TABLE OF CONTENTS
PART I
PAGE
ITEM 1. BUSINESS 2
THE COMPANY 2
POWER SUPPLY 4
FUEL 8
WATER RIGHTS 9
REGULATION 10
ENVIRONMENTAL REGULATION 10
RATES 12
CONSTRUCTION PROGRAM 13
FINANCING PROGRAM 14
ITEM 2. PROPERTIES 15
ITEM 3. LEGAL PROCEEDINGS 17
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS 19
EXECUTIVE OFFICERS OF THE REGISTRANT 19
PART II
ITEM 5. MARKET FOR THE REGISTRANT'S COMMON STOCK AND RELATED
STOCKHOLDER MATTERS 21
ITEM 6. SELECTED FINANCIAL DATA 22
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS 24
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA 36
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON
ACCOUNTING AND FINANCIAL DISCLOSURE 59
PART III
ITEM 10.DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT* 59
ITEM 11.EXECUTIVE COMPENSATION* 59
ITEM 12.SECURITY OWNERSHIP OF CERTAIN BENEFICIAL
OWNERS AND MANAGEMENT* 59
ITEM 13.CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS* 59
PART IV
ITEM 14.EXHIBITS, FINANCIAL STATEMENT SCHEDULE AND REPORTS ON
FORM 8-K 59
SIGNATURES 66
*INCORPORATED BY REFERENCE.
UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-K
(Mark One)
X ANNUAL REPORT PURSUANT TO SECTION 13 OR 15 (d) OF
THE SECURITIES
EXCHANGE ACT OF 1934
For the fiscal year ended December 31, 1997
OR
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES
EXCHANGE ACT OF 1934
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.
Aggregate market value of voting and non-voting common stock
held by nonaffiliates (January 31, 1998) $1,331,222,000
Number of shares of common stock outstanding at February 28, 1998
37,612,351
Documents Incorporated by Reference:
Part III, Item 10 Portions of the joint definitive proxy
statement and prospectus of the Registrant and IDACORP.
Item 11 Inc. to be filed pursuant to Regulation 14A for the
1998 Annual Meeting of Shareowners to be Item 12 held
on May 6, 1998.
Item 12
Item 13
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 772,000. The Company
holds franchises in approximately 70 cities in Idaho and ten
cities in Oregon, and holds certificates from the respective
public utility regulatory authorities to serve all or a portion
of 28 counties in Idaho, three counties in Oregon and one county
in Nevada. As of December 31, 1997, the Company supplied
electric energy to 363,085 general business customers and
employed 1,707 people in its operations (1,615 full-time).
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 in 1993, 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.
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 Wyoming,
Oregon and Nevada using low-sulfur coal from Wyoming and Utah.
For the twelve months ended December 31, 1997, total system
electric revenues from residential customers accounted for 27
percent of the Company's total operating revenues. Commercial
customers with less than 1,000 kiloWatt (kW) demand accounted for
15 percent, industrial customers with 1,000 kW demand and over
accounted for 15 percent and irrigation customers accounted for 8
percent. Off-system and interchange arrangements accounted for
32 percent and other operating revenues accounted for 3 percent.
The Company's principal commercial and industrial customers are
involved in: elemental phosphorus production; food processing;
phosphate fertilizer production; electronics and general
manufacturing; lumber; beet sugar refining; and the recreation
industry, such as lodges, condominiums, ski lifts and related
facilities, including those at the Sun Valley resort area.
The off-system revenue percentage increased in 1997 due primarily
to increases in electricity trading activity. The Company's firm
energy demand, hydroelectric generating conditions and market
conditions throughout the West also affect the volume and price
of off-system sales.
The Company intends to be a competitive energy provider,
including both electricity and natural gas. In 1997, the Company
opened gas trading offices in Houston, Texas to serve the
southern and eastern United States and Boise, Idaho to serve the
northwest and Canadian markets. The Company has also
significantly increased its participation in the wholesale
electricity markets.
Subsidiaries -
Ida-West Energy Company (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 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.
Ida-West has a partnership 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 the five Idaho
hydroelectric entities that are fifty percent owned by Ida-West,
totaling approximately $9.8 million in 1997. At December 31,
1997, the Company's total investment in Ida-West was $23.8
million.
Idaho Energy Resources Company (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, 1997, the Company's
total investment in IERCo was $5.1 million.
IDACORP, Inc. (IDACORP), was organized in 1986 to pursue a non-
regulated diversification program. At the end of 1997 IDACORP
was participating in eight affordable housing programs which
provide a return primarily by reducing federal income taxes
through tax credits and tax depreciation benefits. As of
December 31, 1997, the Company's total investment in IDACORP was
$12.0 million. This subsidiary's name will be changed to IDACORP
Financial Services, Inc. in 1998.
Stellar Dynamics, Inc (Stellar) was formed in 1995 to
commercialize the Company's expertise in control technology for
electric substations and power plants. Currently, Stellar's
market focus is in complex control and automation systems for the
electric utility sector and industrial applications. Stellar
also provides design and engineering for complete electric
substations. Stellar markets its products nationally and
internationally. As of December 31, 1997, the Company's total
investment in Stellar was $1.4 million.
Applied Power Corporation (APC) is a Lacey, Washington based
company that designs, supplies and distributes photovoltaic (PV)
systems. APC provides reliable, cost-effective solar electric
products and systems for industry, contractors, utilities,
government and an international network of solar dealers and
distributors. Idaho Power Resources Company acquired a majority
interest in APC in 1996. During 1997, this investment became a
direct subsidiary of Idaho Power Company. As of December 31,
1997, the Company's total investment in APC was $4.0 million.
Research and Development and Renewable Energy Sources -
During 1997, the Company spent approximately $1.6 million on
research and development of which $1.4 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 subjects of EPRI projects
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 has
contributed $630,500 through 1997 and the EPRI contributed 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 receives by participating
in this project is valuable experience and knowledge in solar
plant design, construction and operation.
Energy Efficiency -
As an active member of the Northwest Energy Efficiency Alliance,
the Company has been shifting the focus of its conservation, or
demand-side management (DSM), activities towards regional market
transformation efforts and renewing its commitment to public
purpose programs. At the same time, the Company has discontinued
many of the traditional DSM programs that required deferral of
costs. In 1997, the Company expended $3.2 million on 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 1995, 1996,
and 1997 the Company's service territory experienced above
average water years. The system peak demand for 1997 was 2,547
MW set on July 8, 1997. Peak demand for 1996 and 1995 were 2,661
and 2,393 MW respectively.
