equivalent for the Snake River above Brownlee
Reservoir was 171 percent of the 30-year average at this time of
year.
Energy Requirements -
With precipitation and streamflow conditions above normal in
1996, hydroelectric generation accounted for 58 percent of the
Company's total energy requirements. This figure is an
improvement over 1994's 40 percent, and is unchanged from 1995.
During 1996, thermal generation accounted for 26 percent of total
energy requirements, while purchased power and other interchanges
supplied 16 percent. Under historically normal conditions, the
Company's hydro system supplies approximately 57 percent of its
total energy requirements, with thermal generation accounting for
34 percent and purchased power and other interchanges
contributing the remaining 9 percent.
The Company expects to meet 1997's projected energy loads by
using its hydro and coal-fired facilities and its strategic
geographic location, which presents excellent opportunities to
purchase, sell, exchange, and transmit Northwest energy.
Regulatory Issues -
Power Cost Adjustment -
Since 1993, the IPUC has permitted Idaho Power to use a PCA
mechanism in its Idaho jurisdiction. The PCA enables the Company
to collect or to refund a portion of the difference between net
power supply costs actually incurred and those allowed in the
Company's base rates. The current balance is adjusted monthly as
actual conditions are compared to the PCA forecasted net power
supply costs. For the period May 1996 through May 1997, the IPUC
approved tariffs, reducing Idaho jurisdictional PCA rates by
$25.7 million (5.9 percent), including the true-up for the PCA
period May 1995 through May 1996. The reduction reflects
anticipated lower power supply costs in the coming year due to
above-average hydroelectric generating conditions. The 1996 PCA
forecast reflects power supply costs below those established for
PCA expenses in the Company's last general rate proceeding. At
December 31, 1996, the Company had recorded as a deferred asset
and reduction in operating expenses $11.4 million of power supply
costs above those projected in the 1996 forecast.
General Revenue Requirement Case -
On January 31, 1995, the Company received IPUC Order No. 25880,
which authorized $17.2 million in general rate relief,
representing a 4.2 percent overall increase in Idaho retail
rates. The relief was based on an 11.0 percent allowed return on
equity and an overall rate of return of 9.2 percent. The
increase in Idaho retail rates went into effect on February 1,
1995.
Twin Falls Rate Case -
In August 1995, the IPUC issued an order authorizing the Company
to increase its Idaho retail rates on an annual basis by $3.8
million (0.9 percent). This increase was uniform to all customer
classes, as well as to special contract customers.
Regulatory Settlement -
On August 3, 1995, Idaho Power filed a proposal with the IPUC to
support the Company's organizational redesign. In response to
the Company's proposal, the IPUC approved a Settlement that
authorizes the Company to defer and amortize costs related to
reorganization in return for a general rate freeze through the
end of 1999. In addition, the Settlement allows for the
accelerated amortization of regulatory liabilities associated
with accumulated deferred investment tax credits (ADITCs) to
provide a minimum 11.50 percent return on actual year-end common
equity for the Idaho jurisdiction. The new rate freeze and the
accelerated amortization of regulatory liabilities associated
with ADITCs gives the Company time to pursue and to implement its
efficiency and growth initiatives with the assurance of at least
a reasonable level of financial performance apart from the need
to change customer prices.
The terms and conditions of the Settlement will remain in effect
through 1999. Under the Settlement, when the Company's actual
earnings in a given year exceed an 11.75 percent return on year-
end common equity, the Company will refund 50 percent of the
excess.
Other important points in the Settlement are: (1) the Company
may accelerate a maximum of $30 million of regulatory liabilities
associated with ADITCs over the five-year period; (2) the Company
will not be allowed to increase its Idaho general rates prior to
January 1, 2000, except under special conditions as defined in
the Settlement Agreement; and (3) Idaho Power agrees that its
quality of service will not decline as a result of corporate
reorganization.
The Company has received approval from the Idaho State Tax
Commission and the Internal Revenue Service on the accounting
treatment for the tax credits. No accelerated ADITC was
recognized in 1995 or 1996.
Cogeneration and Small Power Production Contracts -
In light of the potential deregulation of the electric utility
industry and a more competitive power supply marketplace, Idaho
Power believes that resource acquisition policies must avoid
burdening the Company and its customers with unnecessary future
power supply costs. 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, the IPUC
issued an order on January 31, 1995, approving lower published
CSPP rates for new projects. In addition, the IPUC determined
that negotiated rates for future CSPP projects larger than 1
megawatt (MW) should be tied more closely to values determined in
the Company's integrated resource planning (IRP) process. In a
subsequent order issued on September 4, 1996, the IPUC further
recognized the coming changes by limiting the contract term which
a new CSPP project larger than 1 MW could request to a maximum of
five years.
Oregon General Rate Relief -
In May 1995, Idaho Power filed an application with the Oregon
Public Utilities Commission (OPUC), seeking general rate relief
of approximately $3.4 million, or a 16.65 percent increase. The
Company later negotiated a Settlement Stipulation with the OPUC
staff, the Company's Oregon industrial customers, and the
Citizens Utility Board of Oregon. The Settlement grants Idaho
Power a $1.3 million general rate increase for its Oregon retail
customers. The OPUC approved the Settlement Stipulation on
November 28, 1995.
Oregon Drought-Related Rate Relief -
In response to the Company's April 1995 application, the OPUC
granted $1.5 million in drought-related rate relief. The OPUC
order allows recovery of the $1.5 million through the continued
application of an existing increase authorized in July 1993 (for
1992 drought relief). The rate increase will remain in effect for
approximately 34 months beginning in July 1995. The Company had
deferred, with interest, increased power supply costs between May
1994 and December 31, 1994.
Subsidiaries -
Ida-West Energy Company -
This wholly owned subsidiary of the Company holds investments in
13 operating hydroelectric plants with a total generating
capacity of 72 megawatts (MW).
In January 1996, Ida-West made an investment by acquiring all of
the outstanding bonds that were issued to finance three
hydroelectric plants known collectively as the Friant Power
Project. This project is located at the U.S. Bureau of
Reclamation's Friant Dam on the headwaters of the San Joaquin
River in Madera and Fresno Counties, California. It has an
aggregate generating capacity of 27.4 MW. The project is owned
and operated by Friant Power Authority, a quasi-governmental
entity consisting of six irrigation districts, a water district,
and a municipal utility district.
In November 1996, Ida-West purchased an interest in five
hydroelectric projects located in Shasta County, California, with
a total generating capacity of 11.2 MW. Ida-West acquired the
projects through a limited liability company in which it holds a
50 percent interest.
In addition, Ida-West has an interest in the Hermiston Power
Project, a 460 MW, gas-fired cogeneration project to be located
near Hermiston, Oregon. Ida-West has been responsible for
managing all permitting and development activities relating to
the project since its inception in 1993, and has obtained all
permits necessary for construction and operation of the project.
The partnership is exploring various alternatives for marketing
the project's output. Project financing for construction costs
would be non-recourse to Idaho Power.
To date, the Company has invested $20 million in Ida-West. Ida-
West continues an active search for new projects.
IDACORP, Inc. -
Through this wholly-owned subsidiary, the Company is
participating in five affordable housing programs. These
investments provide a return to IDACORP by reducing the Company's
federal income taxes and by assuring a return on investment
through tax credits and tax depreciation benefits. To date, the
Company has invested $4.0 million in IDACORP.
Idaho Power Resources Corporation -
IPRC, is a wholly-owned subsidiary, incorporated in March 1996 to
provide guidance, resources, and long-term strategic planning to
projects or business proposals that are not subject to regulation
by the FERC and the state regulatory commissions. IPRC's goals
are to establish, acquire, and expand business operations in
sustainable infrastructure technology and services including
energy, water, waste disposal, telecommunications, and
information systems. The Company has invested approximately $4.0
million in development and acquisition activities in IPRC.
IPRC has a Memorandum of Understanding signed by Idaho Power and
representatives from the government of Indonesia on March 6, 1996
that cleared the way to conduct a detailed feasibility study on
using solar photovoltaic (PV) technology, micro hydroelectric
systems, and other renewable energy systems to provide
electricity to various locations throughout Indonesia's complex
of islands. IPRC is currently reviewing results of the completed
business plan. If the project is deemed workable and receives
the required approvals, IPRC would likely begin to develop
services in 1997.
In October 1996, IPRC acquired a majority interest in Applied
Power Corporation (APC), a Lacey, Washington-based, company that
designs, supplies, and distributes photovoltaic (PV) systems.
Stellar Dynamics -
Stellar Dynamics core business is to provide products and
services to control, protect, and monitor utility and industry
processes and equipment. Stellar offers design and integration
of high-quality modular process control systems backed with field
support, training, documentation, and customer service. The
Company has invested $1.5 million in Stellar. As Stellar's
capital requirements increase, the Company has approved
additional equity investments up to a total of $3.0 million.
LIQUIDITY AND CAPITAL RESOURCES -
Cash Flow -
The Company's net cash generation from operations totaled $468.0
million for the three-year period 1994-1996. After deducting
common and preferred dividends of $232.8 million, net cash
generation from operations provided approximately $235.2 million
for the Company's construction program and other capital
requirements.
Internal cash generation after dividends provided 41 percent of
the Company's total capital requirements in 1994, 101 percent in
1995, and 99 percent in 1996. The Company forecasts that
internal cash generation after dividends will provide
approximately 85 percent of total capital requirements in 1997
and over 94 percent during the four-year period 1998-2001. Idaho
Power expects to continue financing its construction program and
other capital requirements with both internally generated funds
and, to the extent necessary, externally financed capital.
During the forecast period, the Company also has first mortgage
bond maturities of $30.0 million in 1998, $80.0 million in 2000,
and $30.0 million in 2001. At January 1, 1997, the Company had
regulatory authority to incur up to $200.0 million of short-term
indebtedness. On December 19, 1996, the Company replaced its
committed lines of credit arrangements with a $120.0 million
multi-year revolving credit facility under which the Company will
pay a facility fee on the commitment, quarterly in arrears, based
on the Company's first mortgage bond rating (see Note 7 of "Notes
to Consolidated Financial Statements").
Construction Program -
The Company's consolidated cash construction expenditures totaled
$110.5 million in 1994, $84.0 million in 1995, and $93.6 in 1996.
Approximately 25 percent of these expenditures were for
generation facilities, 15 percent for transmission facilities, 43
percent for distribution facilities, and 17 percent for general
plant and equipment.
Twin Falls Project -
In July 1995, the Company completed testing of the new expansion
turbine at its Twin Falls Hydroelectric Project and declared the
unit available for commercial operation. This project added 43.5
MW of capacity to the Company's generation system and a second
powerhouse to the Twin Falls site.
Southwest Intertie Project -
The Company's Southwest Intertie Project (SWIP) is on hold. At
the current time, an order from the Public Service Commission of
Nevada is still pending, that would allow Nevada Power to
participate in the project.
The Company's SWIP proposal calls for a 500-mile, 500-kilovolt
(kV) transmission line that would serve as a major north-south
transmission artery, connecting the Company's system with those
of utilities in California and the Southwest. The U.S. Bureau of
Land Management has 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.
The Company and interested parties have completed ownership
allocation and negotiations for the execution of the Memorandum
of Agreement (MOA). When the MOA is executed, the Company will
require each party to pay its share of the approximately $8.5
million expended for environmental permitting, right-of-way
acquisition, and related development activities. The SWIP owners
will then form an Executive Committee, with voting rights
proportional to each share of the project. The Executive
Committee will oversee development activities for the SWIP and
related projects.
Financing Program -
Capital Structure -
The Company's capital structure (as illustrated in Selected
Financial Data) fluctuated during the three-year period, with
common equity ending at 45 percent, preferred stock 7 percent,
and long-term debt 48 percent at December 31, 1996. The
Company's objective is to maintain capitalization ratios of
approximately 45 percent common equity, 5-10 percent preferred
stock, and the balance in long-term debt. The Company's pre-tax
interest coverage ratios were 3.01 times in 1994, and 3.40 times
in 1995, and 3.49 times in 1996. 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 million. On July 29, 1996, the Company issued
$30,000,000 principal amount of Secured Medium Term Notes, Series
B, 6.93% Series Due 2001. The net proceeds were used for
repayment of commercial paper issued in connection with the
Company's ongoing construction program. On October 2, 1996,
$27,000,000 principal amount of Secured Medium Term Notes, Series
B, 6.85% Due 2002 were issued with net proceeds from this sale
used to redeem the Company's 250,000 shares 8.375% Series, Serial
Preferred Stock, Without Par Value.
On August 29, 1996, tax exempt Pollution Control Revenue
Refunding Bonds were issued in principal amount of $68,100,000
Series 1996A, $24,200,000 Series 1996B and $24,000,000 Series
1996C. The proceeds were used to retire the $24,200,000
Pollution Control Revenue Bonds Due 2003, $24,000,000 -Pollution
Control Revenue Bonds Due 2007 and the $68,100,000 Pollution
Control Revenue Bonds Due 2013-2014.
Common Stock -
During the period of January through May 1994, the Company issued
original issue shares of common stock for its Dividend
Reinvestment and Stock Purchase Plan, and for its Employee
Savings Plan. During 1994, common shares totaling 527,296, were
issued under these plans. The Company used the net proceeds from
these issues for its ongoing construction program. During 1995
and 1996, no original issue shares were issued pursuant to these
plans.
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 Fall Chinook Salmon from Threatened to
Endangered. The Company does not anticipate that the new
designation will have any major 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.
In March of 1995, the National Marine Fisheries Service (NMFS)
released a Proposed Recovery Plan for the listed Snake River
Salmon. The NMFS accepted public comment on the Plan through
December of 1995. As drafted, the Plan would not require any
change to the Company's current operations for salmon. Pending
completion of a final recovery plan by the NMFS, the U.S. Army
Corps of Engineers and other governmental agencies operating
federally owned dams and reservoirs on the Snake and Columbia
Rivers will continue to consult with the NMFS regarding ongoing
system operations. These interim operations are not expected to
change the Company's current operations for salmon.
The Northwest Power Planning Council (NWPPC) issued its recovery
plan for Snake River anadromous fish, the Strategy for Salmon, on
December 15, 1994. The NWPPC plan calls on the U. S. Bureau of
Reclamation (BOR) to acquire 500,000 acre-feet of water within
the Snake River Basin by 1996, and an additional 500,000 acre-
feet by 1998. The water is to be acquired from willing sellers.
Thus far, the BOR has indicated it does not intend to comply with
the request to acquire 1,000,000 acre-feet of additional water.
However, if the BOR does comply and successfully implements the
request, its movement of additional water could have a material
impact on the Company's power supply costs. The strategy for
Salmon also calls for the Company to contribute 427,000 acre-feet
of water from Brownlee Reservoir as required in the NMFS Proposed
Recovery Plan. The Company has negotiated a five-year contract
with BPA to replace lost energy and capacity resulting from
recovery plans that impact the Company's power supply cost.
Nez Perce Lawsuit -
In 1996, Idaho Power's Board of Directors and the Nez Perce Tribe
approved an Agreement between the Company and the Tribe which
would resolve a civil lawsuit filed against Idaho Power in
December of 1991, in the United States District Court for the
District of Idaho, regarding alleged damages to the Tribe's
treaty-reserved fishing rights.
The suit arose from the construction, maintenance, and operation
of Idaho Power's three-dam Hells Canyon Complex and the project's
alleged impact both on fish and the Tribe's treaty-reserved
fishing rights. The Agreement required the approval of the
United States government (through the Bureau of Indian Affairs
(BIA)) acting in its capacity as trustee for the Tribe. Under the
terms of the Agreement, Idaho Power will pay the Nez Perce Tribe
$11.5 million in the following manner:
- $5 million at which time the Nez Perce would move for the
dismissal of, with prejudice, their legal action against the
Company.
- $1,625,000 each year for the next four years.
All payments under the Agreement will be made in 1996 dollars,
which allows for adjusted future inflation within a minimum range
of 3 percent and a maximum of 7 percent. The first payment of $5
million plus inflation adjustment will be paid before the end of
1997.
On July 12, 1996 the IPUC issued Order No. 26513, and on August
5, 1996, the OPUC issued Order No. 96-207 approving
capitalization of their respective jurisdictional share of the
$11.5 million. The Company has recorded the $11.5 million as a
regulatory asset due from ratepayers and a liability to the
Tribe. The Tribe requested BIA approval. However, on November
21, 1996, the Portland Area Director of the BIA issued a decision
stating that the Agreement did not have to be approved by the BIA
and declined to review the Agreement. On December 19, 1996, the
Company filed an administrative appeal of the BIA's decision. As
a result of the BIA decision, the Tribe and the Company are
exploring alternatives to BIA approval that would help assure the
ultimate enforceability of the Agreement.
In connection with settling the litigation, Idaho Power and the
Tribe also reached a provisional settlement regarding the license
renewal of the Hells Canyon Complex. In return for the Tribe's
support of the Company's application to relicense the project,
the Company will place $5 million, the majority of which the
Tribe has agreed to dedicate to implementable fisheries
restoration efforts, in an escrow account on August 3, 2003, the
date by which the Company must file its relicense application.
The Tribe will be entitled to earnings from investments on this
account until the Company accepts or rejects a new federal
license for the project. If the Company accepts the new federal
license, the Tribe will take ownership of the money in the
account. If the Company rejects the license, the money will be
returned to the Company. This settlement is provisional because
the Tribe retains the right to opt out of this relicensing
settlement at any time prior to the Company's acceptance of a new
federal license.
Threatened and Endangered Snails -
In mid-December 1992, the U.S. Fish and Wildlife Service (USFWS)
listed five species of Snake River snails as 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. Although 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 effects, if any, that water fluctuations
caused by these facilities may have on the snails. 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.
In 1995, as a part of its federal hydro relicensing process,
Idaho Power obtained a permit from the USFWS to study five
species of endangered Snake River snails. The Company's
biologists will conduct this study over the next three years,
focusing on potential snail habitat in the Middle Snake River.
The Company's objective is to gain scientific insight into how or
if these snails are affected by a variety of factors, including
hydropower production, water quality, and irrigation run-off.
The study will review how these and other factors influence the
status of the various colonies and their respective habitats.
Mountaineer Cleanup -
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 Idaho Power, owns one-third of BCC. In November 1993, BCC
agreed to be included on the list of parties potentially
responsible for this site. The estimated cleanup costs totaled
approximately $4.0 million. BCC's portion of the cleanup costs,
based on the amount of oil delivered to the site, was estimated
to be approximately 4.63 percent ($185,200). This estimate is
likely to be high since the cleanup is substantially complete,
with the exception of ground water monitoring. To date, BCC has
expended $84,700 in cleanup costs and continues to carry $42,750
as an unfunded liability as of December 31, 1996. IERCo is
responsible for one-third of BCC's share of the cleanup costs.
Clean Air -
Idaho Power has analyzed the Clean Air Act's effects on the
Company and its rate payers. The Company's coal-fired plants in
Oregon and Nevada already meet the federal emission rate
standards for sulfur dioxide (SO2) and Idaho Power's coal-fired
plant in Wyoming meets that state's even more stringent SO2
regulations. Therefore, the Company foresees no adverse effects
on its operations with regard to SO2 emissions.
During 1994, 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
and 3, of the Company's Jim Bridger thermal facility, together
with facilities owned by PacifiCorp and Black Hills Corporation,
as substitution units for Illinois Power's Baldwin #2. 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 -
While scientific research has not established any conclusive link
between electric and magnetic fields (EMFs) and human health, the
possibility of a link has caused public concern in the United
States and abroad. Electric and magnetic fields exist 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
EMFs. Depending on what researchers ultimately discover and any
necessary regulations, it is possible that this issue could
affect a number of industries, including electric utilities.
However, it is difficult at this time to estimate what effects,
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, Idaho Power 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.
The Company believes the first meaningful step to a competitive
retail energy market is the functional unbundling of costs into
the various delivery and energy components. The Company believes
that the unbundling of costs will create a real means for our
customers to compare energy prices and that cost unbundling will
facilitate the establishment of more accurate price signals for
service components. The Company is prepared to bring forward cost
unbundling filings in its regulatory jurisdictions in the first
half of 1997. The Company expects that state regulators may
require formal hearings on the cost unbundling issue.
The Company further believes that the future of the electric
utility industry will be characterized by the right of customers
to choose their own electric service provider. To remain
successful, Idaho Power must continue to provide value to its
shareholders in the face of this new competitive environment.
The Company's vision involves three strategies for creating this
value: selective and efficient use of capital; an enhanced
customer orientation; and innovative, efficient operations.
Because future prices for power will be determined more by market
forces and less by regulatory administration, the Company must be
very selective and efficient in the use and allocation of
capital. Idaho Power will invest in improving and expanding its
core business, in developing new opportunities beyond its current
service territory, and in continuing to develop non-regulated
opportunities consistent with the Company's core competencies.
Based on this vision and the Company's efforts to increase
shareholder and customer value, Idaho Power is transforming its
operations to improve both efficiency and customer service.
Teams of employees are redesigning work processes. In some
cases, these improved processes are successfully in place.
During 1995, Idaho Power announced plans for voluntary and
involuntary separation packages in the event of workforce
reductions resulting from its reorganization efforts. The
packages included compensation based on years of service and
address medical benefits and transition services.
FERC Decisions -
On April 24, 1996, the FERC issued its Order Nos. 888 and 889
dealing with Open-Access Non-Discriminatory Transmission Services
by Public and Transmitting Utilities, and standards of conduct
regarding these issues. These orders require public utilities
owning transmission lines to file open-access tariffs available
to buyers and sellers of wholesale electricity; to require
utilities to use the tariffs for their own wholesale sales; and
to allow utilities to recover stranded costs, subject to certain
conditions. Public utilities owning transmission lines were
required to file compliance tariffs by July 9, 1996.
Idaho Power has long had an informal open-access transmission
policy, and is experienced in providing reliable, high-quality,
economical transmission service. The Company provides various
firm and non-firm wheeling services for several surrounding
utilities. In November of 1995, the Company filed open-access
tariffs with the FERC for Point-to-Point and Network transmission
service. The substance of these tariffs was to offer the same
quality and character of transmission services that the Company
uses in its own operations to anyone seeking them. The Company
requested and received permission to implement these tariffs
beginning February 1, 1996. On July 8, 1996, the Company filed a
new open-access transmission tariff to replace the 1995 tariffs.
This provides full compliance with Final Order No. 888. This new
filing did not include a rate change. On November 13, 1996, FERC
issued an unconditional acceptance of the terms and conditions of
this tariff. The rate was not subject to review.
Independent Grid Operator -
A group of seven investor-owned Northwest electric companies,
including Idaho Power, BPA, and three public electric entities
have signed a memorandum of understanding that will create an
independent transmission grid operator called "IndeGO". It will
ensure non-discriminatory, open-access to electricity
transmission facilities in compliance with recent FERC rulings.
This memorandum of understanding is an agreement to investigate
the feasibility of developing a regional transmission grid which
would be operated by an entity independent of power market
interests. It is believed that the formation of such an entity
will facilitate the operation of an evolving competitive electric
power market. Operating as one regional system, the utilities
will be able to increase the efficiency of transmission
operations and provide improved access for all system users.
IndeGo is envisioned as an independent transmission company not
controlled by any individual power market participant(s). It is
anticipated that IndeGO will operate as a single control area,
with pricing based on a single zonal tariff applied equally to
all users including the participating companies.
IndeGO will not own transmission facilities at the onset, but
will be responsible for the operation of main transmission grid
facilities 230 kilovolts (kV) or more that are owned by the
participating utilities. The area encompassed by the IndeGo has
over 20,000 miles of transmission lines accounting for about 97%
of the northwest grid.
The group plans to file the IndeGo proposal with FERC by July
1997, and anticipates operation would commence as early as 1999.
If the FERC's approval arrives by April of 1998, an IndeGo Board
and Site Procurement could be expected by July of 1998.
Marketing Business Unit -
To accommodate its customers and allow itself to compete in the
rapidly evolving competitive market, the Company has formed a
Marketing Business Unit, effective January 1997. This new
business unit will be responsible for all purchases and sales of
electric energy, market research and the planning and
implementation of marketing strategies.
To assist the Marketing Business Unit in bringing value to the
Company, the Board of Directors gave approval for executive
management to form a Risk Management Committee, comprised of
executives and senior managers, to oversee a new risk management
program. The program is intended to minimize fluctuations in
earnings and cash flow while controlling the volatility of the
Company's energy prices to its customers. The objectives of the
program include setting and achieving commodity price targets,
locking in commodity prices related to specific contracts for the
sale of electricity, and managing commodity price risk for
customers.
IPUC Workshops Regarding Industry Changes -
In August 1996, the IPUC completed its investigation into changes
in the electric utility industry and issued Order No. 26555. The
IPUC commended the working group for its effort and for the
development of a position paper (an attachment to the order) on
the changes affecting the electric utility industry. The
position paper was the product of a series of workshops
concerning the electric utility industry restructuring and its
impact on the state of Idaho. Participants included
commissioners and commission staff, electric utility customers
and customer group representatives, publicly-and investor-owned
utilities, and public interest groups. The position paper set
forth regulatory and legal issues that might arise during a
transition to a more competitive environment. The IPUC addressed
the issues individually in Order No. 26555. In its order, the
IPUC described a cautious forward approach, noting that customers
of Idaho regulated utilities pay some of the lowest rates in the
nation and that low cost hydroelectricity is an existing benefit
of Idaho retail customers. The IPUC stated its expectation that
many of the specific restructuring issues would be resolved in a
case-by-case manner.
Relicensing of Hydroelectric Projects -
Idaho Power is actively pursuing the relicensing of its
hydroelectric projects, a process that will continue for the next
10 to 15 years. The Company submitted its first applications for
license renewal to the FERC in December 1995. These first
applications 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 license renewing 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 license renewal.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
INDEX TO FINANCIAL STATEMENT
AND FINANCIAL STATEMENT SCHEDULE
PAGE
Management's Responsibility for Financial Statements 41
Consolidated Financial Statements:
Consolidated Balance Sheets as of December 31, 1996,
1995 and 1994 42-43
Consolidated Statements of Income for the Years
Ended December 31, 1996, 1995 and 1994 44
Consolidated Statements of Retained Earnings for the Years
Ended December 31, 1996, 1995 and 1994 45
Consolidated Statements of Capitalization as of
December 31, 1996, 1995 and 1994 46
Consolidated Statements of Cash Flows for the Years
Ended December 31, 1996, 1995 and 1994 47
Notes to Consolidated Financial Statements 48-60
Independent Auditors' Report 61
Supplemental Financial Information (Unaudited) 62
Supplemental Schedule for the Years Ended December 31,
1996, 1995 and 1994:
Schedule II- Consolidated Valuation and
Qualifying Accounts 69
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.
/s/Joseph W. Marshall /s/J. LaMont Keen
Joseph W. Marshall J. LaMont Keen
Chairman and Chief Executive Officer Vice President,Chief Financial Officer
and Treasurer
IDAHO POWER COMPANY
CONSOLIDATED BALANCE SHEETS
ASSETS
December 31,
1996 1995 1994
(Thousands of Dollars)
ELECTRIC PLANT:
In service (at original cost) $2,537,565 $2,481,830 $2,383,898
Accumulated provision for depreciation (886,885) (830,615) (775,033)
In service - Net 1,650,680 1,651,215 1,608,865
Construction work in progress 42,178 20,564 46,628
Held for future use 1,773 1,106 1,150
Electric plant - Net 1,694,631 1,672,885 1,656,643
INVESTMENTS AND OTHER PROPERTY 36,502 16,826 18,034
CURRENT ASSETS:
Cash and cash equivalents 7,928 8,468 7,748
Receivables:
Customer 34,962 33,357 31,889
Allowance for uncollectible accounts (1,394) (1,397) (1,377)
Notes 5,104 5,134 4,962
Employee notes receivable 4,486 4,648 5,444
Other 8,489 10,771 4,316
Accrued unbilled revenues 27,709 25,025 29,115
Materials and supplies (at average cost) 24,639 25,937 24,141
Fuel stock (at average cost) 11,631 13,063 11,310
Prepayments 16,165 20,778 21,398
Regulatory assets associated
with income taxes 4,397 5,777 5,674
Total current assets 144,116 151,561 144,620
DEFERRED DEBITS:
American Falls and Milner water rights 32,260 32,440 32,605
Company-owned life insurance 57,291 56,066 49,510
Regulatory assets associated
with income taxes 196,696 200,379 179,311
Regulatory assets - other 89,507 68,348 67,713
Other 44,334 43,248 43,380
Total deferred debits 420,088 400,481 372,519
TOTAL $2,295,337 $2,241,753 $2,191,816
The accompanying notes are an integral part of these statements.
IDAHO POWER COMPANY
CONSOLIDATED BALANCE SHEETS
CAPITALIZATION AND LIABILITIES
December 31,
1996 1995 1994
(Thousands of Dollars)
CAPITALIZATION:
Common stock equity:
Common stock - $2.50 par value
(shares authorized 50,000,000
shares outstanding-37,612,351) $ 94,031 $ 94,031 $ 94,031
Premium on capital stock 362,297 363,044 363,063
Capital stock expense (3,842) (4,127) (4,132)
Retained earnings 242,088 229,827 220,838
Total common stock equity 694,574 682,775 673,800
Preferred stock 106,975 132,181 132,456
Long-term debt 738,550 672,618 693,206
Total capitalization 1,540,099 1,487,574 1,499,462
CURRENT LIABILITIES:
Long-term debt due within one year 71 20,517 517
Notes payable 54,016 53,020 55,000
Accounts payable 36,370 40,483 32,063
Taxes accrued 17,304 15,409 16,394
Interest accrued 15,886 14,785 14,755
Deferred income taxes 4,397 5,777 5,674
Other 12,439 12,867 12,574
Total current liabilities 140,483 162,858 136,977
DEFERRED CREDITS:
Regulatory liabilities associated
with deferred investment tax credits 71,283 70,507 71,593
Deferred income taxes 411,890 408,394 375,252
Regulatory liabilities
associated with income taxes 35,028 34,554 35,090
Regulatory liabilities - other 616 789 626
Other 95,938 77,077 72,816
Total deferred credits 614,755 591,321 555,377
COMMITMENTS AND CONTINGENT
LIABILITIES (Note 8)
TOTAL $2,295,337 $2,241,753 $2,191,816
The accompanying notes are an integral part of these statements.
IDAHO POWER COMPANY
CONSOLIDATED STATEMENTS OF INCOME
Year Ended December 31,
1996 1995 1994
(Thousands of Dollars)
REVENUES $578,445 $545,621 $543,658
EXPENSES:
Operation:
Purchased power 69,038 54,586 60,216
Fuel expense 63,334 54,691 94,888
Power cost adjustment (6,859) 7,292 (12,076)
Other 132,667 126,714 123,328
Maintenance 42,731 35,953 43,490
Depreciation 69,705 67,415 60,202
Taxes other than income taxes 20,658 22,979 23,945
Total expenses 391,274 369,630 393,993
INCOME FROM OPERATIONS 187,171 175,991 149,665
OTHER INCOME:
Allowance for equity funds used
during construction 46 (16) 1,680
Other - Net 12,488 14,372 10,480
Total other income 12,534 14,356 12,160
INTEREST CHARGES:
Interest on long-term debt 52,165 51,147 51,172
Other interest 5,183 5,309 3,261
Total interest charges 57,348 56,456 54,433
Allowance for borrowed funds
used during construction (353) (1,442) (1,781)
Net interest charges 56,995 55,014 52,652
INCOME BEFORE INCOME TAXES 142,710 135,333 109,173
INCOME TAXES 52,092 48,412 34,243
NET INCOME 90,618 86,921 74,930
Dividends on preferred stock 7,463 7,991 7,398
EARNINGS ON COMMON STOCK $83,155 $78,930 $67,532
AVERAGE COMMON SHARES
OUTSTANDING (000) 37,612 37,612 37,499
EARNINGS PER SHARE OF
COMMON STOCK $ 2.21 $ 2.10 $ 1.80
The accompanying notes are an integral part of these statements.
IDAHO POWER COMPANY
CONSOLIDATED STATEMENTS OF RETAINED EARNINGS
Year Ended December 31,
1996 1995 1994
(Thousands of Dollars)
RETAINED EARNINGS
Beginning of year $229,827 $220,838 $222,900
NET INCOME 90,618 86,921 74,930
Total 320,445 307,759 297,830
DIVIDENDS:
Preferred stock 7,463 7,991 7,398
Common stock (per share:
1996 - 1994 - $1.86 69,924 69,941 69,594
Total dividends 77,387 77,932 76,992
PREFERRED STOCK REDEMPTION 970 - -
RETAINED EARNINGS
End of year $242,088 $229,827 $220,838
The accompanying notes are an integral part of these statements.
IDAHO POWER COMPANY
CONSOLIDATED STATEMENTS OF CAPITALIZATION
December 31,
1996 % 1995 % 1994 %
(Thousands of Dollars)
COMMON STOCK EQUITY:
Common stock $ 94,031 $ 94,031 $ 94,031
Premium on capital stock 362,297 363,044 363,063
Capital stock expense (3,842) (4,127) (4,132)
Retained earnings 242,088 229,827 220,838
Total common stock equity 694,574 45 682,775 46 673,800 45
PREFERRED STOCK:
4% preferred stock 16,975 17,181 17,456
7.68% Series, serial
preferred stock 15,000 15,000 15,000
8.375% Series, serial
preferred stock - 25,000 25,000
7.07% Series, serial
preferred stock 25,000 25,000 25,000
Auction rate preferred stock 50,000 50,000 50,000
Total preferred stock 106,975 7 132,181 9 132,456 9
First mortgage bonds:
5 1/4 % Series due 1996 - 20,000 20,000
5.33 % Series due 1998 30,000 30,000 30,000
8.65 % Series due 2000 80,000 80,000 80,000
6.93 % Series due 2001 30,000 - -
6.85 % Series due 2002 27,000 - -
6.40 % Series due 2003 80,000 80,000 80,000
8 % Series due 2004 50,000 50,000 50,000
9.50 % Series due 2021 75,000 75,000 75,000
7.50 % Series due 2023 80,000 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 527,000 490,000 490,000
Amount due within one year - (20,000) -
Net first mortgage bonds 527,000 470,000 490,000
Pollution control revenue bonds:
5.90 % Series due 2003 - 24,200 24,650
6.0 % Series due 2007 - 24,000 24,000
7 1/4 % Series due 2008 4,360 4,360 4,360
7 5/8 % Series 1083-1984
due 2013-2014 - 68,100 68,100
8.30 % Series 1984 due 2014 49,800 49,800 49,800
6.05 % Series 1996A due 2026 68,100 - -
Variable rate Series
1996B due 2026 24,200 - -
Variable rate Series
1996C due 2026 24,000 - -
Total pollution control
revenue bonds 170,460 170,460 170,910
Amount due within one year - (450) (450)
Net pollution control
revenue bonds 170,460 170,010 170,460
REA notes 1,632 1,700 1,768
Amount due within one year (71) (67) (67)
Net REA notes 1,561 1,633 1,701
Subsidiary debt 9,000 - -
American Falls bond guarantee 20,560 20,740 20,905
Milner Dam note guarantee 11,700 11,700 11,700
Unamortized premium/discount-Net (1,731) (1,465) (1,560)
Total long-term debt 738,550 48 672,618 45 693,206 46
TOTAL CAPITALIZATION $1,540,099 100 $1,487,574 100 $1,499,462 100
The accompanying notes are an integral part of these statements.