Historically, under normal water conditions, the Company's hydro
system supplies approximately 57 percent, thermal generation
accounts for 32 percent and purchased power and other
interchanges contribute the remaining 11 percent of total system
requirements. In 1997, hydrogeneration was 58 percent, thermal
was 26 percent and purchased power and interchange was 15 percent
of total system requirements. Preliminary 1998 reports indicate
the mountain snowpack is near normal for this time of year, the
carryover reservoir storage throughout the Snake River Basin is
above average, and precipitation for 1998 to date is above
normal. The Company expects to meet projected energy loads
during the coming year using its hydro and coal-fired facilities
and strategic geographic location - which provides opportunities
to purchase, sell, exchange and transmit energy.
Purchased power expenses have increased for the last two years
due primarily to increases in MWH's purchased in the electricity
trading markets for the purpose of remarketing this energy to
others. Increased purchases from cogeneration and small power
production (CSPP) projects as a result of favorable hydro
conditions also increased purchased power expenses for the three
year period.
The Company periodically updates its load and resource
projections and now expects total Company system energy
requirements over the next five years to grow at an annual rate
of approximately 2.0 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 on
both a wholesale and retail level. The National Energy Policy
Act of 1992, FERC rulemakings, state initiatives, customer
demands, and pending legislation at the national and state level
all indicate increasing wholesale and potential retail
competition. The Company's goal is to anticipate and fully
integrate into Company operations any legislative, regulatory or
competitive changes. It is pursuing a rapid, but orderly
transition to at least a partially and possibly a totally
deregulated environment in the years ahead. With its low energy
production costs the Company is well-positioned to succeed in a
more competitive environment and is taking steps to preserve its
low-cost 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 traditional service
territory. A requirement to transmit directly to retail
customers would permit retail customers to purchase electric
capacity and energy from their local electric utility or from any
other electric utility or independent power supplier. The Idaho
Public Utilities Commission (IPUC) conducted an issues workshop
for discussing retail wheeling issues among affected parties in
1996. Following the 1997 session, the Idaho Legislature
established an Interim Committee on Restructuring. The Committee
met periodically throughout 1997 and is the legislative committee
responsible for legislation related to restructuring of the
electric utility industry.
In response to increased competition in the industry, the
potential ability of retail customers to choose their electric
provider, and the apparent restructuring 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 when 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.
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 environment, the Company formed a
Marketing Business Unit in January 1997. The new business unit
is responsible for all purchases and wholesale sales of
electricity and natural gas in the wholesale energy markets,
market research, and 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 services.
During 1997, the Marketing Business Unit expanded electricity
sales and trading operations in Boise, Idaho, and established gas
trading operations in Boise, Idaho, and Houston, Texas. The
business unit is responsible for pursuing the corporate strategy
of expanding business outside the Company's traditional service
area and during 1997 signed wholesale energy and service
contracts with publicly- or cooperatively-owned utilities in
Arizona, California, Nevada, Washington and Idaho.
On February 17, 1998, the Company announced it had joined the
Allied Utility Network (AUN), a member-supported alliance that
provides customer research, marketing and other support services
to utilities. Through its relationship with AUN, the Company
will initially develop the capability to offer retail customers
new products and services. Other members of the alliance include
Colorado Springs Utilities of Colorado Springs, Colo., Omaha
Public Power District of Omaha, Neb. and Cobb Electric Membership
Corporation of Atlanta, Ga. Collectively, the utilities serve
approximately one million customers.
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.
With changing market conditions, the Company is actively talking
to customers and continues to evaluate the economic viability of
the proposed line. The final development of SWIP may be impacted
by regional efforts to form an Independent Grid 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.
On April 24, 1996, the FERC issued Order Nos. 888 and 889 dealing
with Open-Access Non-Discriminatory Transmission Services by
Public and Transmitting Utilities, and standards of conduct
regarding these practices. 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.
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.
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 help
facilitate transmission access and planning throughout the power
system.
Independent Grid Operator -
A group of twenty one Northwest and Rocky Mountain electric
utilities, including Idaho Power had been working to create an
independent transmission grid operator called "IndeGO". As
envisioned, IndeGO would ensure non-discriminatory, open-access
to electricity transmission facilities in compliance with recent
FERC rulings. In 1996, the utilities signed a memorandum of
understanding to investigate the feasibility of developing a
regional transmission grid which would be operated by an entity
independent of power market interests. As initially studied,
IndeGO could control substantially all of the transmission
facilities in eight western states.
In November 1997, the group released a complete package of draft
legal agreements and descriptive materials for formal public
review with the intention of making a filing with FERC in 1998.
However, due to concerns with timing, costs and the status of
restructuring in Idaho, the Company has stated that it cannot
support an IndeGO filing with FERC at this time and as currently
structured. Subsequently, on March 4, 1998, seven Northwest
investor owned utilities, including the Company, issued a joint
statement concluding that it is not productive to devote further
effort to IndeGO development at this time because of critical
questions about electric restructuring and Bonneville Power
Administration participation.
Forecast Energy and Peak Demand -
The following table shows how the Company expects to meet its
forecast peak demand requirements through 2002 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 an extended
contract that expires in 2000 and with Seattle City Light under
an extended contract that expires in 2003.
Summer Peak Capability (MW) (a)
1998 1999 2000 2001 2002
Generation capability 2,681 2,681 2,681 2,681 2,681
Less net peak load 2,593 2,650 2,704 2,751 2,803
Plus contract power 313 313 313 313 313
(b)
Peak capability 401 344 290 243 191
margin
Percent capability 15% 13% 11% 9% 7%
margin (c)
(a) Based upon median hydro conditions.
(b) Sum of exchange and CSPP contracts.
(c) Capability margin divided by the net peak
load.
During the 1998-2002 period, the Company plans to provide all the
energy required to serve its firm load requirements by using 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 Public Utilities Regulatory
Policy Act of 1978 (PURPA) and the adoption of avoided cost
standards by the IPUC, the Company has entered into contracts for
the purchase of energy from private developers. Because the
Company's service territory encompasses substantial irrigation
canal development, forest products production facilities,
mountain streams, and food processing facilities, considerable
amounts of energy are available from these sources. Such energy
comes from hydro power producers who own and operate small plants
and from cogenerators converting waste heat or steam from
industrial processes into electricity. The estimated annualized
cost for the 67 CSPP projects on-line as of December 31, 1997 is
$58.0 million. During 1997, the Company purchased 935.3 million
kilowatt-hours of power from these private developers at a
blended price of 6.0 cents per kilowatt-hour.