IDAHO POWER COMPANY
CONSOLIDATED STATEMENTS OF CASH FLOWS
Year Ended December 31,
1996 1995 1994
(Thousands of Dollars)
OPERATING ACTIVITIES:
Cash received from operations:
Retail revenues $490,504 $468,821 $457,202
Wholesale revenues 66,551 59,260 62,110
Other revenues 24,469 22,825 23,711
Fuel paid (59,798) (61,741) (94,530)
Purchased power paid (70,302) (52,526) (62,592)
Other operation & maintenance (177,055) (154,209) (171,774)
Interest paid (include long and
short-term debt only) (53,273) (54,303) (52,376)
Income taxes paid (45,050) (40,402) (16,518)
Taxes other than income taxes
paid (23,455) (22,939) (21,698)
Other operating cash receipts
and payments-Net 21,824 3,634 2,122
Net cash provided by 174,415 168,420 125,657
FINANCING ACTIVITIES:
First mortgage bonds issued 57,000 - -
PC bond fund requisitions/other
long-term debt 128,534 - -
Common stock issued - - 13,402
Short-term borrowings-Net 1,000 (2,000) 51,000
Long-term debt retirement (140,069) (519) (466)
Preferred stock retirement (26,530) (151) (166)
Dividends on preferred stock (7,850) (7,888) (7,565)
Dividends on common stock (69,923) (69,967) (69,594)
Other sources/uses (4,144) (781) -
Net cash - financing
activities (61,982) (81,306) (13,389)
INVESTING ACTIVITIES:
Additions to utility plant (93,645) (83,965) (110,523)
Conservation (3,839) (5,688) (6,830)
Increase in investments (20,153) - -
Other 4,664 3,259 4,605
Net cash - investing
activities (112,973) (86,394) (112,748)
Change in cash and cash
equivalents (540) 720 (480)
Cash and cash equivalents
beginning of year 8,468 7,748 8,228
Cash and cash equivalents
end of year 7,928 8,468 7,748
RECONCILIATION OF NET INCOME TO NET
CASH PROVIDED BY OPERATING
ACTIVITIES:
Net income $ 90,618 $ 86,921 $ 74,930
Adjustments to reconcile net
income to net cash:
Depreciation 69,705 67,415 60,202
Deferred income taxes 7,201 11,698 14,265
Investment tax credit - Net 776 (1,086) (1,064)
Allowance for funds used
during construction (399) (1,425) (3,461)
Postretirement benefits funding
(excl pensions) 1,340 (2,857) (5,182)
Changes in operating assets
and liabilities:
Accounts receivable 3,079 5,285 (635)
Fuel inventory 3,535 (7,050) 358
Accounts payable (1,264) 2,061 (2,376)
Taxes payable (3,696) (2,519) 7,296
Interest payable 3,870 2,100 1,656
Other - Net (350) 7,877 (20,332)
Net cash provided by
operating activities $174,415 $168,420 $125,657
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 six wholly-
owned subsidiaries, Idaho Energy Resources Co. (IERCo), Ida-West
Energy Company (Ida-West), IDACORP, Inc., Idaho Utility Products
Company (IUPCo), Stellar Dynamics, Inc. (Stellar), and Idaho
Power Resources Corporation (IPRC). All significant intercompany
transactions and balances have been eliminated in consolidation.
Investments in business entities in which the Company and its
subsidiaries do not have control, but has the ability to exercise
significant influence over operating and financial policies, are
accounted for using the equity method.
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 rate
making process over the service life of the related property
through increased revenues resulting from higher rate base and
higher depreciation expense. Based on the uniform formula adopted
by the FERC, the Company's weighted average monthly AFDC rates
for 1996, 1995 and 1994 were 6.1 percent, 6.1 percent and 8.2
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.
In 1996, under terms and conditions of the Regulatory Settlement
with the Idaho Public Utilities Commission (IPUC) , the Company
set aside approximately $4.9 million of revenues for the benefit
of its Idaho customers. Under the Settlement, when the Company's
actual earnings in a given year exceeds an 11.75 percent return
on year-end common equity, the Company will refund 50 percent of
the excess.
POWER COST ADJUSTMENT - The Company has in place, in its Idaho
jurisdiction, a Power Cost Adjustment (PCA) mechanism which
provides for Idaho's retail customer rates to be based on
forecasted net power supply costs. Deviations from forecasted
costs are deferred with interest and then adjusted (trued-up) in
the subsequent year.
DEPRECIATION - All electric plant is depreciated using the
straight-line method. Annual depreciation provisions as a percent
of average depreciable electric plant in service approximated
2.89 percent in 1996, 2.90 percent in 1995 and 2.93 percent in
1994 and are considered adequate to amortize the original cost
over the estimated service lives of the properties.
INCOME TAXES - The Company follows the liability method of
computing deferred taxes on all temporary differences between
book and tax basis of assets and liabilities and adjusts deferred
tax assets and liabilities for enacted changes in tax laws or
rates. 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. 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 (see Note 2).
The state of Idaho allows a three percent investment tax credit
(ITC) upon certain qualifying plant additions. ITC earned on
regulated assets are deferred and amortized to income over the
estimated service lives of the related properties. Credits earned
on non-regulated assets or investments are recognized in the year
earned.
In 1995, the Company received an accounting order from the IPUC
approving acceleration of amortization of up to $30.0 million of
regulatory liabilities associated with deferred ITC to non-
operating income. The Internal Revenue Service and the Idaho
State Tax Commission have both approved the application.
Acceleration of ITC amortization is to be utilized until the
actual return on year-end common equity is 11.5 percent. No
accelerated ITC was recognized in 1995 or 1996.
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.
MANAGEMENT ESTIMATES - The preparation of financial statements,
in conformity with generally accepted accounting principles,
requires management to make estimates and assumptions that affect
the reported amounts of assets and liabilities and the disclosure
of contingent assets and liabilities at the date of the financial
statements and the reported amounts of revenues and expenses
during the reporting period. Actual results could differ from
those estimates.
REGULATION OF UTILITY OPERATIONS - Electric utilities have
historically been recognized as natural monopolies and have
operated in a highly regulated environment in which they have an
obligation to provide electric service to their customers in
return for an exclusive franchise within their service territory
with an opportunity to earn a regulated rate of return. This
regulatory environment is changing. The generation sector has
experienced competition from non-utility power producers, and the
FERC is requiring utilities, including the Company, to provide
wholesale open-access transmission service to others and may
order electric utilities to enlarge their transmission systems to
facilitate transmission services.
Some state regulatory authorities are in the process of changing
utility regulations in response to federal and state statutory
changes and evolving competitive markets. The Company believes
that these statutory and conforming regulations may result in
increased wholesale competition. However, due to the company's
low cost structure, increased wholesale competition is not
expected to adversely affect it in the near term and may
favorably impact it in the long term. The Company is unable to
predict what financial impact or effect the adoption of any such
legislation would have on its operations.
The Company follows Statement of Financial Accounting Standards
(SFAS) No. 71, "Accounting for the Effects of Certain Types of
Regulation", and its financial statements reflect the effects of
the different rate making principles followed by the various
jurisdictions regulating the Company. Pursuant to SFAS No. 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 1996, 1995 and 1994:
1996 1995 1994
Assets Liab. Assets Liab. Assets Liab.
(Millions of Dollars)
Income taxes $201.1 $35.0 $206.2 $ 34.6 $185.0 $35.1
Conservation 40.3 36.3 29.7
Employee benefits 7.4 8.3 9.5
PCA deferral and
amortizatioin 9.6 2.1 9.1
Other 32.2 0.6 21.6 0.7 19.4 0.6
Accumulated deferred
Investment tax credits 71.3 70.5 71.6
Total $290.6 $106.9 $274.5 $105.8 $252.7 $107.3
At December 31, 1996, the Company had $22.6 million of regulatory
assets that were not earning a return on investment excluding the
$201.1 million that relates to income taxes.
In the event that recovery of cost through rates becomes unlikely
or uncertain, SFAS No. 71 would no longer apply. If the Company
were to discontinue application of SFAS No. 71 for some or all of
its operations, then these items may 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 is not allowed recovery of these
investments, it would be required to write off the applicable
portion of regulatory assets and the financial effects could be
significant.
DERIVATIVES - The Company has a policy which allows for the use
of financial instruments such as commodity futures, options and
swaps as a means of hedging against the risks associated with
price fluctuations in the electricity market. At December 31,
1996, the Company's hedging transactions did not have a material
effect on its financial statements.
OTHER ACCOUNTING POLICIES - Debt discount, expense and premium
are being amortized over the terms of the respective debt issues.
RECLASSIFICATIONS - Certain items previously reported for years
prior to 1996 have been reclassified to conform with the current
year' s presentation. Net income was not affected by these
reclassifications.
2. INCOME TAXES:
A reconciliation between the statutory
federal income tax 1996 1995 1994
rate and the effective rate is as
follows: (Thousands of Dollars)
Computed income taxes based on
statutory federal income tax rate $ 49,949 $ 47,367 $ 38,210
Change in taxes resulting from:
AFDC (140) (504) (1,211)
Investment tax credits (2,835) (2,837) (3,351)
Repair allowance (2,800) (3,150) (1,575)
Elimination of amounts provided
in prior years (16) (1,963) (2,607)
Current state income taxes 2,823 3,275 1,496
Depreciation 5,945 5,493 2,812
Affordable housing tax credits (1,777) - -
Other 943 731 469
Total provision for federal and
state income taxes $ 52,092 $ 48,412 $ 34,243
Effective tax rate 36.5% 35.8% 31.4%
The provision for income taxes
consists of the following:
Income taxes currently payable:
Federal $40,379 $33,456 $19,617
State 3,746 4,503 1,425
Total 44,125 37,959 21,042
Income taxes deferred - Net of
amortization:
Federal 6,877 10,904 12,595
State 314 635 1,670
Total 7,191 11,539 14,265
Investment and other tax credits:
Deferred 3,611 1,751 1,643
Restored (2,835) (2,837) (2,707)
Total 776 (1,086) (1,064)
Total provision for income taxes $ 52,092 $ 48,412 $ 34,243
The tax effects of significant items
comprising the Company's net deferred
tax liability are as follows:
Deferred tax assets:
Regulatory liability $ 35,028 $ 34,554 $ 35,090
Advances for construction 17,736 14,823 10,542
Other 13,550 10,498 6,387
Total 66,314 59,875 52,019
Deferred tax liabilities:
Property, plant and equipment 245,652 237,655 225,444
Regulatory asset 201,093 206,156 184,985
Investment tax credit 71,283 70,507 71,593
Conservation programs 13,720 11,746 4,704
Other 22,136 18,489 17,812
Total 553,884 544,553 504,538
Net deferred tax liabilities $487,570 $484,678 $452,519
The Company has settled Federal and Idaho tax liabilities on all
open years through the 1992 tax year except for amounts related
to a partnership which, in management's opinion, have been
adequately accrued.
3. COMMON STOCK:
Changes in shares of the common stock of the Company for 1996,
1995 and 1994 were as follows:
Common Stock
Premium on
$2.50 Capital
Shares Par Value Stock
(Thousands of Dollars)
Balance at December 31, 1993 37,085,055 $92,713 $350,882
Gain on reacquired 4%
preferred stock - - 126
Stock purchase plans 527,296 1,318 12,055
Balance at December 31, 1994 37,612,351 94,031 363,063
Gain on reacquired 4%
preferred stock - - 117
Restricted stock plans - - (136)
Balance at December 31, 1995 37,612,351 94,031 363,044
Gain on reacquired 4%
preferred stock - - 83
Restricted stock plans - - (102)
Preferred stock redemption - - (728)
Balance at December 31, 1996 37,612,351 $94,031 $362,297
During the period of January 1994 through May 1994, the Company
issued 527,296 original issue shares of common stock for its
Dividend Reinvestment and Stock Purchase Plan and the Employee
Savings Plan.
As of December 31, 1996, 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.
The Company has a Shareowner Rights Plan (Plan) designed to
ensure that all shareholders receive fair and equal treatment in
the event of any proposal to acquire control of the Company.
Under the Plan, the Company declared a distribution of one
Preferred Stock Right (Right) for each of the Company's
outstanding Common shares held on January 29, 1990 or issued
thereafter. The Rights are currently not exercisable and will be
exercisable only if a person or group (Acquiring Person) either
acquires ownership of 20 percent or more of the Company's Voting
Stock or commences a tender offer that would result in ownership
of 20 percent or more. The Company may redeem the Rights at a
price of $0.01 per Right anytime prior to acquisition by an
Acquiring Person of a 20 percent position.
Following the acquisition of a 20 percent position, each Right
will entitle its holder, subject to regulatory approval, to
purchase for $85 that number of shares of Common Stock or
Preferred Stock having a market value of $170.
If after the Rights become exercisable, the Company is acquired
in a merger or other business combination, 50 percent or more of
its consolidated assets or earnings power are sold or the
Acquiring Person engages in certain acts of self-dealing, each
Right entitles the holder to purchase for $85, shares of the
acquiring company's Common Stock having a market value of $170.
Any Rights that are or were held by an Acquiring Person become
void if either of these events occurs. The Rights expire on
January 11, 2000.
4. PREFERRED STOCK:
The number of shares of preferred stock outstanding at December
31, 1996, 1995 and 1994 were as follows:
Shares Outstanding at Call Price
December 31,
1996 1995 1994 Per Share
Preferred stock:
Cumulative, $100 par value:
4% preferred stock
(authorized 215,000 shares) 169,753 171,813 174,556 $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) - 250,000 250,000
7.07% Series, $100 stated
value, authorized 250,000
shares)(a) 250,000 250,000 250,000 $103.535 to
$100.354
Auction rate preferred
stock, $100,000 stated
value, (authorized 500
shares)(b) 500 500 500 $100,000.00
Total 570,253 822,313 825,056
(a) The preferred stock is not redeemable prior to July 1, 2003.
(b) Dividend rate at December 31, 1996 was 4.05% and ranged
between 4.00% and 4.31% during the year.
During 1996, 1995 and 1994 the Company reacquired and retired
2,060; 2,743; and 2,950 shares of 4% preferred stock resulting in
a net addition to premium on capital stock of $82,900, $117,346,
and $126,066 respectively. As of December 31, 1996 the overall
effective cost of all outstanding preferred stock was 5.54
percent.
On November 7, 1996, the Company redeemed the $25,000,000
principal amount of 8.375% Series, serial preferred stock with
par value, ($100 stated value) from proceeds of the issuance of
$27,000,000 principal amount of secured medium term notes, Series
B, 6.85%, Due 2002. The total cost was $26,395,000 which
includes a premium of $1,395,000. The redemption premium plus
the initial issuance expense of $303,547, was charged $728,541 to
premium on capital stock and $970,006 to retained earnings.
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.
First mortgage bonds maturing during the five-year period ending
2001 are $30,000,000 in 1998, $80,000,000 in 2000 and $30,000,000
in 2001. On July 29, 1996, the Company issued $30,000,000
principal amount of Secured Medium Term Notes, Series B, 6.93%
Series Due 2001. The net proceeds were used for repayment of
commercial paper issued in connection with the Company's ongoing
construction program. On October 2, 1996, $27,000,000 principal
amount of Secured Medium Term Notes, Series B, 6.85% Due 2002
were issued with net proceeds from this sale used to redeem the
Company's 250,000 shares of 8.375% Series, Serial Preferred
Stock, Without Par Value.
On August 29, 1996, tax exempt Pollution Control Revenue
Refunding Bonds were issued in principal amount of $68,100,000
Series 1996A, $24,200,000 Series 1996B and $24,000,000 Series
1996C. The proceeds were used to retire the $24,200,000
Pollution Control Revenue Bonds due 2003, $24,000,000 Pollution
Control Revenue Bonds due 2007 and the $68,100,000 Pollution
Control Revenue Bonds due 2013-2014. At December 31, 1996, 1995
and 1994, the overall effective cost of all outstanding first
mortgage bonds and pollution control revenue bonds was 7.73
percent, 8.02 percent and 8.02 percent, respectively.
6. FINANCIAL INSTRUMENTS:
Fair Value - 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 $773,760,000 for 1996,
$731,168,000 for 1995 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, 1997, the Company had regulatory authority to incur
up to $200,000,000 of short-term indebtedness. On December 19,
1996, the Company replaced its committed lines of credit
arrangements with a $120,000,000 multi-year revolving credit
facility, which will expire on December 19, 2001. Under this
facility the Company will pay a facility fee on the commitment,
quarterly in arrears, based on the Company's First Mortgage Bond
rating. Commercial paper may be issued in an amount not to
exceed 25 percent of revenues for the latest twelve-month period
subject to the $200,000,000 maximum described above 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,
1996 1995 1994
(Thousands of Dollars)
Balance at end of year $54,016 $53,020 $55,000
Effective annual interest rate
at end of year 5.7% 6.0% 6.1%
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 $2.2 million at December 31, 1996. 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 67 on-line
cogeneration and small power production facilities with contracts
ranging from 1 to 32 years. Under these contracts the Company is
required to purchase all of the output from these facilities.
During the fiscal year ended December 31, 1996, the Company
purchased 776,368 (MWH) at a cost of $43.7 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
financial position, results of operation or cash flow.
9. BENEFIT PLANS:
Incentive Plans - The Company implemented two annual incentive
plans 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. For
the years 1996 and 1995 total incentive for the plans was
$2,467,334 and $2,898,785, respectively.
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. At December 31, 1996, there were 370,000 shares of
common stock reserved for the Plan. Grants are offered to all
officers. The Committee has selected a three-year restricted
period for each grant. A new grant can be offered in each
succeeding year with a single financial performance goal of
Cumulative Earnings Per Share ("CEPS"). Final award amounts will
depend on the attainment by the Company of the CEPS performance
goal established by the Committee and may be prorated in the
event of death, disability or retirement of an officer based on
the number of whole months of service the officer completes
during the Restricted Period. Upon the officer's termination of employment
during the Restricted Period for any other reason, all such
shares will be forfeited by the officer to the Trustee.
Effective January 1, 1997, certain senior managers of the Company
have become participants in the Plan.
Restricted stock awards are compensatory awards and the Company
accrues compensation expenses (which are charged to operations)
based upon the market value of the granted shares.
For the years 1996 and 1995, total compensation for the plan was
$184,153 and $91,200, respectively.
The following table shows the cumulative amount of grants offered
by the Company for the years 1996 and 1995:
Balance of shares outstanding at January 1, 1995 -
Granted in 1995 9,480
Forfeited in 1995 (360)
Balance at December 31, 1995 9,120
Granted in 1996 9,740
Forfeited in 1996 (720)
Balance at December 31, 1996 18,140
At December 31, 1996, no shares were vested under the plan.
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 was not required to contribute to the plan in 1996, but
funded $5.9 million in 1995 and $5.5 million in 1994. 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 (Security Plan) 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 in excess of the projected benefit
obligation and do not qualify as plan assets in the actuarial
computation of the funded status. Based upon SFAS No. 87,
"Employers' Accounting for Pensions", the Company has recorded a
net liability of $21.8 million as of December 31, 1996.
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.
Plan Costs for the Year 1996 1995 1994
Pension plan: (Thousands of Dollars)
Service cost $ 6,273 $ 5,167 $ 6,049
Interest cost 13,647 12,998 12,263
Actual return on plan assets (30,214) (45,990) 312
Deferred gain (loss) on plan 12,230 31,489 (15,584)
Net cost $ 1,936 $ 3,664 $ 3,040
Approximate percentage
included in operating expenses 67% 65% 67%
Net deferred compensation plan
costs charged to other income
(including life insurance and
SFAS No. 87 liability
accrual)(a) $ 794 $ 37 $ 508
(a) These charges to the Income Statement have been reduced by
gains from the Company-owned life insurance of $1,697; $2,320
and $2,724, for 1996, 1995 and 1994, respectively.
Funded status and significant assumptions as of December 31:
Pension Plan Deferred Compensation Plan
1996 1995 1994 1996 1995 1994
(Thousands of Dollars)
Actuarial present
value of benefit
obligations:
Vested benefit
obligation $155,343 $145,334 $128,162 $21,840 $21,530 $19,148
Accumulated benefit
obligation 158,349 150,688 132,766 21,840 21,530 19,148
Projected benefit
obligation $202,049 $193,133 $167,103 $22,370 $22,111 $19,681
Plan assets at fair
value 230,479 204,760 165,839 - - -
Plan assets in
excess of (or less
than) projected
benefit obligation 28,430 11,627 (1,264) (22,370) (22,111) (19,681)
Unrecognized net
(gain) loss from past
experience different
from that assumed (20,995) (8,341) 6,040 4,376 4,389 2,173
Unrecognized prior
service cost 5,517 5,941 6,365 (2,762) (3,097) (3,516)
Unrecognized net
(asset) obligation
existing at date of
initial adoption
(19.5 years straight-
line amortization) (2,230) (2,493) (2,756) 5,214 5,827 6,440
Minimum liability
adjustment - - - (6,298) (6,538) (4,564)
Net asset (liability)
included in the
balance sheet $ 10,722 $ 6,734 $ 8,385 $(21,840) $(21,530) $(19,148)
Discount rate to
compute projected
benefit obligation 7.35% 7.25% 8.0% 7.35% 7.25% 8.0%
Rate for future
compensation
increases 4.5 4.5 4.5 4.5 4.5 4.5
Expected long-term
rate of return on
plan assets 9.0 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 benefit
obligation of this plan was $1,752,000, $1,581,000, and $857,000 at
December 31, 1996, 1995 and 1994, respectively, with accrued pension
costs of $918,000, $682,000, and $396,000. The Company's net periodic
pension cost of this plan was $306,000, $184,000, and $125,000 for the
same periods. During 1996, the SERP was merged with the Security Plan.
Savings Plan - The Company has an Employee Savings Plan whereby,
for each $1 of employee contribution up to 6 percent of their
base 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 in any or all of seven investment options. The
Company's contribution amounted to $2,285,904 in 1996, $2,426,840
in 1995, and $2,410,200 in 1994.
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 following tables set forth the amounts recognized in the
Company's financial statements for year-end 1996, 1995 and 1994
and the funded status of the plan in accordance with SFAS No.
106, "Employers' Accounting for Postretirement Benefits other
than Pensions", as of December 31:
1996 1995 1994
Postretirement Benefit Cost: (Thousands of Dollars)
Service Cost $ 794 $ 763 $ 855
Interest Cost 3,172 3,571 3,334
Actual return on plan assets (1,410) (1,116) (1,114)
Amortization of transition
obligation (20-year amortization) 2,040 2,040 2,040
Net amortization and deferral (57) - -
Regulatory assets - 506 (1,907)
Voluntary severance program - 64 -
Net cost $ 4,539 $ 5,828 $ 3,208
Funded Status:
Accumulated postretirement benefit
obligation (APBO) $(44,439) $(48,928) $(45,001)
Plan assets at fair value 17,341 15,920 12,116
APBO in excess of plan assets (27,098) (33,008) (32,885)
Unrecognized gain/losses (5,478) 378 773
Unrecognized transition obligation 32,640 34,680 36,720
Prepaid postretirement benefit cost $ 64 $ 2,050 $ 4,608
Discount rate 7.50% 7.50% 8.25%
Medical and dental inflation rate 6.75 6.75 7.25
Long-term plan assets expected return 9.0 9.0 9.0
A one percent change in the medical inflation rate would change
the APBO by 7.2 percent and the post retirement expense for 1996
by 8.6 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 $1,390,800 in
1996, $1,754,300 in 1995 and $776,400 in 1994. The funding to the
VEBA was $0 in 1996, $916,200 in 1995, and $743,600 in 1994 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.
Post-employment Retirement Benefits - The Company provides
certain benefits to former or inactive employees, their
beneficiaries, and covered dependents after employment but before
retirement. The Company accrues for such post employment
benefits. These benefits include salary continuation and related
health care and life insurance for both long and short-term
disability plans, workmen's compensation and health care for
surviving spouse and dependent plan. The Company recognizes a
deferred asset which represents future revenue expected to be
realized at the time the post employment benefits are included in
the Company's rates. The Company has recorded a liability of $4.1
million and a regulatory asset of $3.0 million which represents
the costs associated with post employment benefits at December
31, 1996. The Company received an IPUC order 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 1996, 1995, and 1994.
1996 1995 1994
(Thousands of Dollars)
Electric Plant in Service:
Production $1,323,090 $1,350,239 $1,303,572
Transmission 371,123 330,812 308,055
Distribution 688,232 648,549 625,149
General and Other 155,120 152,230 147,122
Total in service 2,537,565 2,481,830 2,383,898
Less accumulated provision
for depreciation 886,885 830,615 775,033
In service - Net $1,650,680 $1,651,215 $1,608,865
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
operation and maintenance expenses applicable to the projects.
Each facility and extent of Company participation as of December
31, 1996 are as follows:
Company Ownership
Accumulated
Electric Provision
Name of Plant Location In Service for Depreciation % MW
(Thousands of Dollars)
Jim Bridger Rock Springs, WY
Units 1-4 $382,135 $169,126 33 693
Boardman Boardman, OR 60,780 28,028 10 53
Valmy Units 1 Winnemucca, NV
and 2 299,156 112,523 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 $34,974,000 in 1996,
$44,278,000 in 1995, and $46,097,000 in 1994.
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 $8,953,000 in
1996, $8,696,000 in 1995, and $7,139,000 in 1994.
INDEPENDENT AUDITORS' REPORT
Board of Directors and Shareowners of Idaho Power Company:
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 schedule at Item 8. These financial statements and
financial statement schedule are the responsibility of the
Company's management. Our responsibility is to express an opinion
on the financial statements and financial statement schedules
based on our audits.
We conducted our audits in accordance with generally accepted
auditing standards. Those standards require that we plan and
perform the audit to obtain reasonable assurance about whether
the financial statements are free of material misstatement. An
audit includes examining, on a test basis, evidence supporting
the amounts and disclosures in the financial statements. An audit
also includes assessing the accounting principles used and
significant estimates made by management, as well as evaluating
the overall financial statement presentation. We believe that our
audits provide a reasonable basis for our opinion.
In our opinion, such consolidated financial statements present
fairly, in all material respects, the financial position of Idaho
Power Company and subsidiaries at December 31, 1996, 1995, and
1994, 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 schedule, when considered in relation to the basic
consolidated financial statements taken as a whole, presents
fairly in all material respects the information set forth
therein.
DELOITTE & TOUCHE LLP
Portland, Oregon
January 31, 1997
IDAHO POWER COMPANY
SUPPLEMENTAL FINANCIAL INFORMATION, UNAUDITED
QUARTERLY FINANCIAL DATA:
The following unaudited information is presented for each quarter
of 1996, 1995 and 1994 (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 operations 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 December
30 31
1996
Revenues $146,629 $140,384 $149,652 $141,781
Income from operations 58,489 46,741 41,780 40,161
Income taxes 17,466 12,828 11,597 10,201
Net income 30,211 23,033 19,151 18,225
Dividends on preferred stock 1,952 1,927 1,954 1,632
Earnings on common stock 28,259 21,106 17,197 16,593
Earnings per share of
common stock 0.75 0.56 0.45 0.44
1995
Revenues 131,336 130,254 148,726 135,306
Income from operations 46,552 38,681 45,637 45,122
Income taxes 14,234 10,951 12,442 10,786
Net income 20,727 17,588 23,771 24,833
Dividends on preferred stock 2,026 2,006 1,976 1,982
Earnings on common stock 18,701 15,582 21,795 22,851
Earnings per share of
common stock 0.50 0.41 0.58 0.61
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 stock 0.44 0.41 0.38 0.57
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, 1996.
(c) Exhibits.
*Previously Filed and Incorporated Herein by Reference
Exhibit File Number As 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.
Exhibit File Number As Exhibit
*3(b) 33-41166 4(b) Waiver resolution to Restated
Articles of Incorporation adopted
by Shareholders on May 1, 1991.
*3(c) 33-00440 4(a)(xiv) By-laws of the Company amended on
June 30, 1989, and presently in
effect.
*4(a)(i) 2-3413 B-2 Mortgage and Deed of Trust, dated as
of October 1, 1937, between the
Company and Bankers Trust Company
and R. G. Page, as Trustees.
*4(a)(ii) Supplemental Indentures to Mortgage
and Deed of Trust:
Number Dated
1-MD B-2-a First July 1, 1939
2-5395 7-a-3 Second November 15, 1943
2-7237 7-a-4 Third February 1, 1947
2-7502 7-a-5 Fourth May 1, 1948
2-8398 7-a-6 Fifth November 1, 1949
2-8973 7-a-7 Sixth October 1, 1951
2-12941 2-C-8 Seventh January 1, 1957
2-13688 4-J Eighth July 15, 1957
2-13689 4-K Ninth November 15, 1957
2-14245 4-L Tenth April 1, 1958
2-14366 2-L Eleventh October 15, 1958
2-14935 4-N Twelfth May 15, 1959
2-18976 4-O Thirteenth November 15, 1960
2-18977 4-Q Fourteenth November 1, 1961
2-22988 4-B-16 Fifteenth September 15, 1964
2-24578 4-B-17 Sixteenth April 1, 1966
2-25479 4-B-18 Seventeenth October 1, 1966
2-45260 2(c) Eighteenth September 1, 1972
2-49854 2(c) Nineteenth January 15, 1974
2-51722 2(c)(i) Twentieth August 1, 1974
2-51722 2(c)(ii) Twenty-first October 15, 1974
2-57374 2(c) Twenty-second November 15, 1976
2-62035 2(c) Twenty-third August 15, 1978
33-34222 4(d)(iii) Twenty-fourth September 1, 1979
33-34222 4(d)(iv) Twenty-fifth November 1, 1981
33-34222 4(d)(v) Twenty-sixth May 1, 1982
33-34222 4(d)(vi) Twenty-seventh May 1, 1986
33-00440 4(c)(iv) Twenty-eighth June 30, 1989
33-34222 4(d)(vii) Twenty-ninth January 1, 1990
33-65720 4(d)(iii) Thirtieth January 1, 1991
33-65720 4(d)(iv) Thirty-first August 15, 1991
33-65720 4(d)(v) Thirty-second March 15, 1992
33-65720 4(d)(vi) Thirty-third April 16, 1993
1-3198 4 Thirty-fourth December 1, 1993
Form 8-K
Dated
12/17/93
Exhibit File Number As Exhibit
*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.
Exhibit File Number As Exhibit
*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(i)(ii) 1-3198 10(i)(ii) Third Restated and Amended Coal
Form 10-Q Sales Agreement, dated January 1,
for 3/31/96 1996, 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).
Exhibit File Number As Exhibit
*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 1-3198 10(n)(i) The Revised Security Plans for
Form 10-K Senior Management Employees and for
for 1994 Directors-a non-qualified, deferred
compensation plan effective November
30, 1994.
*10(n)(ii)1 1-3198 10(n)(ii) The Executive Annual Incentive Plan
Form 10-K for senior management employees
for 1994 effective January 1, 1995.
*10(n)(iii)1 1-3198 10(n)(iii) The 1994 Restricted Stock Plan for
Form 10-K officers and key executives
for 1994 effective July 1, 1994.
10(n)(iv)1 The Revised Security Plans for
Senior Management Employees and for
Directors-a non-qualified, deferred
compensation plan effective August
1, 1996.
*10(o) 33-65720 10(f) Residential Purchase and Sale
Agreement, dated August 22, 1981,
among the United Stated of American
Department of Energy acting by and
through the Bonneville Power
Administration, and the Company.
*10(p) 33-65720 10(g) Power Sales Contact, dated
August 25, 1981, including
amendments, among the United States
of America Department of Energy
acting by and through the Bonneville
Power Administration, and the
Company.
*10(q) 33-65720 10(h) Framework Agreement, dated October
1, 1984, between the State of Idaho
and the Company relating to the
Company's Swan Falls and Snake River
water rights.
*10(q)(i) 33-65720 10(h)(i) Agreement, dated October 25, 1984,
between the State of Idaho and the
Company relating to the agreement
filed as Exhibit 10(q).
*10(q)(ii) 33-65720 10(h)(ii) Contract to Implement, dated October
25, 1984, between the State of Idaho
and the Company relating to the
agreement filed as Exhibit 10(q).
*10(r) 33-65720 10(i) Agreement for Supply of Power and
Energy, dated February 10, 1988,
between the Utah Associated
Municipal Power Systems and the
Company.
1 Compensatory Plan
Exhibit File Number As Exhibit
*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.
*10(x) 1-3198 10(x) Agreement for design of substation
Form 10-Q dated October 4, 1995, between the
for 9/30/95 Company and Micron Technology, Inc.
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 Auditor's Consent
27 Financial Data Schedule
IDAHO POWER COMPANY
SCHEDULE II - CONSOLIDATED VALUATION AND QUALIFYING ACCOUNTS
Years Ended December 31, 1996, 1995 and 1994
Column A Column B Column C Column D Column E
Additions
Charged
Balance at Charged (Credited) Balance at
Beginning to to Other Deduction End of
Classification of Period Income Accounts (1) Period
(Thousands of Dollars)
1996:
Reserves Deducted
From Applicable Assets:
Reserve for
uncollectible
accounts $1,397 $ - $3,003(2) $3,006 $1,394
Other Reserves:
Injuries and
damages
reserve $1,500 $ - $ - $ - $1,500
Miscellaneous
operating
reserves $1,143 $ 829 $4,874 $ 198 $6,648
1995:
Reserves Deducted
From Applicable Assets:
Reserve for
uncollectible
accounts $1,377 $ 217 $2,927(2) $3,124 $1,397
Other Reserves:
Injuries and
damages
reserves $1,500 $1,364 $ - $1,364 $1,500
Miscellaneous
operating
reserve $ 940 $ 460 $ (176) $ 81 $1,143
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
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 caused this
report to be signed on its behalf by the undersigned, thereunto
duly authorized.
IDAHO POWER COMPANY
(Registrant)
March 13, 1997 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 13, 1997
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, Chief Financial "
J. LaMont Keen Officer and Treasurer
(Principal Financial and
Accounting Officer)
By:/s/Robert D. Bolinder By:/s/Evelyn Loveless "
Robert D. Bolinder Evelyn Loveless
Director Director
By:/s/Roger L. Breezley By:/s/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)(iv) The Revised Security Plans
for Senior Management
Employees and for Directors-a 72
non-qualified, deferred
compensation plan effective
August 1, 1996
12 Statement Re: Computation of
Ratio of Earnings to Fixed 139
Charges
12(a) Statement Re: Computation of
Supplemental Ratio of 140
Earnings to Fixed Charges
12(b) Statement Re: Computation of
Ratio of Earnings to Combined
Fixed Charges and Preferred 141
Dividend Requirements
12(c) Statement Re: Computation of
Supplemental Ratio of
Earnings to Combined Fixed 142
Charges and Preferred
Dividend Requirements.
21 Subsidiaries of Registrant 143
23 Independent Auditors' 144
Consent.
27 Financial Data Schedule 145
Exhibit 10(n)(iv)
IDAHO POWER COMPANY
SECURITY PLAN FOR
SENIOR MANAGEMENT EMPLOYEES
Amended and Restated
Effective August 1, 1996
TABLE OF CONTENTS
ARTICLE I _ PURPOSE; EFFECTIVE DATE 1
ARTICLE II _ DEFINITIONS 2
2.1 Actuarial Equivalent 2
2.2 Administrative Committee 2
2.3 Beneficiary 2
2.4 Board 2
2.5 Change in Control 3
2.6 Change in Control Period 4
2.7 Company 4
2.8 Compensation 5
2.9 Compensation Committee 5
2.10 Contract of Participation 5
2.11 Disability 5
2.12 Early Retirement Date 5
2.13 Employer 5
2.14 Final Average Monthly Compensation 5
2.15 Frozen Retirement Benefit 6
2.16 Frozen Survivor Benefit 7
2.17 Normal Form of Benefit 7
2.18 Normal Retirement Date 7
2.19 Participant 8
2.20 Plan Year 8
2.21 Retirement 8
2.22 Retirement Plan 8
2.23 Security Plan Retirement Benefit 8
2.24 Target Retirement Percentage 8
2.25 Years of Participation 8
ARTICLE III _ PARTICIPATION AND VESTING 9
3.1 Eligibility and Participation 9
3.2 Vesting 9
3.3 Change in Employment Status 9
ARTICLE IV _ BENEFIT ELECTION 10
4.1 Benefit Election 10
4.2 Commencement of Benefits 10
ARTICLE V _ SURVIVOR BENEFITS 11
5.1 Pre-retirement Survivor Benefits 11
5.2 Post-termination Survivor Benefit 12
5.3 Survivor Benefit Election for
Participants Prior to December 1, 1994. 12
5.4 Suicide 13
ARTICLE VI _ SECURITY PLAN RETIREMENT BENEFITS 14
6.1 Normal Retirement Benefit 14
6.2 Early Retirement Benefit 14
6.3 Early Retirement Factor 14
6.4 Early Termination Benefits 16
6.5 Termination After Change in Control 16
6.6 Form of Payment 17
ARTICLE VII _ OTHER RETIREMENT PROVISIONS 18
7.1 Disability 18
7.2 Withholding Payroll Taxes 18
7.3 Payment to Guardian 18
7.4 Accelerated Distribution 18
ARTICLE VIII _ BENEFICIARY DESIGNATION 20
8.1 Beneficiary Designation for Participant
Not Eligible for Frozen Survivor Benefit 20
8.2 Beneficiary Designation for Participant
Eligible for Frozen Survivor Benefit 21
8.3 Beneficiary Designation at Commencement
of Benefits 23
8.4 Effect of Payment 23
ARTICLE IX _ ADMINISTRATION 24
9.1 Administrative Committee Duties 24
9.2 Indemnity of Administrative Committee 24
ARTICLE X _ CLAIMS PROCEDURE 26
10.1 Claim 26
10.2 Denial of Claim 26
10.3 Review of Claim 26
10.4 Final Decision 26
ARTICLE XI _ TERMINATION, SUSPENSION OR AMENDMENT 28
11.1 Termination, Suspension or Amendment of Plan 28
11.2 Change in Control 28
ARTICLE XII _ MISCELLANEOUS 29
12.1 Unfunded Plan 29
12.2 Unsecured General Creditor 29
12.3 Trust Fund 29
12.4 Nonassignability 30
12.5 Not a Contract of Employment 30
12.6 Governing Law 30
12.7 Validity 31
12.8 Notice 31
12.9 Successors 31
IDAHO POWER COMPANY
SECURITY PLAN FOR SENIOR MANAGEMENT EMPLOYEES
AMENDED AND RESTATED
EFFECTIVE AUGUST 1, 1996
ARTICLE I
PURPOSE; EFFECTIVE DATE
The purpose of this Security Plan for Senior Management Employees
(the "Plan") is to provide supplemental retirement benefits for
certain key employees of Idaho Power Company, its subsidiaries and
affiliates. It is intended that the Plan will aid in retaining and
attracting individuals of exceptional ability by providing them with
these benefits. The effective date of this restatement shall be
August 1, 1996.