With the potential deregulation of the power supply function 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 less than one MW. In addition, the IPUC
determined that negotiated rates for future CSPP projects larger
than one MW should be tied more closely to values determined in
the Company's integrated resource planning process. In
subsequent orders issued on September 4, 1996 and August 28,
1997, the IPUC further recognized the coming changes by limiting
the length of new contracts to a maximum of five years (see
"Rates").
Wholesale Power Sales -
The Company has firm wholesale power sales contracts with several
entities. These contracts are for various amounts of energy,
ranging from 6 to 75 average megawatts, and are of various
lengths expiring between 1998 and 2009. The Company is actively
participating in the electricity trading markets and as a result,
has increased significantly the number of counterparties with
which wholesale sales are being transacted. 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 supplying 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 Canyon Fuel Co., LLC, 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 300,000 tons per
year to a maximum of 1,000,000 tons per year. This flexibility
will accommodate fluctuations in energy demands, hydroelectric
generating conditions and purchases of energy from CSPP
facilities.
WATER RIGHTS
Except as discussed below, the Company has acquired valid water
rights under applicable 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 Utility
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 related FERC regulations. These conditions
and regulations include 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. With respect to project
property located in Oregon, these facilities are subject to 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 present environmental laws and regulations, the
Company estimates its capital expenditures (excluding allowance
for funds used during construction) for environmental matters for
1998 and during the period 1999-2002 will total approximately
$5.7 million and $31.6 million, respectively. Mitigation of
environmental concerns due to relicensing of hydro facilities
will be a major portion of these expenditures. The Company
anticipates incurring approximately $23 million annually of
operating expenses for environmental facilities during the period
1998-2002, based upon present environmental laws and regulation.
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 foresees no material
adverse effects upon its operations with regard to SO2 emissions.
On July 16, 1997, the EPA announced new National Ambient Air Quality
Standards for ozone and Particulate Matter (PM). In addition to these
standards, on July 17, 1997, the EPA proposed regional haze regulations
for protection of visibility in national parks and wilderness areas.
Impacts of the ozone and PM regulations and the proposed regional haze
regulations on the Company's thermal operations are unknown at this time.
Although not presently required to meet any federal nitrogen oxide (NOx)
limits, North Valmy, Boardman, and Jim Bridger Unit 4 elected to meet
Phase I NOx limits beginning in 1998. As a result of this voluntary
"early election" these units will not be required to meet the more
restrictive Phase II NOx limits until 2008. Had the units not voluntarily
"early elected", they would have been required to meet the Phase II NOx
limits beginning in 2000.
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.
The Company has agreed to meet certain dissolved oxygen standards
at its American Falls hydroelectric generating plant. 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 downstream from the Company's plant during the
May 15 to October 15 period each year.
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. At December 31, 1997, the investment in these facilities
was $12.2 million and the annual cost of operation pursuant to
FERC License 1971 was approximately $2.4 million annually.
Endangered Species -
Several species of salmon and Snake River mollusks living within
the Company's operating area are listed as threatened or
endangered. The Company continues to review and analyze the
effect such designation has on its operations. The Company is
cooperating with various governmental agencies to resolve issues
related to these species. (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 its 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 $0.4 million, $0.9 million and $1.0 million
for 1995, 1996 and 1997 respectively. The Company anticipates
that all of its generating facilities and substations, except for
capacitors, will be non-PCB by the end of 1998.
RATES
Idaho Jurisdiction
Since 1993 the Company has had a Power Cost Adjustment (PCA)
mechanism in place in its Idaho jurisdiction. The PCA provides
for annual adjustments to the rates charged to Idaho retail
customers. These adjustments are based on a comparison of
forecasted net power supply costs to power supply costs allowed
in the Company's base rates.
The 1997-1998 forecast assumed above-average hydroelectric
generating conditions. This resulted in forecasted power supply
costs and retail rates being lower than the base amounts
established in past regulatory proceedings. The Company's May
1997 PCA adjustment, combined with the revenue sharing mechanism
described below, decreased rates 0.63%. Revenue from Idaho
retail customers will be $20.2 million less than what would be
recovered if the Company was charging the base rates during this
rate period. The May 1996 PCA adjustment decreased Idaho
jurisdictional PCA rates 5.9%.
In the current rate period, actual power costs have exceeded the
forecast. The Company has recorded a regulatory asset of, and
decreased expenses by, $12.8 million as of December 31, 1997.
The variance that exists at the end of the current rate period
will be trued-up in the next annual PCA adjustment.
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 one 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 one 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. The settlement gives the Company time to pursue and
to implement its efficiency and growth initiatives with the
assurance of a reasonable level of financial performance without
the need to change customer prices.
Under the Settlement, which remains in effect through 1999, when
the Company's actual earnings in a given year exceed an 11.75
percent return on year-end common equity for the Idaho
jurisdiction, the Company will share 50 percent of the excess
with its Idaho retail customers. In 1997 the Company set aside
approximately $8.7 million for the benefit of its Idaho
customers. In 1996 the Company set aside approximately $4.9
million, $1.4 million of which was retained from refunding and
applied against the regulatory asset balance of Idaho demand-side
conservation management expenditures.
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 Company has received approval from
the Idaho State Tax Commission and the Internal Revenue Service
on the accounting treatment for the tax credits up to a maximum
of $30 million of ADITC's. As of December 31, 1997, no ADITCs
have been used under the regulatory agreement.
Other important points in the Settlement are that 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 that the Company agrees that its quality of
service will not decline as a result of corporate reorganization.
Other Jurisdictions -
In 1997, the Company did not file any applications for rate
relief before the FERC or in its Oregon or Nevada retail
jurisdictions. 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 1998-2002 period
(excluding allowances for funds used during construction) is
presently estimated to require cash funds of approximately $490.0
million as follows:
1998 1999-2002 (a)
(Millions of Dollars)
Generating Facilities:
Hydro $11.1 $71.0
Thermal 8.3 23.0
Total generating facilities 19.4 94.0
Transmission lines and 13.4 77.4
substations
Distribution lines and 44.1 176.2
substations
General 23.1 42.4
Total cash construction 100.0 390.0
AFUDC 1.0 8.1
Total construction $101.0 $398.1
including AFUDC (b)
(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 including: (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. The Company will pursue the projects that
best meet its future energy needs.