ARTICLE II
DEFINITIONS
For the purposes of this Plan, the following terms shall have the
meanings indicated, unless the context clearly indicates otherwise:
2.1 Actuarial Equivalent. "Actuarial Equivalent" shall mean
equivalence in value between two (2) or more forms and/or times of
payment based on a determination by an actuary chosen by the Company
using generally accepted actuarial assumptions, methods and factors as
used in the Retirement Plan of Idaho Power Company which may be
amended from time to time.
For purposes of Section 7.4, Actuarial Equivalent shall be
calculated using the Pension Benefit Guaranty Immediate Rate as of the
month preceding distribution plus 1% and the mortality table specified
in the Retirement Plan of Idaho Power Company which may be amended
from time to time.
2.2 Administrative Committee. "Administrative Committee" shall
mean the Administrative Committee appointed by the Compensation
Committee pursuant to Section 9.1 hereof to administer the Plan.
2.3 Beneficiary. "Beneficiary" shall mean the person, persons
or entity designated by the Participant pursuant to Article VIII to
receive any benefits payable under the Plan. Each such designation
shall be made in a written instrument filed with the Administrative
Committee and shall become effective only when received, accepted and
acknowledged in writing by the Administrative Committee or its
designee.
2.4 Board. "Board" shall mean the Board of Directors of the
Company.
2.5 Change in Control. "Change in Control" shall mean the
earlier of the
following to occur:
(a) the public announcement by the Company or by any person
(which shall not include the Company, any subsidiary of the
Company or any employee benefit plan of the Company or of any
subsidiary of the Company) ("Person") that such Person, who or
which, together with all Affiliates and Associates (within the
meanings ascribed to such terms in Rule 12b-2 of the Securities
Exchange Act of 1933 [the "Exchange Act"]) of such Person, shall
be the beneficial owner of twenty percent (20%) or more of the
voting stock then outstanding;
(b) the commencement of, or after the first public
announcement of any Person to commence, a tender or exchange
offer the consummation of which would result in any Person
becoming the beneficial owner of voting stock aggregating thirty
percent (30%) or more of the then outstanding voting stock;
(c) the announcement of any transaction relating to the
Company required to be described pursuant to the requirements of
Item 6(e) of Schedule 14A of Regulation 14A of the Securities and
Exchange Commission under the Exchange Act;
(d) a proposed change in the constituency of the Board such
that, during any period of two (2) consecutive years, individuals
who at the beginning of such period constitute the Board cease
for any reason to constitute at least a majority thereof, unless
the election or nomination for election by the shareholders of
the Company of each new director was approved by a vote of at
least two-third (2/3) of the directors then still in office who
were members of the Board at the beginning of the period; or
(e) the Company enters into an agreement of merger,
consolidation, share exchange or similar transaction with any
other corporation other than a transaction which would result in
the Company's voting stock outstanding immediately prior to the
consummation of such transaction continuing to represent (either
by remaining outstanding or by being converted into voting stock
of the surviving entity) at least two-thirds of the combined
voting power of the Company's or such surviving entity's
outstanding voting stock immediately after such transaction;
(f) the Board approves a plan of liquidation or dissolution
of the Company or an agreement for the sale or disposition by the
Company (in one transaction or a series of transactions) of all
or substantially all of the Company's assets to a person or
entity which is not an affiliate of the Company other than a
transaction(s) for the purpose of dividing the Company's assets
into separate distribution, transmission or generation entities
or such other entities as the Company may determine.
(g) any other event which shall be deemed by a majority of
the Executive Committee of the Board to constitute a "Change in
Control."
2.6 Change in Control Period. "Change in Control Period" shall
mean the period beginning with a Change in Control as defined in
Section 2.5 and ending with the earlier of: (i) termination date of
the Change in Control as determined by the Compensation Committee or
(ii) 24 months following the consummation of a Change in Control.
2.7 Company. "Company" shall mean the Idaho Power Company, an
Idaho corporation, its successors and assigns.
2.8 Compensation Committee. "Compensation Committee" shall mean
the Board committee assigned responsibility for administering
Executive Compensation.
2.9 Compensation. "Compensation" shall mean the base salary and
annual bonuses paid to a Participant and considered to be "wages" for
purposes of federal income tax withholding. Compensation shall be
calculated before reduction for any amounts deferred by the
Participant pursuant to any plan sponsored by the Employer which
permits deferral of current compensation. Compensation does not
include long-term incentive compensation in any form, expense
reimbursements, or any form of noncash compensation or benefits.
2.10 Contract of Participation. "Contract of Participation"
shall mean an agreement of participation in the Idaho Power Security
Plan for Senior Management Employees between the Participant and the
Employer in the form attached as Appendix A.
2.11 Disability. "Disability" shall mean that a Participant is
eligible to receive benefits under the Long-Term Disability Program
maintained by the Employer.
2.12 Early Retirement Date. "Early Retirement Date" shall mean
the date on which a Participant terminates employment with the
Employer, if such termination date occurs on or after such
Participant's attainment of age fifty-five (55) but prior to
Participant's Normal Retirement Date.
2.13 Employer. "Employer" shall mean the Company and any
affiliated or subsidiary corporation designated by the Board, or any
successors to the business thereof.
2.14 Final Average Monthly Compensation. "Final Average Monthly
Compensation" shall mean the Compensation received by the Participant
during any sixty (60) consecutive months (during the last ten (10)
years of employment) for which the Participant's compensation was the
highest divided by sixty (60). In determining Final Average Monthly
Compensation, annual bonuses shall be allocated equally to the months
in which they were accrued or earned. Final Average Monthly
Compensation shall not include any Compensation payable to a
Participant pursuant to a written severance agreement with the
Employer.
2.15 Frozen Retirement Benefit. "Frozen Retirement Benefit"
shall mean the benefit accrued as of November 30, 1994, under the
Idaho Power Company Security Plan for Senior Management Employees as
amended and restated May 1, 1990. The Frozen Retirement Benefit shall
be calculated using compensation through November 30, 1994, and actual
age at commencement of benefits. All Participants are 100% vested in
their Frozen Retirement Benefit as of November 30, 1994. The Frozen
Retirement Benefit shall be paid in the form and manner set forth in
this Plan prior to the November 30, 1994 amendment including the early
retirement reduction factors in effect under the May 1, 1990
restatement. The Frozen Retirement Benefit shall include the
Participant's salary reduction with interest as provided in Section
5.5 of the Idaho Power Company Security Plan for Senior Management
Employees as amended and restated May 1, 1990. In addition, the
Frozen Retirement Benefit shall also include any benefit payable from
the Idaho Power Company Supplemental Employee Retirement Plan (SERP)
before August 1, 1996 Restatement. The Participant's age, service and
compensation at August 1, 1996 shall be used in determining this
additional Frozen Retirement Benefit from the SERP. Effective
November 30, 1994, there shall be no additional employee contributions
or salary reductions under this Plan. The Frozen Retirement Benefit
accrued shall not be reduced due to the failure to complete salary
reductions for the final benefit class if such failure resulted from
removing the salary reduction requirement from the Plan effective
November 30, 1994.
2.16 Frozen Survivor Benefit. "Frozen Survivor Benefit" shall
mean the survivor benefit accrued as of November 30, 1994, under
Article IV of the Idaho Power Company Security Plan for Senior
Management Employees as amended and restated May 1, 1990. The Frozen
Survivor Benefit shall be calculated using compensation through
November 30, 1994. All Participants are 100% vested in their Frozen
Survivor Benefit as of November 30, 1994. The Frozen Survivor Benefit
shall be paid in the form and manner set forth in this Plan prior to
the November 30, 1994 amendment. The Frozen Survivor Benefit shall
include the Participant's salary reduction with interest as provided
in Section 5.5 of the Idaho Power Company Security Plan for Senior
Management Employees as amended and restated May 1, 1990. Effective
November 30, 1994, there shall be no additional employee contributions
or salary reductions under this Plan. In addition, the Frozen
Survivor Benefit shall also include any benefit payable from the Idaho
Power Company Supplemental Employee Retirement Plan (SERP) before
August 1, 1996 Restatement. The Participant's age, service and
compensation at termination shall be used in determining this
additional Frozen Survivor Benefit from the SERP. The Frozen Survivor
Benefit accrued shall not be reduced due to the failure to complete
salary reductions for the final benefit class if such failure resulted
from removing the salary reduction requirement from the Plan effective
November 30, 1994.
2.17 Normal Form of Benefit. "Normal Form of Benefit" shall mean
the normal form of monthly retirement benefit provided under
Section 3.01 of the Employer's Retirement Plan.
2.18 Normal Retirement Date. "Normal Retirement Date" shall mean
the date on which the Participant terminates employment with the
Employer if the termination date occurs on or after the Participant
attains age sixty-two (62).
2.19 Participant. "Participant" shall mean any individual who is
participating in or has participated in this Plan as provided in
Article III.
2.20 Plan Year. "Plan Year" shall mean the calendar year
effective November 30, 1994.
2.21 Retirement. "Retirement" shall mean a Participant's
termination from employment with the Employer at the Participant's
Early Retirement Date or Normal Retirement Date, as applicable.
2.22 Retirement Plan. "Retirement Plan" shall mean The
Retirement Plan of Idaho Power Company as may be amended from time to
time.
2.23 Security Plan Retirement Benefit. "Security Plan Retirement
Benefit" shall mean the benefit determined under Article VI of this
Plan.
2.24 Target Retirement Percentage. "Target Retirement
Percentage" shall equal six percent (6%) for each of the first ten
(10) years of participation plus an additional one percent (1%) for
each Year of Participation, exceeding ten (10). The maximum Target
Retirement Percentage shall be seventy-five percent (75%).
2.25 Years of Participation. "Years of Participation" shall be
twelve (12) month periods, and portions thereof, which shall begin on
the earlier of, the date of the Participant's employment in a senior
management level position or a date designated by the Administrative
Committee, and shall end at the termination of participation. Partial
Years of Participation, if any, shall be used in determining benefits
under this Plan.
ARTICLE III
PARTICIPATION AND VESTING
3.1 Eligibility and Participation.
(a) Eligibility. Eligibility to participate in the Plan is
limited to those key employees of the Employer that are
designated, from time to time, by the Employer.
(b) Participation. Participation in the Plan shall
continue until such time as the Participant ceases participation
in this Plan and as long thereafter as the Participant is
eligible to receive benefits under this Plan.
3.2 Vesting. A Participant shall be one hundred percent (100%)
immediately vested.
3.3 Change in Employment Status. If the Employer determines
that a Participant's employment performance or classification is no
longer at a level which deserves participation in this Plan, but does
not terminate the Participant's employment with the Employer,
participation herein and eligibility to receive benefits hereunder
shall be limited to the Participant's accrued benefit as of the date
of the change in employment status. In such an event, the benefits
payable to the Participant shall be based solely on the Participant's
Years of Participation and Final Average Monthly Compensation as of
such date. The benefit shall be calculated under the early retirement
provisions pursuant to Sections 6.2 and 6.3(a), with commencement of
benefit not earlier than the later of termination of employment or age
fifty-five (55).
ARTICLE IV
BENEFIT ELECTION
4.1 Benefit Election. Participants in this Plan prior to
December 1, 1994 or, if the Participant is deceased, the Beneficiary
of such Participant, must elect to receive in the 30-day period
immediately prior to receipt of any benefits under this Plan, (a) the
Frozen Benefit (the Frozen Retirement Benefit or Frozen Survivor
Benefit); or (b) the benefit accrued under this Plan as in effect
after November 30, 1994.
A Participant may at any time prior to death or commencing
benefits elect pursuant to Section 5.3(b) that upon their death before
commencing benefits, the Frozen Survivor Benefit be paid to the
designated Beneficiaries. This election may be revoked by the
Participant at any time. This election requires spousal consent if
the Participant is married.
4.2 Commencement of Benefits. A Participant or a Beneficiary
shall determine the date when benefits shall commence within the time
authorized by the Plan.
ARTICLE V
SURVIVOR BENEFITS
5.1 Pre-retirement Survivor Benefits. If a Participant dies
while employed by the Employer, the Employer shall pay a survivor
benefit to such Participant's Beneficiary as follows:
(a) Amount. The pre-termination survivor benefit shall be
equal to sixty-six and two-thirds percent (66 2/3%) of the
retirement benefit calculated under Article VI assuming
retirement occurred at the later of age sixty-two (62) or date of
death. Final Average Monthly Compensation and the Retirement
Plan benefit shall be determined as of the date of the
Participant's death. For purposes of this section (a), the
Retirement Plan benefit shall be the accrued benefit determined
as of the date of death as defined in the Retirement Plan.
(b) Payment. If the Participant is married on the date of
death, the benefits shall be paid to the spouse of the
Participant for the life of the spouse beginning on the first day
of the month coincident with or following the date of death. If
the spouse's date of birth is more than ten (10) years after the
Participant's date of birth, the monthly benefit shall be reduced
using the Actuarial Equivalent factors to reflect the number of
years over ten (10) the spouse is younger than the Participant.
If the Participant is unmarried on the date of death, the benefit
shall be paid to the Participant's Beneficiary in a lump sum that
is the Actuarial Equivalent of the value of a death benefit
payable to an assumed spouse the same age as the Participant.
5.2 Post-termination Survivor Benefit.
(a) Death Prior to Commencement of Benefits.
(i) Amount. The amount of the post-termination
survivor benefit shall be equal to sixty-six and two thirds
percent (66 2/3%) of the retirement benefit payable to the
Participant.
(ii) Payment. If the Participant is married on the
date of death, the benefits shall be paid to the spouse of
the Participant for the life of the spouse beginning on the
first day of the month coincident with or following the date
of death. If the spouse's date of birth is more than ten
(10) years after the Participant's date of birth, the
monthly benefit shall be reduced using Actuarial Equivalent
factors to reflect the number of years over ten (10) the
spouse is younger than the Participant. If the Participant
is unmarried on the date of death, the benefit shall be paid
to the Participant's Beneficiary in a lump sum that is the
Actuarial Equivalent of the value of a death benefit payable
to an assumed spouse the same age as the Participant.
(b) Death After Commencement of Benefits. If a Participant
dies after commencement of benefits, a survivor benefit will be
paid only if, and to the extent provided for, under the form of
benefit elected by the Participant pursuant to Sections 6.6.
5.3 Survivor Benefit Election for Participants Prior to December
1, 1994.
(a) Death Prior to Commencing Benefits and Making Frozen
Survivor Benefit Election. As described in Section 4.1, if a
Participant who participated in this Plan prior to December 1,
1994 dies prior to commencing benefits, the Beneficiary of the
Participant must elect to receive (a) the Frozen Survivor
Benefit; or (b) the benefit accrued under Section 5.1 of this
plan as in effect after November 30, 1994. If the Participant
was unmarried at the time of the Participant's death and more
than one primary Beneficiary has been designated, the
Beneficiaries shall be deemed to have elected the benefit of
highest value based on the Actuarial Equivalent basis specified
in Section 2.1 of this Plan.
(b) Election of Frozen Survivor Benefit Prior to Commencing
Benefits. A Participant may at any time prior to commencing
benefits elect that, upon their death before commencing benefits,
the Frozen Survivor Benefit be paid to the designated
Beneficiary(ies). This election, including the Beneficiary(ies)
designation, requires spousal consent if married. This election
may be revoked by the Participant at any time. If this election
is made and the Participant dies before commencing benefits, the
Frozen Survivor Benefit shall be paid to the Beneficiary(ies) in
lieu of the survivor benefits described in Sections 5.1 and 5.2.
5.4 Suicide. In the event a Participant commits suicide within
one (1) year of initially entering this Plan, no benefits shall be
payable hereunder to the Participant's Beneficiaries.
ARTICLE VI
SECURITY PLAN RETIREMENT BENEFITS
6.1 Normal Retirement Benefit. The monthly Security Plan
Retirement Benefit shall equal the Target Retirement Percentage
multiplied by the Participant's Final Average Monthly Compensation,
less the amount of the Participant's retirement benefit under the
Retirement Plan Normal Form of Benefit regardless of the form actually
selected by the Participant under the Retirement Plan. If the
Participant selects an "optional" form of benefit under this Plan,
then the benefit shall be the Actuarial Equivalent of the Normal Form
of Benefit.
6.2 Early Retirement Benefit. If a Participant retires at an
Early Retirement Date, the Employer shall pay to the Participant a
monthly Security Plan Retirement Benefit. The Early Retirement
Benefit shall be equal to the Target Retirement Percentage, multiplied
by the Early Retirement Factor and by the Participant's Final Average
Monthly Compensation, less the amount of the Participant's retirement
benefit under the Retirement Plan Normal Form of Benefit at the later
of, age fifty-five (55) or the Participant's retirement date. If the
Participant selects an "optional" form of benefit under this Plan,
then the benefit shall be the Actuarial Equivalent of the Normal Form
of Benefit.
6.3 Early Retirement Factor. If a Participant retires before
the Participant's Normal Retirement Date, the Target Retirement
Percentage shall be multiplied by one (1) of the following Early
Retirement Factors.