FINANCING PROGRAM
The Company's five-year estimate of capital requirements and
sources of capital is $484.9 million outlined as follows:
1998 1999-2002
(Millions of Dollars)
Capital Requirements:
Net cash construction $100.0 $390.0
expenditures
Conservation expenditures 3.0 3.1
Other cash expenditures .5 (11.7)
Total $103.5 $381.4
Sources of Capital:
Internal generation $87.8 $414.4
Short-term bank loans - Net (6.9) 13.6
First mortgage bonds 19.5 (45.7)
Debt repayment (0.1) (0.3)
Common stock - -
Cash investments (increase) 3.2 (0.6)
Total (a) $103.5 $381.4
(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, 1997, net earnings were 6.56
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, 1997,
the actual preferred dividend earnings coverage was 3.03 times.
If the dividends on the shares of Auction Preferred Stock were to
reach the maximum allowed, the preferred dividend earnings
coverage would be 2.78 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 4,644 miles of high
voltage transmission lines; 21 step-up transmission substations
located at power plants; 17 transmission substations; 7
transmission switching stations; and 200 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
Project Capacity kW Capacity kW Expiration
Properties Subject to
Federal Licenses:
Lower Salmon 70,000 60,000 1997(a)
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
Canyon
Swan Falls 25,547 25,000 2010
American Falls 112,420 92,340 2025
Cascade 14,000 12,420 2031
Milner 59,448 59,448 2038
Twin Falls 54,300 52,737 2041
Other Generating Plants:
Other Hydroelectric 10,400 11,300
Jim Bridger (Coal-Fired 698,333 699,104
Station)
Valmy (Coal-Fired 260,650 260,650
Station)
Boardman (Coal-Fired 53,000 56,050
Station)
(a)Renewed on a year-to-year basis; application for
relicense pending.
At December 31, 1997, the composite average ages of the principal
parts of the Company's system, based on dollar investment, were:
production plant, 17.9 years; transmission system and
substations, 18.4 years; and distribution lines and substations,
14.3 years. The Company considers its properties to be well
maintained and in good operating condition.
The Company owns in fee all of its principal plants and other
important units of real property, except for portions of certain
projects licensed under the Federal Power Act and reservoirs and
other easements, subject to the lien of its Mortgage and Deed of
Trust and the provisions of its project licenses, and to minor
defects common to properties of such size and character that do
not materially impair the value to, or the use by, the Company of
such properties.
As a result of various federal legislative actions and proposals
(such as the Electric Consumers Protection Act of 1986, Energy
Policy Act of 1992, Clean Water Act Reauthorization and
Endangered Species Act Reauthorization), a major issue facing the
Company is the relicensing of its hydro facilities. 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,
seeking renewal of the Company's licenses for its Bliss, Upper
Salmon Falls and Lower Salmon Falls Hydroelectric Projects. In
May 1997 the Company submitted its application for its Shoshone
Falls project. The Company is also in the process of submitting
a draft application for license renewal for its C J Strike
Hydroelectric Project. Although various federal requirements and
issues must be resolved through the licensing 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 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 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 Idaho Public Utilities
Commission (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 with prejudice, 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.
This case is scheduled for a trial by Judge alone commencing
April 6, 1998.
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
13, 1997 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, 59 Appointed August 18, 1989.
Chairman of the Board and
Chief Executive Officer
J. B. Packwood, 54 Appointed September 1, 1997. Mr.
President and Chief Packwood was Executive Vice President
Operating Officer from July 11, 1996 to September 1,
1997. Mr. Packwood was Vice
President-Power Supply prior to July
11, 1996.
J. LaMont Keen, 45 Appointed March 14, 1996. Mr. Keen
Vice President, Chief was Vice President and Chief
Financial Officer and Financial Officer prior to March 14,
Treasurer 1996.
Douglas H. Jackson, 61 Appointed August 1, 1997. Mr.
Vice President - Jackson was Vice President-Delivery
Corporate Affairs prior to August 1, 1997.
Name, Age and Position Business Experience During Past Five
(5) Years
James C. Miller, 43 Appointed July 10, 1997. Mr. Miller
Vice President - was General Manager of Power Supply
Generation from September 1, 1996 to July 10,
1997, and General Manager of Power
Delivery from July 29, 1995 to
September 1, 1996. Mr. Miller was
Manager of System Operations prior to
July 29, 1995.
C. N. Olson, 48 Appointed July 11, 1991.
Vice President - Corporate
Services
Richard Riazzi, 43 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.
Kip W. Runyan, 47 Appointed August 1, 1997. Mr. Runyan
Vice President - Delivery was President and Chief Executive
Officer for Ida-West Energy Company
prior to August 1, 1997.
Robert W. Stahman, 53 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 years of 1995, 1996 and 1997, cash
dividends per share of common stock were $1.86. At the July 1997
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
1996 and 1997, as reported by The Wall Street Journal as
composite tape transactions. The Company's year-end common stock
price was $37 5/8 per share and the number of stockholders of
record at December 31, 1997, was 27,019.
1997 Quarters
Common Stock, $2.50 par 1st 2nd 3rd 4th
value:
High $31 7/8 $31 1/2 $32 13/16 $37 3/4
Low 29 3/4 28 1/2 31 30 5/16
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 1997 1996 1995
(Thousands of Dollars)
Revenues:
General business $ 480,458 $ 484,145 $ 461,594
Off system sales 243,874 70,222 57,418
Other revenues 24,171 24,078 26,609
Total revenues 748,503 578,445 545,621
Expenses:
Purchased power 219,200 69,038 54,586
Fuel expense 71,271 63,334 54,691
Other operation and 180,148 168,539 169,959
maintenance
Depreciation 71,973 69,705 67,415
Taxes other than 21,162 20,658 22,979
income taxes
Total expenses 563,754 391,274 369,630
Income from operations 184,749 187,171 175,991
Other income and (14,255) (12,534) (14,356)
deductions - Net
Interest charges - Net 60,258 56,995 55,014
Income taxes 46,472 52,092 48,412
Cumulative effect of - - -
accruing unbilled
revenues
Net Income 92,274 90,618 86,921
Dividends on preferred 5,176 7,463 7,991
stocks
Earnings on common stock 87,098 83,155 78,930
Dividends on common 69,887 69,924 69,941
stock
Net change to retained $ 17,211 $ 13,231 $ 8,989
earnings
CAPITALIZATION (000
omitted) % % %
First mortgage bonds $ 527,000} $ 527,000} $ 470,000}
Other long-term debt 176,684 46 211,550 48 202,618 45
Preferred stock 106,697 7 106,975 7 132,181 9
Common stock (incl. 452,519} 452,486} 452,948}
prem. & exp.)