(a) If termination occurs with approval or if the
Participant terminates within a Change in Control Period, the
Early Retirement Factor shall be as described below:
Exact Age When Early
Payments Begin Retirement
Factor
62 100%
61 96%
60 92%
59 87%
58 82%
57 77%
56 72%
55 67%
Early retirement factors will be prorated to
reflect retirement on other than an exact age (completed
months).
(b) If termination occurs without approval and the
Participant has not terminated within a Change in Control Period,
the Early Retirement Factor shall be the factor described in (a)
above, times a fraction equal to the Participant's Years of
Participation at termination divided by the Years of
Participation the Participant would have had at Participant's
Normal Retirement Date if Participant had continued to be
employed by the Employer.
(c) Authorization to grant approval for early retirement is
vested with the Compensation Committee for elected officers of
the Employer and with the Chief Executive Officer of the Employer
for non-officers.
6.4 Early Termination Benefits. If a vested Participant
terminates employment with the Employer prior to Retirement or death,
the Employer shall pay to the Participant, commencing not earlier than
the later of the Participant's fifty-fifth (55th) birthday or
termination of employment, the Security Plan Retirement Benefit as
determined under this section.
(a) The Target Retirement Percentage shall be calculated
based upon the Years of Participation and then multiplied by a
fraction equal to the Participant's actual Years of Participation
divided by the Years of Participation the Participant would have
had at the Normal Retirement Date if the Participant had
continued to be employed by the Employer to age sixty-two (62).
The adjusted Target Retirement Percentage shall be further
reduced by the factor described in Section 6.3(a) for each month
between the Participant's benefits commencement date and age
sixty-two (62).
(b) The Early Termination Benefit shall be offset by the
Retirement Plan Normal Form of Benefit payable on the date of
benefit commencement regardless of service.
6.5 Termination After Change in Control. If a Participant
terminates within the Change in Control Period, the Participant shall
receive, beginning on the later of the attainment of age fifty-five
(55) or the Participant's actual termination date, the Early
Retirement Benefit calculated with the Early Retirement Factors set
forth in 6.3(a).
6.6 Form of Payment. The Security Plan Retirement Benefit shall
be paid in the normal form provided below unless the Participant
elects twelve months prior to commencement of benefits an Actuarial
Equivalent form of benefit provided in this section.
(a) Normal Form of Benefit Payment. The normal form of
payment shall be a single-life annuity for the lifetime of the
Participant.
(b) Actuarial Equivalent Forms of Benefit.
(i) A joint and survivor annuity with payments
continued to the surviving spouse at an amount equal to two-
thirds (2/3) of the Participant's benefit.
(ii) A joint and survivor annuity with payments continued to
the surviving spouse at an amount equal to the Participant's benefit.
ARTICLE VII
OTHER RETIREMENT PROVISIONS
7.1 Disability. During a period of Disability, a Participant
will continue to accrue Years of Participation; and any benefits
payable under this Plan shall be based upon the greater of the
Participant's Compensation at the time of Disability or Final Average
Monthly Compensation.
7.2 Withholding Payroll Taxes. The Employer shall withhold from
payments made hereunder any taxes required to be withheld from a
Participant's wages under federal, state or local law.
7.3 Payment to Guardian. If a Plan benefit is payable to a
minor or a person declared incompetent or to a person incapable of
handling the disposition of property, the Administrative Committee may
direct payment of such Plan benefit to the guardian, legal
representative or person having the care and custody of the minor,
incompetent or person. The Administrative Committee may require proof
of incompetency, minority, incapacity or guardianship, as it may deem
appropriate, prior to distribution of the Plan benefit. The
distribution shall completely discharge the Administrative Committee
and the Employer from all liability with respect to such benefit.
7.4 Accelerated Distribution. Notwithstanding any other
provision of the Plan, a Participant shall be entitled to receive,
upon written request to the Administrative Committee, a lump sum
distribution equal to ninety percent (90%) of the Actuarial Equivalent
vested accrued Security Plan Retirement Benefit, as of the date thirty
(30) days after notice is given to the Administrative Committee. The
remaining balance of ten percent (10%) shall be forfeited by the
Participant. The amount payable under this section shall be paid in a
lump sum with ten (10) days following the thirty (30) day period
outlined above. If a Participant requests and obtains an accelerated
distribution under this Section 7.4 and remains employed by the
Company, participation will cease and there will be no future benefit
accruals under this Plan. Following the death of a Participant, the
Beneficiary may, at any time, request an accelerated distribution
under this section. If the deceased Participant named multiple
Beneficiaries, then all named Beneficiaries must consent to the
request for an accelerated distribution. The benefit payable to the
Beneficiary shall be equal to ninety percent (90%) of the Actuarial
Equivalent of the Security Plan Retirement Benefit payable to the
Beneficiary. Payment of an accelerated distribution pursuant to this
Section 7.4 shall completely discharge the Employer's obligation to
the Participant and any Beneficiaries under this Plan.
ARTICLE VIII
BENEFICIARY DESIGNATION
8.1 Beneficiary Designation for Participant Not Eligible for
Frozen Survivor Benefit. If the Participant is married, the
Beneficiary shall be the Participant's spouse. Each unmarried
Participant shall have the right, at any time, to designate any person
or persons as Beneficiary or Beneficiaries (both primary as well as
contingent) to whom payment under this Plan shall be made in the event
of the Participant's death prior to the discharge of the Employer's
obligation under this plan.
Any Beneficiary designation may be changed by a Participant by
the filing of a written form prescribed by the Administrative
Committee. The filing of a new Beneficiary designation form will
cancel all Beneficiary designations previously filed. Any finalized
divorce or marriage (other than common law) of a Participant
subsequent to the date of filing of a Beneficiary designation form
shall automatically revoke the prior designation. If a Participant
fails to designate a Beneficiary as provided above, or if the
Beneficiary designation is revoked by marriage or divorce, without
execution of a new designation, or if all designated Beneficiaries
predecease the Participant or die prior to complete distribution of
the Participant's benefits, then Participant's designated Beneficiary
shall be deemed to be the person or persons surviving the Participant
in the first of the following classes in which there is a survivor,
share and share alike:
(a) the Participant's surviving spouse;
(b) the Participant's children, except that if any of the
children predecease the Participant but leave issue surviving,
the issue shall take by right of representation;
(c) the Participant's personal representative (executor or
administrator).
8.2 Beneficiary Designation for Participant Eligible for Frozen
Survivor Benefit.
(a) Frozen Survivor Benefit Elected. If the Participant
elects the Frozen Survivor Benefit pursuant to Section 5.3(b),
the Participant shall designate any person or persons as
Beneficiary or Beneficiaries (both primary as well as contingent)
to whom payment of the Frozen Survivor Benefit shall be made in
the event of the Participant's death prior to commencement of
benefits under this Plan. If the Participant is married,
designation of a Beneficiary other than the spouse shall require
spousal consent. Any future change in Beneficiary shall also
require spousal consent.
(b) Frozen Survivor Benefit Not Elected by Married
Participant. If the Participant does not elect the Frozen
Survivor Benefit pursuant to Section 5.3(b) and the Participant
is married, the Participant's spouse shall be the Beneficiary to
whom payment of the Frozen Survivor Benefit shall be made in the
event of the Participant's death prior to the commencement of
benefits under the Plan.
(c) Frozen Survivor Benefit Not Elected by Unmarried
Participant. If the Participant does not elect the Frozen
Survivor Benefit pursuant to Section 5.3(b) and the Participant
is unmarried, the Participant shall designate any person or
persons as Beneficiary(ies) (both primary as well as contingent)
to whom payment of the Frozen Survivor Benefit shall be made in
the event of the Participant's death prior to the commencement of
benefits under this Plan.
Any Beneficiary designation may be changed by a Participant by
filing a written form prescribed by the Administrative Committee. The
filing of a new Beneficiary designation form will cancel all
Beneficiary designations previously filed.
Any finalized divorce or marriage (other than common law) of a
Participant subsequent to the date of filing a Beneficiary designation
form shall automatically revoke the prior designation unless the
Frozen Survivor Benefit has been elected pursuant to Section 5.3(b)
and a nonspouse beneficiary designated. If a Participant fails to
designate a Beneficiary as provided above, or if the Beneficiary
designation is revoked by marriage or divorce, without execution of a
new designation, or if all designated Beneficiaries predecease the
Participant or die prior to complete distribution of the Participant's
benefits, then Participant's designated Beneficiary shall be deemed to
be the person or persons surviving the Participant in the first of the
following classes in which there is a survivor, share and share alike:
(a) the Participant's surviving spouse;
(b) the Participant's children, except that if
any of the children predecease the Participant but
leave issue surviving, the issue shall take by right of
representation;
(c) the Participant's personal representative (executor or
administrator).
8.3 Beneficiary Designation at Commencement of Benefits.
Notwithstanding any Beneficiary designation made pursuant to Sections
8.1. and 8.2, a Participant who commences retirement benefits under
Article VI shall:
(a) If they elect the Frozen Retirement Benefit, designate
a Beneficiary or Beneficiaries (primary as well as contingent) to
whom any remainder of the payments shall be made in the event of
their death prior to receiving 180 payments.
(b) If they elect the benefit accrued under Article VI as
in effect after November 30, 1994, the Beneficiary shall be the
spouse pursuant to an election under Section 6.6. If no election
has been made under Section 6.6(b), no benefits are payable upon
the Participant's death.
8.4 Effect of Payment. The payment to the Beneficiary shall
completely discharge Employer's obligations under this Plan.
ARTICLE IX
ADMINISTRATION
9.1 Administrative Committee Duties. This Plan shall be
administered by an Administrative Committee which shall consist of not
less than three (3) nor more than five (5) persons appointed by the
Compensation Committee. Members of the Administrative Committee may
be Participants under this Plan. The Administrative Committee shall
have the authority to make, amend, interpret and enforce all
appropriate rules and regulations for the administration of this Plan
and decide or resolve any and all questions including interpretations
of this Plan, as may arise in connection with the Plan. A majority
vote of the Administrative Committee members shall control any
decision.
In the administration of this Plan, the Administrative Committee
may, from time to time, employ agents and delegate to them such
administrative duties as it sees fit and may from time to time consult
with counsel who may be counsel to the Employer.
Subject to Article X, the decision or action of the
Administrative Committee in respect of any questions arising out of,
or in connection with, the administration, interpretation and
application of the Plan and the rules and regulations promulgated
hereunder shall be final and conclusive and binding upon all persons
having any interest in the Plan.
9.2 Indemnity of Administrative Committee. To the extent
permitted by applicable law, the Employer shall indemnify, hold
harmless and defend the Administrative Committee against any and all
claims, loss, damage, expense or liability arising from any action or
failure to act with respect to this Plan, provided that the
Administrative Committee was acting in accordance with the applicable
standard of care. The indemnity provisions set forth in this Article
shall not be deemed to restrict or diminish in any way any other
indemnity available to the Administrative Committee members in
accordance with the Articles or By-laws of the Company.
ARTICLE X
CLAIMS PROCEDURE
10.1 Claim Any person claiming a benefit, requesting an
interpretation or ruling under the Plan, or requesting information
under the Plan shall present the request in writing to the
Administrative Committee who shall respond in writing as soon as
practicable.
10.2 Denial of Claim. If the claim or request is denied, the
written notice of denial shall state:
(a) the reason for denial, with specific reference to the
Plan provisions on which the denial is based;
(b) a description of any additional material or information
required and an explanation of why it is necessary; and
(c) an explanation of the Plan's claims review procedure.
10.3 Review of Claim. Any person whose claim or request is
denied or who has not received a response within thirty (30) days may
request a review by notice given in writing to the Administrative
Committee. The claim or request shall be reviewed by the
Administrative Committee who may, but shall not be required to, grant
the claimant a hearing. On review, the claimant may have
representation, examine pertinent documents, and submit issues and
comments in writing.
10.4 Final Decision. The decision on review shall normally be
made within sixty (60) days. If an extension of time is required for
a hearing or other special circumstances, the claimant shall be
notified and the time limit shall be one hundred twenty (120) days.
The decision shall be in writing and shall state the reason and the
relevant Plan provisions. All decisions on review shall be final and
bind all parties concerned.
ARTICLE XI
TERMINATION, SUSPENSION OR AMENDMENT
11.1 Termination, Suspension or Amendment of Plan. The Board
may, in its sole discretion, terminate or suspend this Plan at any
time or from time to time, in whole or in part. The Board may amend
this Plan at any time or from time to time. Any amendment may provide
different benefits or amounts of benefits from those herein set forth.
However, no such termination, suspension or amendment or other action
with respect to the Plan shall adversely affect the benefits of
Participants which have accrued prior to such action, the benefits of
any Participant who has previously retired, or the benefits of any
Beneficiary of a Participant who has previously died. Furthermore, no
termination, suspension or amendment shall alter the applicability of
the vesting schedule in Section 3.2 with respect to a Participant's
accrued benefit at the time of such termination, suspension or
amendment.
11.2 Change in Control. Notwithstanding Section 11.1 above,
during a Change in Control Period, neither the Board nor the
Administrative Committee may terminate this Plan with regard to
accrued benefits of current Participants. No amendment may be made to
the Plan during a Change in Control Period which would adversely
affect the accrued benefits of current Participants, the benefits of
any Participant who has retired, or the Beneficiary of any Participant
who has died. The Plan shall continue to operate and be effective
with regard to all current or retired Participants and their
Beneficiaries during any Change in Control Period.
ARTICLE XII
MISCELLANEOUS
12.1 Unfunded Plan. This Plan is intended to be an unfunded plan
maintained primarily to provide deferred compensation benefits for a
select group of "management or highly compensated employees" within
the meaning of Sections 201, 301 and 401 of the Employee Retirement
Income Security Act of 1974, as amended ("ERISA"), and therefore to be
exempt from the provisions of Parts 2, 3 and 4 of Title I of ERISA.
12.2 Unsecured General Creditor. Participants and their
Beneficiaries, heirs, successors and assigns shall have no legal or
equitable rights, interest or claims in any property or asset of the
Employer, nor shall they be Beneficiaries of, or have any rights,
claims or interests in any life insurance policies, annuity contracts
or the proceeds therefrom owned or which may be acquired by the
Employer. Except as may be provided in Section 12.3, such policies,
annuity contracts or other assets of the Employer shall not be held
under any trust for the benefit of Participants, their Beneficiaries,
heirs, successors or assigns, or held in any way as collateral
security for the fulfilling of the obligation of the Employer under
this Plan. Any and all of the Employer's assets and policies shall
be, and remain, the general, unpledged, unrestricted assets of the
Employer. The Employer's obligation under the Plan shall be that of
an unfunded and unsecured promise to pay money in the future.
12.3 Trust Fund. The Employer shall be responsible for the
payment of all benefits provided under the Plan. At its discretion,
the Employer may establish one or more trusts, with such trustees as
the Board may approve, for the purpose of providing for the payment of
such benefits. Such trust or trusts may be irrevocable, but the
assets thereof shall be subject to the claims of the Employer's
creditors. To the extent any benefits provided under the Plan are
actually paid from any such trust, the Employer shall have no further
obligation with respect thereto, but to the extent not so paid, such
benefits shall remain the obligation of, and shall be paid by, the
Employer.
12.4 Nonassignability. Neither a Participant nor any other
person shall have any right to commute, sell, assign, transfer,
pledge, anticipate, mortgage or otherwise encumber, transfer,
hypothecate or convey in advance of actual receipt the amounts, if
any, payable hereunder, or any part thereof, which are, and all rights
to which are, expressly declared to be unassignable and
nontransferable. No part of the amount payable shall, prior to actual
payment, be subject to seizure or sequestration for the payment of any
debts, judgments, alimony or separate maintenance owed by a
Participant or any other person, nor be transferable by operation of
law in the event of Participant's or any other person's bankruptcy or
insolvency.
12.5 Not a Contract of Employment. The terms and conditions of
this Plan shall not be deemed to constitute a contract of employment
between the Employer and the Participant, and the Participant (or
Participant's Beneficiary) shall have no rights against the Employer
except as may otherwise be specifically provided herein. Moreover,
nothing in this Plan shall be deemed to give a Participant the right
to be retained in the service of the Employer or to interfere with the
right of the Employer to discipline or discharge the Participant at
any time.
12.6 Governing Law. The provisions of this Plan shall be
construed, interpreted and governed in all respects in accordance with
the applicable federal law and, to the extent not preempted by such
federal law, in accordance with the laws of the State of Idaho without
regard to the principles of conflicts of laws.
12.7 Validity. If any provision of this Plan shall be held
illegal or invalid for any reason, the remaining provisions shall
nevertheless continue in full force and effect without being impaired
or invalidated in any way.
12.8 Notice. Any notice or filing required or permitted to be
given under the Plan shall be sufficient if in writing and hand
delivered, or sent by registered or certified mail or fax. The notice
shall be deemed given as of the date of delivery or, if delivery is
made by mail, as of the date shown on the postmark on the receipt for
registration or certification.
12.9 Successors. Subject to Section 11.1, the provisions of this
Plan shall bind and inure to the benefit of the Employer and its
successors and assigns. The term successors as used herein shall
include any corporate or other business entity which shall, whether by
merger, consolidation, purchase or otherwise acquire all or
substantially all of the business and assets of the Employer, and
successors of any such corporation or other business entity.
IDAHO POWER COMPANY
By: ________________________________
Chairman
By: ________________________________
Secretary
Dated: _____________________________
APPENDIX A
CONTRACT OF PARTICIPATION IN THE
IDAHO POWER COMPANY SECURITY PLAN
FOR SENIOR MANAGEMENT EMPLOYEES
NAME OF PARTICIPANT:
DATE OF BIRTH:
SENIOR MANAGEMENT PLAN ENTRY DATE:
BENEFICIARY:
This Agreement is made and entered into as of the date written
hereinbelow by and between Idaho Power Company and ______________.
This Agreement is subject to all of the terms of the Idaho Power
Company Security Plan for Senior Management Employees, as amended and
restated November 30, 1994 (The "Plan"). By signing this agreement,
Participant acknowledges receipt of a copy of the Plan document.