Retained earnings 259,299 47 242,088 45 229,827 46
Total
capitalization $1,522,199 100 $1,540,099 100 $1,487,574 100
Short-term borrowings
outstanding $ 57,516 $ 54,016 $ 53,020
FINANCIAL STATISTICS
Income from operations
as a percent of 24.7 % 32.4 % 32.3 %
total revenues
Times interest charges
earned:
Before tax 3.28 3.49 3.40
After tax 2.52 2.58 2.54
Market-to-book ratio 199 % 169 % 165 %
Payout ratio 80 % 84 % 89 %
Return on year-end 12.24 % 11.97 % 11.56 %
common equity
Common stock data:
Earnings per average
share outstanding $ 2.32 $ 2.21 $ 2.10
Dividends declared per
share $ 1.86 $ 1.86 $ 1.86
Book value per share $ 18.93 $ 18.47 $ 18.15
Average shares 37,612 37,612 37,612
outstanding (000
omitted)
Common shareowners 27,019 29,333 30,795
*Includes cumulative
effect of accounting
change
CUSTOMER DATA
General business data:
Energy sales - kwh 13,240 13,035 11,983
(000,000 omitted)
Number of customers 363,085 352,487 340,708
Residential customer
data:
Number of customers 300,714 292,145 282,797
Average kwh use per 13,665 13,828 13,475
customer
Average rate per
kwh (cents) 4.96 5.07 5.16
OTHER STATISTICS
Total assets (000
omitted) $2,405,432 $2,295,337 $2,241,753
Gross plant additions $ 96,762 $ 94,120 $ 87,297
(000 omitted)
Number of employees 1,615 1,565 1,522
(full-time)
SUMMARY OF OPERATIONS 1994 1993 1992
(Thousands of Dollars)
Revenues:
General business $ 457,354 $ 428,658 $ 431,818
Off system sales 59,923 86,525 42,000
Other revenues 26,381 25,219 24,274
Total revenues 543,658 540,402 498,092
Expenses:
Purchased power 60,216 45,361 58,496
Fuel expense 94,888 87,855 96,710
Other operation and 154,742 164,388 137,547
maintenance
Depreciation 60,202 58,724 59,823
Taxes other than 23,945 22,129 20,562
income taxes
Total expenses 393,993 378,457 373,138
Income from operations 149,665 161,945 124,954
Other income and (12,160) (12,984) (11,133)
deductions - Net
Interest charges - Net 52,652 53,991 52,935
Income taxes 34,243 36,474 23,162
Cumulative effect of - - -
accruing unbilled
revenues
Net Income 74,930 84,464 59,990
Dividends on preferred 7,398 6,009 5,516
stocks
Earnings on common stock 67,532 78,455 54,474
Dividends on common 69,594 67,959 65,043
stock
Net change to retained
earnings $ (2,062) $ 10,496 $ (10,569)
CAPITALIZATION (000 % % %
omitted)
First mortgage bonds $ 490,000} $ 490,000} $ 485,000}
Other long-term debt $ 203,206 46 203,780 47 216,948 49
Preferred stock 132,456 9 132,751 9 107,874 7
Common stock (incl. 452,962} 439,467} 412,988}
prem. & exp.)
Retained earnings 220,838 45 222,900 44 212,404 44
Total
capitalization $1,499,462 100 $1,488,898 100 $1,435,224 100
Short-term borrowings
outstanding $ 55,000 $ 4,000 $ 6,000
FINANCIAL STATISTICS
Income from operations
as a percent of 27.5 % 30.0 % 25.1 %
total revenues
Times interest charges
earned:
Before tax 3.01 3.14 2.50
After tax 2.38 2.50 2.08
Market-to-book ratio 131 % 170 % 159 %
Payout ratio 103 % 87 % 120 %
Return on year-end 10.02 % 11.84 % 8.71 %
common equity
Common stock data:
Earnings per average
share outstanding $ 1.80 $ 2.14 $ 1.55
Dividends declared per
share $ 1.86 $ 1.86 $ 1.86
Book value per share $ 17.91 $ 17.86 $ $17.28
Average shares 37,499 36,675 35,116
outstanding (000
omitted)
Common shareowners 26,209 26,870 27,834
*Includes cumulative
effect of accounting
change
CUSTOMER DATA
General business data:
Energy sales - kwh 12,194 11,406 11,606
(000,000 omitted)
Number of customers 330,308 317,772 307,567
Residential customer
data:
Number of customers 274,187 263,682 255,022
Average kwh use per 14,159 14,587 13,856
customer
Average rate per kwh (cents) 4.83 4.82 4.80
OTHER STATISTICS
Total assets (000
omitted) $2,191,816 $2,097,417 $1,862,307
Gross plant additions $ 107,667 $ 116,972 $ 118,920
(000 omitted)
Number of employees 1,609 1,654 1,638
(full-time)
SUMMARY OF OPERATIONS 1991 1990 1989
(Thousands of Dollars)
Revenues:
General business
$ 409,454 $ 401,350 $ 397,974
Off system sales 52,563 44,368 70,749
Other revenues 21,176 19,217 27,438
Total revenues 483,193 464,935 496,161
Expenses:
Purchased power 51,210 43,923 43,845
Fuel expense 75,161 77,606 77,127
Other operation and 151,593 134,126 132,114
maintenance
Depreciation 57,597 55,114 53,092
Taxes other than 21,168 20,752 20,213
income taxes
Total expenses 356,729 331,521 326,391
Income from operations 126,464 133,414 169,770
Other income and (9,453) (11,666) (10,005)
deductions - Net
Interest charges - Net 56,901 52,605 52,997
Income taxes 21,144 23,234 42,041
Cumulative effect of - - -
accruing unbilled
revenues
Net Income 57,872 69,241 84,737
Dividends on preferred 4,904 4,279 4,285
stocks
Earnings on common stock 52,968 64,962 80,452
Dividends on common 63,197 63,197 62,177
stock
Net change to retained $ (10,229) $ 1,765 $ 18,275
earnings
CAPITALIZATION (000 % % %
omitted)
First mortgage bonds $ 435,000} $ 367,500} $ 377,000}
Other long-term debt 194,981 48 194,159 46 165,551 47
Preferred stock 108,191 8 58,761 5 58,923 5
Common stock (incl. 356,824} 358,078} 357,986}
prem. & exp.)
Retained earnings 222,973 44 233,241 49 231,476 48
Total
capitalization $1,317,969 100 $1,211,739 100 $1,190,936 100
Short-term borrowings
outstanding $ 48,500 $ 48,280 $ 31,000
FINANCIAL STATISTICS
Income from operations
as a percent of 26.2 % 28.7 % 34.2 %
total revenues
Times interest charges
earned:
Before tax 2.34 2.72 3.30
After tax 1.98 2.29 2.53
Market-to-book ratio 168 % 148 % 169 %
Payout ratio 119 % 97 % 77 %
Return on year-end 9.14 % 10.99 % 13.65 %
common equity
Common stock data:
Earnings per average
share outstanding $ 1.56 $ 1.91 $ 2.37
Dividends declared per
share $ 1.86 $ 1.86 $ 1.83
Book value per share $ 17.07 $ 17.40 $ 17.35
Average shares 33,977 33,977 33,977
outstanding (000
omitted)
Common shareowners 28,069 29,080 30,291
*Includes cumulative
effect of accounting
change
CUSTOMER DATA
General business data:
Energy sales - kwh 11,266 11,086 11,069
(000,000 omitted)
Number of customers 297,808 291,800 284,363
Residential customer
data:
Number of customers 246,689 241,790 236,008
Average kwh use per 14,845 14,281 14,923
customer
Ave rate per kwh (cents) 4.72 4.73 4.69
OTHER STATISTICS
Total assets (000
omitted) $1,773,674 $1,680,110 $1,625,120
Gross plant additions
(000 omitted) $ 135,904 $ 80,117 $ 62,094
Number of employees 1,626 1,574 1,528
(full-time)
SUMMARY OF OPERATIONS 1988 1987
(Thousands of Dollars)
Revenues:
General business $ 362,050 $ 343,899
Off system sales 32,175 35,447
Other revenues 18,096 15,251
Total revenues 412,321 394,597
Expenses:
Purchased power 43,723 30,234
Fuel expense 74,528 65,934
Other operation and 116,230 114,235
maintenance
Depreciation 51,691 50,929
Taxes other than 19,301 19,072
income taxes
Total expenses 305,473 280,404
Income from operations 106,848 114,193
Other income and (6,552) (13,115)
deductions - Net
Interest charges - Net 50,762 51,843
Income taxes 13,558 27,246
Cumulative effect of - (11,302)
accruing unbilled
revenues
Net Income 49,080 59,521
Dividends on preferred 4,293 4,298
stocks
Earnings on common stock 44,787 55,223
Dividends on common 61,159 61,159
stock
Net change to retained $ (16,372) $ (5,936)
earnings
CAPITALIZATION (000
omitted) % %
First mortgage bonds $ 392,000} $ 407,000}
Other long-term debt 164,426 47 160,003 47
Preferred stock 59,126 5 59,238 5
Common stock (incl. 357,866} 357,977}
prem. & exp.)
Retained earnings 213,201 48 229,573 48
Total $1,186,619 100 $1,213,611 100
capitalization
Short-term borrowings
outstanding $ 37,000 $ 4,000
FINANCIAL STATISTICS
Income from operations
as a percent of 25.9 % 28.9 %
total revenues
Times interest charges
earned:
Before tax 2.18 2.76 *
After tax 1.93 2.10 *
Market-to-book ratio 138 % 127 %
Payout ratio 137 % 111 %
Return on year-end 7.84 % 9.40 %
common equity
Common stock data:
Earnings per average
share outstanding $ 1.32 $ 1.63*
Dividends declared per
share $ 1.80 $ 1.80
Book value per share
$ 16.81 $ 17.29
Average shares 33,977 33,977
outstanding (000
omitted)
Common shareowners 32,225 33,733
*Includes cumulative
effect of accounting
change
CUSTOMER DATA
General business data:
Energy sales - kwh 10,563 10,175
(000,000 omitted)
Number of customers 279,529 276,249
Residential customer
data:
Number of customers 232,650 230,486
Average kwh use per 14,364 13,785
customer
Ave rate per kwh (cents) 4.47 4.34
OTHER STATISTICS
Total assets (000
omitted) $1,608,935 $1,602,311
Gross plant additions $ 64,358 $ 38,929
(000 omitted)
Number of employees 1,500 1,521
(full-time)
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS
Idaho Power Company's consolidated financial statements represent
the Company and its wholly-owned or controlled subsidiaries.
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.
RESULTS OF OPERATIONS
Overview -
A number of factors have contributed to the increase in earnings
per share over the last three years, including improved
hydroelectric generating conditions, a strong service territory
economy, continued strong customer growth, resolution of rate
cases, regulatory settlements and improved subsidiary operating
results.
Idaho Power's service territory experienced above average water
years from 1995-1997. Hydro generation was 69 percent of total
Company generation in 1997 and 1996, and 67 percent in 1995,
compared to the historical average of 62 percent.
Idaho's economy, especially in the Company's service territory,
continued its strong performance over the last three years.
Idaho's non-agricultural employment growth for the twelve months
ended November 1997 was 1.9 percent; annual growth rates in 1996
and 1995 were 3.1 percent and 3.2 percent, respectively. Within
the Boise Metropolitan Statistical Area, the heart of Idaho
Power's service territory, non-agricultural employment increased
4.0 percent for the twelve months ended November 1997, 4.0
percent in 1996 and 5.1 percent in 1995.
General business customer growth continued in 1997, with a 3.0
percent increase, compared with a 3.5 percent increase in 1996.
This growth is attributable to strong overall economic conditions
in the Company's service territory.
Operating revenues increased $170.1 million in 1997, due
primarily to increased trading in the electricity market, and
$32.8 million in 1996, due primarily to customer growth and
weather conditions in the Company's service territory. The
Company set aside approximately $8.7 million in 1997 and $4.9
million in 1996 for the benefit of its Idaho customers. The
provision for refund reduced reported earnings per share by
approximately $0.14 in 1997 and $0.08 in 1996 (See "Regulatory
Issues - Regulatory Settlement").