PARTICIPANT IDAHO POWER COMPANY
BY BY
PARTICIPANT CHAIRMAN
DATE DATE
IDAHO POWER COMPANY
SECURITY PLAN FOR BOARD OF DIRECTORS
Amended and Restated
Effective August 1, 1996
TABLE OF CONTENTS
ARTICLE IPURPOSE; EFFECTIVE DATE 1
1.1 Purpose 1
ARTICLE IIDEFINITIONS 2
2.1 Actuarial Equivalent 2
2.2 Administrative Committee 2
2.3 Beneficiary 2
2.4 Board 3
2.5 Change in Control 3
2.6 Change in Control Period 5
2.7 Company 5
2.8 Compensation Committee 5
2.9 Contract of Participation 5
2.10 Employer 5
2.11 Participant 6
2.12 Plan Anniversary Date 6
2.13 Plan Year 6
2.14 Supplemental Retirement Benefit 6
2.15 Year of Service 6
ARTICLE IIIPARTICIPATION AND VESTING 7
3.1 Participation 7
3.2 Fee Reduction 7
3.3 Vesting 7
ARTICLE IVSURVIVOR BENEFITS 8
4.1 Death Benefit 8
4.2 Suicide 12
ARTICLE V
RETIREMENT BENEFITS 13
5.1 Benefit 13
5.2 Form of Payment 13
5.3 Commencement of Benefit Payment 14
5.4 Grandfathered Form of Benefit 14
ARTICLE VIBENEFICIARY DESIGNATION 15
6.1 Beneficiary Designation 15
6.2 Amendments, Marital Status,
No Participant Designation 15
6.3 Effect of Payment 16
ARTICLE VIITERMINATION, SUSPENSION OR
AMENDMENT OF PLAN 17
7.1 Termination, Suspension or
Amendment of Plan 17
7.2 Change in Control 17
ARTICLE VIIIADMINISTRATION 18
8.1 Administrative Committee Duties 18
8.2 Indemnity of Administrative Committee 19
ARTICLE IXCLAIMS PROCEDURE 20
9.1 Claim 20
9.2 Denial of Claim 20
9.3 Review of Claim 20
9.4 Final Decision 20
ARTICLE XMISCELLANEOUS 22
10.1 Unfunded Plan 22
10.2 Unsecured General Creditor 22
10.3 Trust Fund 23
10.4 Nonassignability 23
10.5 Governing Law 23
10.6 Validity 24
10.7 Notice 24
10.8 Successors 24
10.9 Payment to Guardian 24
10.10 Accelerated Distribution. 25
IDAHO POWER COMPANY
SECURITY PLAN FOR BOARD OF DIRECTORS
AMENDED AND RESTATED AUGUST 1, 1996
ARTICLE I
PURPOSE; EFFECTIVE DATE
1.1 Purpose. The purpose of this restated Security Plan
for Board of Directors (the "Plan") is to define the terms of the
Plan to advance the interests of Idaho Power Company, an Idaho
corporation, and its stockholders by furnishing a variety of
supplemental benefits designed to attract and retain outstanding
individuals as directors of Idaho Power Company, its subsidiaries
and affiliates, and to stimulate the efforts of such directors by
giving suitable recognition to services which will contribute
materially to the success of Idaho Power. The effective date of
this restatement shall be August 1, 1996.
ARTICLE II
DEFINITIONS
For the purposes of this Plan, the following terms shall
have the meaning indicated, unless the context clearly indicates
otherwise.
2.1 Actuarial Equivalent. "Actuarial Equivalent" shall
mean equivalence in value between two (2) or more forms and/or
times of payment based on a determination by an actuary chosen by
the Company using generally accepted actuarial assumptions,
methods and factors as used in the Retirement Plan of Idaho Power
Company which may be amended from time to time.
For purposes of Section 10.10, Actuarial Equivalent shall be
calculated using the Pension Benefit Guaranty Immediate Rate as
of the month preceding distribution plus 1% and the mortality
table specified in the Retirement Plan of Idaho Power Company
which may be amended from time to time.
2.2 Administrative Committee. "Administrative Committee"
shall mean the committee appointed by the Compensation Committee
pursuant to Section 8.1 hereof to administer the Plan.
2.3 Beneficiary. "Beneficiary" shall mean the person,
persons or entity designated by the Participant or pursuant to
Article VI to receive any benefits payable under the Plan. Each
such designation shall be made in a written instrument filed with
the Administrative Committee and shall become effective only when
received, accepted and acknowledged in writing by the
Administrative Committee or its designee.
2.4 Board. "Board" shall mean the Board of Directors of
the Company.
2.5 Change in Control. "Change in Control" shall mean the
earlier of the
following to occur:
(a) the public announcement by the Company or by any
person (which shall not include the Company, any subsidiary of
the Company or any employee benefit plan of the Company or of any
subsidiary of the Company) ("Person") that such Person, who or
which, together with all Affiliates and Associates (within the
meanings ascribed to such terms in Rule 12b-2 of the Securities
Exchange Act of 1933 [the "Exchange Act"]) of such Person, shall
be the beneficial owner of twenty percent (20%) or more of the
voting stock then outstanding;
(b) the commencement of, or after the first public
announcement of any Person to commence, a tender or exchange
offer the consummation of which would result in any Person
becoming the beneficial owner of voting stock aggregating thirty
percent (30%) or more of the then outstanding voting stock;
(c) the announcement of any transaction relating to
the Company required to be described pursuant to the requirements
of Item 6(e) of Schedule 14A of Regulation 14A of the Securities
and Exchange Commission under the Exchange Act;
(d) a proposed change in the constituency of the Board
such that, during any period of two (2) consecutive years,
individuals who at the beginning of such period constitute the
Board cease for any reason to constitute at least a majority
thereof, unless the election or nomination for election by the
shareholders of the Company of each new director was approved by
a vote of at least two-third (2/3) of the directors then still
in office who were members of the Board at the beginning of the
period; or
(e) the Company enters into an agreement of merger,
consolidation, share exchange or similar transaction with any
other corporation other than a transaction which would result in
the Company's voting stock outstanding immediately prior to the
consummation of such transaction continuing to represent (either
by remaining outstanding or by being converted into voting stock
of the surviving entity) at least two-thirds of the combined
voting power of the Company's or such surviving entity's
outstanding voting stock immediately after such transaction;
(f) the Board approves a plan of liquidation or
dissolution of the Company or an agreement for the sale or
disposition by the Company (in one transaction or a series of
transactions) of all or substantially all of the Company's assets
to a person or entity which is not an affiliate of the Company
other than a transaction(s) for the purpose of dividing the
Company's assets into separate distribution, transmission or
generation entities or such other entities as the Company may
determine.
(g) any other event which shall be deemed by a
majority of the Executive Committee of the Board to constitute a
"Change in Control."
2.6 Change in Control Period. "Change in Control Period"
shall mean the period beginning with a Change in Control as
defined in Section 2.5 and ending with the earlier of: (i)
termination date of the Change in Control as determined by the
Compensation Committee or (ii) 24 months following the
consummation of a Change in Control
2.7 Company. "Company" shall mean the Idaho Power Company,
an Idaho corporation, its successors and assigns.
2.8 Compensation Committee. "Compensation Committee" shall
mean the Board committee assigned responsibility for
administering Executive Compensation.
2.9 Contract of Participation. "Contract of Participation"
shall mean an agreement of participation in the Idaho Power
Security Plan for Board of Directors between the Participant and
the Employer, in the form attached as Appendix A.
2.10 Employer. "Employer" shall mean the Company and any
affiliated or subsidiary corporation designated by the Board, or
any successors to the business thereof.
2.11 Participant. "Participant" shall mean any individual
who is elected to the Board and who has executed a Contract of
Participation.
2.12 Plan Anniversary Date. "Plan Anniversary Date" shall
mean February 1 of any year.
2.13 Plan Year. "Plan Year" shall mean the calendar year
effective November 30, 1994.
2.14 Supplemental Retirement Benefit. "Supplemental
Retirement Benefit" shall mean a benefit determined under
Article V of this Plan.
2.15 Year of Service. "Year of Service" shall mean each
twelve (12) months of service on the Board.
ARTICLE III
PARTICIPATION AND VESTING
3.1 Participation. Effective November 30, 1994,
participation in the Plan shall be limited to outside directors
who elect to participate in this Plan by executing a Contract of
Participation. Inside directors who were Participants on
November 30, 1994, shall receive their vested accrued benefit as
provided in Section 4.1(b) and Article V.
3.2 Fee Reduction. Effective November 30, 1994, no
additional or future fee reduction will be required.
3.3 Vesting. Participants shall be one hundred percent
(100%) immediately vested in their accrued benefit.
ARTICLE IV
SURVIVOR BENEFITS
4.1 Death Benefit.
(a) For all Participants who are first elected to the
Board after November 30, 1994, the survivor benefit shall be as
follows:
(i) If a Participant's death occurs prior to
severance from service on the Board and commencement of the
Supplemental Retirement Benefit, the Employer shall pay a
survivor benefit to such Participant's Beneficiary as follows:
(a) Amount. The pre-termination survivor
benefit shall be equal to sixty-six and two-thirds percent (66
2/3%) of the Supplemental Retirement Benefit calculated under
Article V. A Participant shall be considered to have a minimum
of five (5) Years of Service for purposes of this calculation.
(b) Payment. If the Participant is married
on the date of death, the benefits shall be paid for the life of
the spouse. If the spouse's date of birth is more than ten (10)
years after the Participant's date of birth, the monthly benefit
shall be reduced to the Actuarial Equivalent of the above
benefit, assuming the above benefit is payable to a spouse ten
(10) years younger than the Participant. If the Participant is
unmarried on the date of death, the benefit shall be paid to the
Participant's Beneficiary in a lump sum equal to the value of a
death benefit payable to an assumed spouse the same age as the
Participant.
(ii) If a Participant's death occurs after
termination from service on the Board but prior to commencement
of the Supplemental Retirement Benefit, the Employer shall pay a
survivor benefit to said Participant's Beneficiary as follows:
(a) Amount. The amount of the post-
termination survivor benefit shall be equal to sixty-six and two-
thirds percent (66 2/3%) of the Supplemental Retirement Benefit
payable to the Participant.
(b) Payment. If the Participant is married
on the date of death, the benefits shall be paid for the life of
the spouse. If the spouse's date of birth is more than ten (10)
years after the Participant's date of birth, the monthly benefit
shall be reduced to the Actuarial Equivalent of the above
benefit, assuming the above benefit is payable to a spouse ten
(10) years younger than Participant. If the Participant is
unmarried on the date of death, the benefit shall be paid to the
Participant's Beneficiary in a lump sum equal to the value of a
death benefit payable to an assumed spouse the same age as the
Participant.
(iii) Death After Commencement of Benefits.
If a Participant dies after commencement of benefits, a survivor
benefit will be paid only if, and to the extent provided for,
under the form of benefit elected by the Participant.
(b) For all Participants who are first elected to the
Board on or prior to November 30 1994, the survivor benefit shall
be as follows:
(i) If a Participant's death occurs prior to
commencement of the Supplemental Retirement Benefit, the
Participant's Beneficiaries shall receive the death benefit
described below unless the Participant's Beneficiary elects to
receive the death benefits provided for in Section 4.1(a)(i) in
lieu of this benefit. The death benefit will be determined by
the Participant's Years of Service, including Years of Service
after November 30, 1994, at death as set forth in the schedule
below:
YEARS OF MONTHLY ANNUAL
SERVICE BENEFIT BENEFIT
1 $ 291.67 $ 3,500
2 583.33 7,000
3 875.00 10,500
4 1,166.67 14,000
5 and over 1,458.33 17,500
The death benefits shall be paid to the Beneficiary in
equal monthly installments for the period of one hundred eighty
(180) months without interest. Payments shall commence on the
tenth day of the month following receipt by the Administrative
Committee of proof of Participant's death.
(ii) Death After Commencement of Benefits.
(a) A Participant who did not elect to
receive the Supplemental Retirement Benefit in the grandfathered
form as provided for in Section 5.4, and dies at any time after
severance from service on the Board and after the commencement of
the Supplemental Retirement Benefit, the Participant's
Beneficiary shall receive a survivor benefit to the extent
provided for under the form of benefit elected by the
Participant.
(b) A Participant who elected to receive the
Supplemental Retirement Benefit in the grandfathered form as
provided for in Section 5.4 and dies at any time after severance
from service on the Board and after the commencement of the
Supplemental Retirement Benefit, the Participant's Beneficiaries
shall receive the balance, if any, of the 180-month Supplemental
Retirement Benefit. Receipt by the Participant's Beneficiaries
of the benefit under this subparagraph shall be in lieu of all
other survivor benefits under this Plan.
4.2 Suicide. In the event a Participant commits suicide
within one (1) year of initially entering this Plan, no benefits
shall be payable hereunder to the Participant's Beneficiaries.
ARTICLE V
RETIREMENT BENEFITS
5.1 Benefit. Upon severance of service on the Board, each
Participant shall be entitled to receive, at the time specified
in Section 5.3 below, a Supplemental Retirement Benefit, the
amount of which will be determined by the Participant's Years of
Service on the Plan Anniversary Date immediately preceding or
coinciding with his severance date as set forth below:
YEARS OF MONTHLY ANNUAL
SERVICE BENEFIT BENEFIT
1 $ 291.67 $ 3,500
2 583.33 7,000
3 875.00 10,500
4 1,166.67 14,000
5 and over 1,458.33 17,500
5.2 Form of Payment. The Supplemental Retirement Benefit
shall be paid in the basic form provided below unless the
Participant elects in the calendar year prior to retirement or
termination an Actuarial Equivalent form of benefit provided in
this section. Participants elected to the Board prior to
November 30, 1994, may elect a grandfathered form of benefit as
provided in Section 5.4 in lieu of any other form of benefit.
(a) Normal Form of Benefit Payment. The normal form
of payment shall be a single-life annuity for the lifetime of the
Participant.
(b) Actuarial Equivalent Forms of Benefit.
(i) A joint and survivor annuity with payments
continued to the survivor at an amount equal to two-thirds (2/3)
of the Participant's benefits.
(ii) A joint and survivor annuity with payments
continued to the survivor at an amount equal to the Participant's
benefits.
5.3 Commencement of Benefit Payment.
(a) Outside Directors. The Supplemental Retirement
Benefit shall be paid to an outside director Participant
commencing on the tenth (10th) day of the month immediately
following the later of age sixty-five (65) or severance from
service on the Board as an outside director.
(b) Inside Directors. The Supplemental Retirement
Benefit shall be paid to an inside director Participant
commencing on the tenth (10th) day of the month immediately
following severance from service on the Board.
5.4 Grandfathered Form of Benefit. A Participant first
elected to the Board prior to November 30, 1994, may elect a
grandfathered form of benefit. This grandfathered form of
benefit shall be paid in 180 equal monthly installments in an
amount set forth in Section 5.1. The election shall be made
prior to the Participant's termination.
ARTICLE VI
BENEFICIARY DESIGNATION
6.1 Beneficiary Designation. The Primary Beneficiary shall
be the Participant's spouse. Each Participant, in the event the
Participant's spouse predeceases the Participant or if the
Participant is unmarried, shall have the right, at any time, to
designate any person or persons as Beneficiary or Beneficiaries
(both principal as well as contingent) to whom payment under this
Plan shall be made in the event of death prior to complete
distribution to Participant of the benefits due Participant under
the Plan.
6.2 Amendments, Marital Status, No Participant Designation.
Any Beneficiary designation form may be changed by a Participant
by the filing of a written form prescribed by the Administrative
Committee. The filing of a new Beneficiary designation form will
cancel all Beneficiary designations previously filed. Any
finalized divorce or marriage (other than common law) of a
Participant subsequent to the date of filing of a Beneficiary
designation form shall automatically revoke the prior
designation. If a Participant fails to designate a Beneficiary
as provided above, or if the Beneficiary designation is revoked
by marriage or divorce, without execution of a new designation,
or if all designated Beneficiaries predecease the Participant or
die prior to complete distribution of the Participant's benefits,
then Participant's designated Beneficiary shall be deemed to be
the person or persons surviving the Participant in the first of
the following classes in which there is a survivor, share and
share alike:
(a) the Participant's surviving spouse;
(b) the Participant's children, except that if any of
the children predecease the Participant but leaves issue
surviving, the issue shall take by right of representation;
(c) the Participant's personal representative
(executor or administrator).
6.3 Effect of Payment. The payment to the Beneficiary
shall completely discharge Employer's obligations under this
Plan.
ARTICLE VII
TERMINATION, SUSPENSION OR AMENDMENT OF PLAN
7.1 Termination, Suspension or Amendment of Plan. The
Board may, in its sole discretion, terminate or suspend this Plan
at any time or from time to time, in whole or in part. Either
the Board or the Administrative Committee may amend this Plan at
any time or from time to time. Any amendment may provide
different benefits or amounts of benefits from those herein set
forth. However, no such termination, suspension or amendment
shall adversely affect the benefits of Participants vested
therein prior to such action, the benefits of any Participant who
has retired, or the Beneficiary of any Participant who has died.
7.2 Change in Control. Notwithstanding Section 7.1 above,
during a Change in Control Period, neither the Board nor the
Administrative Committee may terminate this Plan with regard to
accrued benefits of current Participants. No amendment may be
made to the Plan during a Change in Control Period which would
adversely affect the accrued benefits of current Participants,
the benefits of any Participant who has retired, or the
Beneficiary of any Participant who has died. The Plan shall
continue to operate and be effective with regard to all current
or retired Participants and their Beneficiaries during any Change
in Control Period.
ARTICLE VIII
ADMINISTRATION
8.1 Administrative Committee; Duties. This Plan shall be
administered by an Administrative Committee which shall consist
of not less than three (3) nor more than five (5) persons
appointed by the Compensation Committee. Members of the
Administrative Committee may be Participants under this Plan.
The Administrative Committee shall have the authority to make,
amend, interpret and enforce all appropriate rules and
regulations for the administration of this Plan and decide or
resolve any and all questions including interpretations of this
Plan, as may arise in connection with the Plan. A majority vote
of the Administrative Committee members shall control any
decision.
In the administration of this Plan, the Administrative
Committee may, from time to time, employ agents and delegate to
them such administrative duties as it sees fit and may from time
to time consult with counsel who may be counsel to the Employer.
Subject to Article IX, the decision or action of the
Administrative Committee in respect of any questions arising out
of, or in connection with, the administration, interpretation and
application of the Plan and the rules and regulations promulgated
hereunder shall be final and conclusive and binding upon all
persons having any interest in the Plan.
8.2 Indemnity of Administrative Committee. To the extent
permitted by applicable law, the Employer shall indemnify, hold
harmless and defend the Administrative Committee against any and
all claims, loss, damage, expense or liability arising from any
action or failure to act with respect to this Plan, provided that
the Administrative Committee was acting in accordance with the
applicable standard of care. The indemnity provisions set forth
in this Article shall not be deemed to restrict or diminish in
any way any other indemnity available to the Administrative
Committee members in accordance with the Article or By-laws of
the Company.
ARTICLE IX
CLAIMS PROCEDURE
9.1 Claim. Any person claiming a benefit, requesting an
interpretation or ruling under the Plan, or requesting
information under the Plan shall present the request in writing
to the Administrative Committee which shall respond in writing as
soon as practicable.
9.2 Denial of Claim. If the claim or request is denied,
the written notice of denial shall state:
(a) the reason for denial, with specific reference to
the Plan provisions on which the denial is based;
(b) a description of any additional material or
information required and an explanation of why it is necessary;
and
(c) an explanation of the Plan's claim review
procedure.
9.3 Review of Claim. Any person whose claim or request is
denied or who has not received a response within thirty (30) days
may request review by notice given in writing to the
Administrative Committee. The claim or request shall be reviewed
by the Administrative Committee who may, but shall not be
required to, grant the claimant a hearing. On review, the
claimant may have representation, examine pertinent documents,
and submit issues and comments in writing.
9.4 Final Decision. The decision on review shall normally
be made within sixty (60) days. If an extension of time is
required for a hearing or other special circumstances, the
claimant shall be notified, and the time limit shall be one
hundred twenty (120) days. The decision shall be in writing and
shall state the reason and the relevant Plan provisions. All
decisions on review shall be final and bind all parties
concerned.
ARTICLE X
MISCELLANEOUS
10.1 Unfunded Plan. This Plan is intended to be an unfunded
plan maintained primarily to provide deferred compensation
benefits for a select group of "management or highly compensated
employees" within the meaning of Sections 201, 301 and 401 of the
Employee Retirement Income Security Act of 1974, as amended
("ERISA"), and therefore to be exempt from the provisions of
Parts 2, 3 and 4 of Title I of ERISA.
10.2 Unsecured General Creditor. Participants and their
Beneficiaries, heirs, successors and assigns shall have no legal
or equitable rights, interest or claims in any property or asset
of the Employer, nor shall they be Beneficiaries of, or have any
rights, claims or interests in any life insurance policies,
annuity contracts or the proceeds therefrom owned or which may be
acquired by the Employer. Except as may be provided in
Section 10.3, such policies, annuity contracts or other assets of
the Employer shall not be held under any trust for the benefit of
Participants, their Beneficiaries, heirs, successors or assigns,
or held in any way as collateral security for the fulfilling of
the obligation of the Employer under this Plan. Any and all of
the Employer's assets and policies shall be, and remain, the
general, unpledged, unrestricted assets of the Employer. The
Employer's obligation under the Plan shall be that of an unfunded
and unsecured promise to pay money in the future.
10.3 Trust Fund. The Employer shall be responsible for the
payment of all benefits provided under the Plan. At its
discretion, the Employer may establish one or more trusts, with
such trustees as the Board may approve, for the purpose of
providing for the payment of such benefits. Such trust or trusts
may be irrevocable, but the assets thereof shall be subject to
the claims of the Employer's creditors. To the extent any
benefits provided under the Plan are actually paid from any such
trust, the Employer shall have no further obligation with respect
thereto, but to the extent not so paid, such benefits shall
remain the obligation of, and shall be paid by, the Employer.
10.4 Nonassignability. Neither a Participant nor any other
person shall have any right to commute, sell, assign, transfer,
pledge, anticipate, mortgage or otherwise encumber, transfer,
hypothecate or convey in advance of actual receipt the amounts,
if any, payable hereunder, or any part thereof, which are, and
all rights to which are, expressly declared to be unassignable
and nontransferable. No part of the amount payable shall, prior
to actual payment, be subject to seizure or sequestration for the
payment of any debts, judgments, alimony or separate maintenance
owed by a Participant or any other person, nor be transferable by
operation of law in the event of Participant's or any other
person's bankruptcy or insolvency.
10.5 Governing Law. The provisions of this Plan shall be
construed, interpreted and governed in all respects in accordance
with the applicable federal law and, to the extent not preempted
by such federal law, in accordance with the laws of the State of
Idaho without regard to the principles of conflicts of laws.
10.6 Validity. If any provision of this Plan shall be held
illegal or invalid for any reason, the remaining provisions shall
nevertheless continue in full force and effect without being
impaired or invalidated in any way.
10.7 Notice. Any notice or filing required or permitted to
be given under the Plan shall be sufficient if in writing and
hand delivered, or sent by registered or certified mail or fax.
The notice shall be deemed given as of the date of delivery or,
if delivery is made by mail, as of the date shown on the postmark
on the receipt for registration or certification.
10.8 Successors. Subject to Section 7.1, the provisions of
the Plan shall bind and inure to the benefit of the Employer and
its successors and assigns. The term successors as used herein
shall include any corporation or other business entity which
shall, whether by merger, consolidation, purchase or otherwise
acquire all or substantially all of the business and assets of
the Employer, and successors of any such corporation or other
business entity.
10.9 Payment to Guardian. If a Plan benefit is payable to a
minor or a person declared incompetent or to a person incapable
of handling the disposition of property, the Administrative
Committee may direct payment of such Plan benefit to the
guardian, legal representative or person having the care and
custody of the minor, incompetent or person. The Administrative
Committee may require proof of incompetency, minority, incapacity
or guardianship, as it may deem appropriate, prior to
distribution of the Plan benefit. The distribution shall
completely discharge the Administrative Committee and the
Employer from all liability with respect to such benefit.
10.10 Accelerated Distribution. Notwithstanding any
other provision of the Plan, a Participant shall be entitled to
receive, upon written request to the Administrative Committee, a
lump sum distribution equal to ninety percent (90%) of the
Actuarial Equivalent vested accrued Security Plan Retirement
Benefit, as of the date thirty (30) days after notice is given to
the Administrative Committee. The remaining balance of ten
percent (10%) shall be forfeited by the Participant. The amount
payable under this section shall be paid in a lump sum with ten
(10) days following the thirty (30) day period outlined above.
If a Participant requests and obtains an accelerated distribution
under this Section 10.10 and remains a director of the Company,
participation will cease and therewill be no future benefit
accruals under this Plan. Following the death of a Participant,
the Beneficiary may, at any time, request an accelerated
distribution under this section. If the deceased Participant
named multiple Beneficiaries, then all named Beneficiaries must
consent to the request for an accelerated distribution. The
benefit payable to the Beneficiary shall be equal to ninety
percent (90%) of the Actuarial Equivalent of the Security Plan
Retirement Benefit payable to the Beneficiary. Payment of an
accelerated distribution pursuant to this Section 10.10 shall
completely discharge the Employer's obligation to the Participant
and any Beneficiaries under this Plan.
IDAHO POWER COMPANY
By: _________________________
Chairman
Dated:_________________________
APPENDIX A
CONTRACT OF PARTICIPATION IN THE
IDAHO POWER COMPANY SECURITY PLAN
FOR BOARD OF DIRECTORS
NAME OF PARTICIPANT:
DATE OF BIRTH:
SECURITY PLAN ENTRY DATE:
BENEFICIARY:
This Agreement is made and entered into as of the date written
hereinbelow by and between Idaho Power Company and ____________.
This Agreement is subject to all of the terms of the Idaho Power
Company Security Plan for Board of Directors, as amended and restated
November 30, 1994 (The "Plan"). By signing this agreement,
Participant acknowledges receipt of a copy of the Plan document.
PARTICIPANT IDAHO POWER COMPANY
BY BY
PARTICIPANT CHAIRMAN
DATE DATE
<TABLE>
<CAPTION>
Exhibit 12
Idaho Power Company
Consolidated Financial Information
Ratio of Earnings to Fixed Charges
Twelve Months Ended December 31,
(Thousands of Dollars)
1991 1992 1993 1994 1995 1996
<S> <C> <C> <C> <C> <C> <C>
Computation of Ratio of Earnings to
Fixed Charges:
Consolidated net income $ 57,872 $ 59,990 $ 84,464 $ 74,930 $ 86,921 $ 90,618
Income taxes:
Income taxes (includes amounts charged
to other income and deductions) 24,321 24,601 38,057 35,307 49,498 51,316
Investment tax credit adjustment (3,177) (1,439) (1,583) (1,064) (1,086) 776
Total income taxes 21,144 23,162 36,474 34,243 48,412 52,092
Income before income taxes 79,016 83,152 120,938 109,173 135,333 142,710
Fixed Charges:
Interest on long-term debt 54,370 53,408 53,706 51,172 51,147 52,165
Amortization of debt discount,
expense and premium - net 374 392 507 567 567 594
Interest on short-term bank loans 935 647 220 1,157 3,144 2,269
Other interest 3,297 1,011 2,023 1,538 1,598 2,319
Interest portion of rentals 884 683 1,077 794 925 991
Total fixed charges 59,860 56,141 57,533 55,228 57,381 58,338
Earnings - as defined $138,876 $139,293 $178,471 $164,401 $192,714 $201,048
Ratio of earnings to fixed charges 2.32X 2.48X 3.10X 2.98X 3.36X 3.45X
</TABLE>
<TABLE>
<CAPTION>
Exhibit 12(a)
Idaho Power Company
Consolidated Financial Information
Supplemental Ratio of Earnings to Fixed Charges
Twelve Months Ended December 31,
(Thousands of Dollars)
1991 1992 1993 1994 1995 1996
<S> <C> <C> <C> <C> <C> <C>
Computation of Ratio of Earnings to
Fixed Charges:
Consolidated net income $ 57,872 $ 59,990 $ 84,464 $ 74,930 $ 86,921 $ 90,618
Income taxes:
Income taxes (includes amounts charged
to other income and deductions) 24,321 24,601 38,057 35,307 49,498 51,316
Investment tax credit adjustment (3,177) (1,439) (1,583) (1,064) (1,086) 776
Total income taxes 21,144 23,162 36,474 34,243 48,412 52,092
Income before income taxes 79,016 83,152 120,938 109,173 135,333 142,710
Fixed Charges:
Interest on long-term debt 54,370 53,408 53,706 51,172 51,147 52,165
Amortization of debt discount,
expense and premium - net 374 392 507 567 567 594
Interest on short-term bank loans 935 647 220 1,157 3,144 2,269
Other interest 3,297 1,011 2,023 1,538 1,598 2,319
Interest portion of rentals 884 683 1,077 794 925 991
Total fixed charges 59,860 56,141 57,533 55,228 57,381 58,338
Suppl increment to fixed charges* 1,599 2,487 2,631 2,622 2,611 2,600
Total supplemental fixed charges 61,459 58,628 60,164 57,850 59,992 60,938
Supplemental earnings - as defined $140,475 $141,780 $181,102 $167,023 $195,325 $203,648
Supplemental ratio of earnings to fixed
charges 2.29X 2.42X 3.01X 2.89X 3.26X 3.34X
<F1>
* Explanation of increment:
Interest on the guaranty of American Falls Reservoir District Bonds and Milner Dam Inc.
notes which are already included in operating expense.
</TABLE>
<TABLE>
<CAPTION>
Exhibit 12(b)
Idaho Power Company
Consolidated Financial Information
Ratio of Earnings to Combined Fixed Charges and Preferred Dividend Requirements
Twelve Months Ended December 31,
(Thousands of Dollars)
1991 1992 1993 1994 1995 1996
<S> <C> <C> <C> <C> <C> <C>
Computation of Ratio of Earnings to
Fixed Charges:
Consolidated net income $ 57,872 $ 59,990 $ 84,464 $ 74,930 $ 86,921 $ 90,618
Income taxes:
Income taxes (includes amounts charged
to other income and deductions) 24,321 24,601 38,057 35,307 49,498 51,316
Investment tax credit adjustment (3,177) (1,439) (1,583) (1,064) (1,086) 776
Total income taxes 21,144 23,162 36,474 34,243 48,412 52,092
Income before income taxes 79,016 83,152 120,938 109,173 135,333 142,710
Fixed Charges:
Interest on long-term debt 54,370 53,408 53,706 51,172 51,147 52,165
Amortization of debt discount,
expense and premium - net 374 392 507 567 567 594
Interest on short-term bank loans 935 647 220 1,157 3,144 2,269
Other interest 3,297 1,011 2,023 1,538 1,598 2,319
Interest portion of rentals 884 683 1,077 794 925 991
Total fixed charges 59,860 56,141 57,533 55,228 57,381 58,338
Preferred dividends requirements 6,663 7,611 8,547 10,682 12,392 12,146
Total fixed charges and
preferred dividends 66,523 63,752 66,080 65,910 69,773 70,484
Earnings - as defined $138,876 $139,293 $178,471 $164,401 $192,714 $201,048
Ratio of earnings to fixed charges and
preferred dividends 2.09X 2.18X 2.70X 2.49X 2.76X 2.85X
</TABLE>
<TABLE>
<CAPTION>
Exhibit 12(c)
Idaho Power Company
Consolidated Financial Information
Supplemental Ratio of Earnings to Combined Fixed Charges and Preferred Dividend
Requirements
Twelve Months Ended December 31,
(Thousands of Dollars)
1991 1992 1993 1994 1995 1996
<S> <C> <C> <C> <C> <C> <C>
Computation of Ratio of Earnings to
Fixed Charges:
Consolidated net income $ 57,872 $ 59,990 $ 84,464 $ 74,930 $ 86,921 $ 90,618
Income taxes:
Income taxes (includes amounts charged
to other income and deductions) 24,321 24,601 38,057 35,307 49,498 51,316
Investment tax credit adjustment (3,177) (1,439) (1,583) (1,064) (1,086) 776
Total income taxes 21,144 23,162 36,474 34,243 48,412 52,092
Income before income taxes 79,016 83,152 120,938 109,173 135,333 142,710
Fixed Charges:
Interest on long-term debt 54,370 53,408 53,706 51,172 51,147 52,165
Amortization of debt discount,
expense and premium - net 374 392 507 567 567 594
Interest on short-term bank loans 935 647 220 1,157 3,144 2,269
Other interest 3,297 1,011 2,023 1,538 1,598 2,319
Interest portion of rentals 884 683 1,077 794 925 991
Total fixed charges 59,860 56,141 57,533 55,228 57,381 58,338
Suppl increment to fixed charges* 1,599 2,487 2,631 2,622 2,611 2,600
Supplemental fixed charges 61,459 58,628 60,164 57,850 59,992 60,938
Preferred dividend requirements 6,663 7,611 8,547 10,682 12,392 12,146
Total supplemental fixed charges
and preferred dividends 68,122 66,239 68,711 68,532 72,384 73,084
Supplemental earnings - as defined $140,475 $141,780 $181,102 $167,023 $195,325 $203,648
Supplemental ratio of earnings to fixed
charges and preferred dividends 2.06X 2.14X 2.64X 2.44X 2.70X 2.79X
<F2>
* Explanation of increment:
Interest on the guaranty of American Falls Reservoir District Bonds
and Milner Dam Inc. Notes which are already included in operating expense.
</TABLE>
EXHIBIT 21
SUBSIDIARIES OF REGISTRANT
1. Idaho Energy Resources Co., a Wyoming Corporation
2. Idaho Utility Products Company, an Idaho Corporation
3. IDACORP, Inc., an Idaho Corporation
4. Ida-West Energy Company, an Idaho Corporation
5. Stellar Dynamics Inc., an Idaho Corporation
6. Idaho Power Resources Corporation, an Idaho Corporation
EXHIBIT 23
INDEPENDENT AUDITORS' CONSENT
We consent to the incorporation by reference in
Registration Statement Nos. 33-51215, and 333-00139
of Idaho Power Company on Form S-3 and Registration
Statement No. 33-56071 of Idaho Power Company on
Form S-8 of our report dated January 31, 1997
appearing in the Annual Report on Form 10-K of Idaho
Power Company for the year ended December 31, 1996.
DELOITTE & TOUCHE LLP
Portland, Oregon
March 14, 1997
<TABLE> <S> <C>
<ARTICLE> UT
<LEGEND>
This schedule contains summary financial information extracted from balance
sheets, income statements and cash flow statements and is qualified in its
entirety by reference to such financial statements.
</LEGEND>
<MULTIPLIER> 1,000
<S> <C>
<PERIOD-TYPE> 12-MOS
<FISCAL-YEAR-END> DEC-31-1996
<PERIOD-END> DEC-31-1996
<BOOK-VALUE> PER-BOOK
<TOTAL-NET-UTILITY-PLANT> 1,694,631
<OTHER-PROPERTY-AND-INVEST> 36,502
<TOTAL-CURRENT-ASSETS> 144,116
<TOTAL-DEFERRED-CHARGES> 420,088
<OTHER-ASSETS> 0
<TOTAL-ASSETS> 2,295,337
<COMMON> 94,031
<CAPITAL-SURPLUS-PAID-IN> 358,455
<RETAINED-EARNINGS> 242,088
<TOTAL-COMMON-STOCKHOLDERS-EQ> 694,574
0
106,975
<LONG-TERM-DEBT-NET> 716,218
<SHORT-TERM-NOTES> 0
<LONG-TERM-NOTES-PAYABLE> 22,332
<COMMERCIAL-PAPER-OBLIGATIONS> 54,016
<LONG-TERM-DEBT-CURRENT-PORT> 71
0
<CAPITAL-LEASE-OBLIGATIONS> 0
<LEASES-CURRENT> 0
<OTHER-ITEMS-CAPITAL-AND-LIAB> 701,151
<TOT-CAPITALIZATION-AND-LIAB> 2,295,337
<GROSS-OPERATING-REVENUE> 578,445
<INCOME-TAX-EXPENSE> 52,092
<OTHER-OPERATING-EXPENSES> 391,274
<TOTAL-OPERATING-EXPENSES> 443,366
<OPERATING-INCOME-LOSS> 135,079
<OTHER-INCOME-NET> 12,534
<INCOME-BEFORE-INTEREST-EXPEN> 147,613
<TOTAL-INTEREST-EXPENSE> 56,995
<NET-INCOME> 90,618
7,463
<EARNINGS-AVAILABLE-FOR-COMM> 83,155
<COMMON-STOCK-DIVIDENDS> 69,924
<TOTAL-INTEREST-ON-BONDS> 52,165
<CASH-FLOW-OPERATIONS> 174,415
<EPS-PRIMARY> 2.21
<EPS-DILUTED> 2.21
</TABLE>