Total operating expenses increased $172.5 million in 1997, due
primarily to increased trading in wholesale electricity markets,
and $21.6 million in 1996, due primarily to increased purchased
power and fuel expenses resulting from increased sales.
Income taxes decreased $5.6 million in 1997, due primarily to an
increase in tax credits earned from increasing investments in
affordable housing projects.
Earnings per share of common stock in 1997 were $2.32, up from
$2.21 earned in 1996 and $2.10 earned in 1995. The 1997 earnings
equate to a 12.2 percent earned return on year-end common equity,
as compared to the 12.0 percent earned in 1996 and the 11.6
percent earned in 1995. At December 31, 1997, the book value per
share of common stock was $18.93, compared to $18.47 at December
31, 1996 and $18.15 at December 31, 1995.
General Business Revenue -
General business revenue is dependent on a number of factors,
including the number of customers, rate adjustments, and weather
patterns. The 0.8 percent decrease in general business revenue
in 1997 is due primarily to a rate decrease, more moderate
temperatures and increased precipitation, which reduced average
irrigation customer energy sales by 8.2 percent and average
residential customer energy sales by 1.2 percent. Precipitation
increased 37.1 percent during the 1997 growing season, compared
to 1996, and heating and cooling degree days, a common measure
used in the electric utility industry to analyze usage, decreased
by 3.3 percent in 1997. These factors were partially offset by
a 3.0 percent increase in the number of general business
customers.
The 4.9 percent increase in general business revenue in 1996 is
due to a 5.3 percent increase in average energy sales per
customer and a 3.5 percent increase in the number of customers,
offset by decreases in customer rates. Usage per customer was
influenced by more extreme temperatures and decreased
precipitation. Heating and cooling degree days increased 6.5
percent over 1995 and precipitation during the growing season
decreased 17.1 percent.
Off-System Sales -
Off-system sales increased $173.7 million in 1997 and $12.8
million in 1996. The increases in off-system revenue are due
primarily to increases in MWH sales, of approximately 200 percent
in 1997 and 48 percent in 1996. This volume growth reflects
significant increases in trading in the wholesale electricity
markets.
Off-system sales are comprised of trading in the wholesale
electricity markets, 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 western United
States.
Expenses -
Purchased power expense increased $150.2 million in 1997 and
$14.5 million in 1996 due primarily to increases in MWHs
purchased in the electricity trading markets. Total MWHs of
purchased power increased 213 percent in 1997 and 41 percent in
1996. These increases reflect the Company's increased trading in
the wholesale electricity markets and the availability of low
cost energy resulting from the abundance of hydro generation in
the West.
Fuel expense increased by $7.9 million in 1997 and $8.6 million
in 1996 due primarily to increased generation at the Company's
coal-fired plants to take advantage of off-system sales
opportunities. Total generation at the coal-fired plants was
approximately 5.4 million MWHs in 1997, 4.8 million MWH in 1996
and 4.6 million MWHs in 1995.
In 1997, the change in the PCA was minimal, but in 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 "Regulatory Issues - Power Cost Adjustment").
The increases in other operation expenses in 1997 and 1996 were
due primarily to increased payroll and benefits, and changes in
operations due to water conditions.
Maintenance expenses increased $6.0 million in 1997 and $6.8
million in 1996. The 1997 increase is due to extensive
maintenance at the Company's Valmy generation facility due to
increased utilization, and repairs to hydro facilities and
distribution facilities damaged by natural causes. The 1996
increase is due primarily to maintenance on transmission and
distribution facilities damaged by natural causes.
Depreciation expense increased for the two-year period by $4.6
million, due to greater plant investment.
Interest Charges -
Interest charges on long-term debt increased $1.1 million in 1997
and $1.0 million in 1996, reflecting an increase in the average
amount of debt outstanding during the periods, partially offset
by decreased interest rates. In October 1996 the Company issued
$27.0 million of Secured Medium Term Notes (Series B, 6.85%, Due
2002) the proceeds of which were used to redeem $25.0 million of
preferred stock and pay related redemption premiums.
Other interest increased $2.4 million in 1997, due primarily to
increased short-term borrowing and subsidiary financing.
Income Taxes -
Income taxes decreased $5.6 million in 1997 and increased $3.7
million in 1996. The decrease in 1997 is due primarily to a $2.7
million increase in affordable housing tax credits and decreased
net income before taxes. The increase in 1996 is due primarily
to increased net income before taxes.
Regulatory Issues -
Power Cost Adjustment (PCA)-
The Company has a PCA mechanism that provides for annual
adjustments to the rates charged to Idaho retail customers.
These adjustments are based on forecasts of net power supply
costs, and take effect annually on May 16. The difference
between the actual costs incurred and the forecasted costs are
deferred, with interest, and trued-up in the next annual rate
adjustment.
The 1997-1998 forecast assumed above-average hydroelectric
generating conditions. This resulted in forecasted power supply
costs and rates being lower than the base amounts established in
past regulatory proceedings. The Company's May 1997 PCA
adjustment, combined with the revenue-sharing mechanism described
below, decreased rates 0.63%. Revenue from Idaho retail
customers will be $20.2 million less than what would be recovered
if the Company was charging the base rates during this rate period.
The May 1996 adjustment reduced Idaho jurisdictional PCA rates 5.9
percent.
So far in the current rate period, actual power costs have
exceeded the forecast. The Company has recorded a regulatory
asset of, and decreased expenses by, $12.8 million as of December
31, 1997. The variance that exists at the end of the current
rate period will be trued-up in the next annual PCA adjustment.
Regulatory Settlement -
On August 3, 1995, the Company filed a proposal with the IPUC to
support the Company's organizational redesign. In response to
the 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 1999. The settlement
gives the Company time to pursue and to implement its efficiency
and growth initiatives with the assurance of a reasonable level
of financial performance without the need to change customer
prices.
Under the terms of the settlement, which remains in effect
through 1999, when the Company's actual earnings in a given year
exceed an 11.75 percent return on year-end common equity for the
Idaho jurisdiction, the Company will refund 50 percent of the
excess to Idaho's retail ratepayers. In 1997, the Company set
aside $8.7 million for the benefit of its Idaho customers. In
1996, the Company set aside $4.9 million, $1.4 million of which
was retained from refunding and applied against the regulatory
asset balance of Idaho demand side conservation management
expenditures.
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, up to a maximum of $30 million of ADITCs.
The Company has received approval from the Idaho State Tax
Commission and the Internal Revenue Service on the accounting
treatment for the tax credits. As of December 31, 1997, no
ADITCs have been used under the regulatory agreement.
Other important points in the Settlement are that 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 the Company agrees that its quality
of service will not decline as a result of corporate
reorganization.
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 a request 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 less than one MW. 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 one MW could
request to a maximum of five years.
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.
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 granted 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 for the year
1994. 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 went into
effect in July 1995 and will remain in effect until approximately
May 1998.
Subsidiaries -
Ida-West Energy Company -
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 a partnership 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.
IDACORP, Inc. -
Through IDACORP, the Company is participating in eight 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 $6.5 million in
IDACORP.
LIQUIDITY AND CAPITAL RESOURCES -
Cash Flow -
The Company's net cash generated from operations totaled $516.2
million for the three-year period 1995-1997. After deducting
common and preferred dividends of $231.0 million, net cash
generation from operations provided approximately $285.1 million
for the Company's construction program and other capital
requirements. Internal cash generation after dividends provided
101 percent of the Company's total capital requirements in 1997,
99 percent in 1996, and 101 percent in 1995.
The Company forecasts that internal cash generation after
dividends will provide approximately 85 percent of total capital
requirements in 1998 and over 105 percent during the four-year
period 1999-2002. 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 has first mortgage bond maturities of $30.0 million in
1998, $0 in 1999, $80.0 million in 2000, $30.0 million in 2001
and $27.0 million in 2002.
At January 1, 1998, the Company had regulatory authority to incur
up to $200.0 million of short-term indebtedness. At December 31,
1997, the Company's short-term borrowing totaled $57.5 million
compared to $54.0 million at December 31, 1996 and $53.0 million
at December 31, 1995.
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 pays 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
$94.5 in 1997, $93.6 million in 1996, and $84.0 million in 1995.
Approximately 26 percent of these expenditures were for
generation facilities, 19 percent for transmission facilities, 43
percent for distribution facilities, and 12 percent for general
plant and equipment. The Company estimates that its cash
construction program will require $100 million in 1998 and $390
million in the four year period 1999-2002. These estimates are
subject to revision in light of changing economic, regulatory,
environmental, and conservation factors.
Southwest Intertie Project (SWIP) -
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 Company is
continuing to evaluate the economic viability of the proposed
line.
Operational and Financial Information Systems -
During 1997 the Company implemented new financial and operating
information systems. Total costs for both hardware and software
were $19.3 million. The Company expects to spend an additional
$1.2 million on the project in 1998.
Financing Program -
The Company's capital structure fluctuated slightly during the
three-year period, with common equity ending at 47 percent,
preferred stock 7 percent, and long-term debt 46 percent at
December 31, 1997. 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 3.28 times in
1997, 3.49 times in 1996, and 3.40 times in 1995.
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 $25,000,000 principal
amount of 8.375% Series, Serial Preferred Stock, Without Par
Value ($100 stated value). These transactions have reduced the
remaining balance on the shelf registration to $143 million as of
December 31, 1997.
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.
OTHER MATTERS -
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 Company and the
BPA have negotiated a five-year contract, expiring April 15,
2001, requiring BPA to replace lost energy and capacity resulting
from recovery plans that impact the Company's power supply cost.
Nez Perce Lawsuit -
On March 21, 1997, the United States District Court for the
District of Idaho entered a judgment related to a civil lawsuit
filed against Idaho Power in 1991 by the Nez Perce Tribe. 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 judgment, which incorporated the terms of an
agreement already reached by the Company and the Tribe, requires
Idaho Power to pay the Nez Perce Tribe $11.5 million over five
years. The first payment of $5 million plus agreed upon
interest was paid on March 28, 1997. Additional payments of
$1,625,000 will be made each of 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
three percent and a maximum of seven percent.
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.
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. In 1997, the Company's
biologists completed this study, which focused on potential snail
habitat in the Middle Snake River. The Company's objective was
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. A final
report on the study is due in May 1998.
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 and is responsible for one-
third of BCC's costs. BCC's portion of the cleanup costs at
Mountaineer was $261,700. Cleanup is substantially complete,
with the exception of ground water monitoring which will continue
for the next seven years.
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.
On July 16, 1997, the EPA announced new National Ambient Air Quality
Standards for ozone and Particulate Matter (PM). In addition to
these standards, on July 17, 1997, the EPA proposed regional haze
regulations for protection of visibility in national parks and
wilderness areas. Impacts of the ozone and PM regulations and the
proposed regional haze regulations on the Company's thermal operations
are unknown at this time.
Although not presently required to meet any federal nitrogen oxide
(NOx) limits, North Valmy, Boardman, and Jim Bridger Unit 4 elected
to meet Phase I NOx limits beginning in 1998. As a result of this
voluntary "early election" these units will not be required to meet
the more restrictive Phase II NOx limits until 2008. Had the units
not voluntarily "early elected", they would have been required to meet
the Phase II NOx limits beginning in 2000.
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.
Electric Industry Restructuring -
Competition is increasing in the electric utility industry on
both a wholesale and retail level. Idaho Power's goal is to
anticipate and fully integrate into Company operations any
legislative, regulatory or competitive changes. It is pursuing a
rapid, but orderly transition to at least a partially and
possibly a totally deregulated environment in the years ahead.
With its low energy production costs, Idaho Power is well-positioned
to succeed in a more competitive environment and is taking steps to
preserve its low-cost advantage. The following items describe
some of the changes to date, as well as steps being taken by the
Company.
Legislative Actions -
In 1997, the Idaho legislature appointed a committee to study
deregulation of the electric utility industry. Legislation
resulting from this committee required the IPUC to begin an
investigation into the unbundling of costs into its various
delivery and energy components. The Company has filed cost
unbundling studies in July and December 1997. The IPUC next will
compile cost data presented by all the electric utilities and
present that information to the legislature. Although the
committee will continue studying a variety of deregulation ideas
throughout 1998, it is not expected to recommend restructuring
legislation until at least 1999.
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.
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 twenty one Northwest and Rocky Mountain electric
utilities, including Idaho Power had been working to create an
independent transmission grid operator called "IndeGO". As
envisioned, IndeGO would ensure non-discriminatory, open-access
to electricity transmission facilities in compliance with recent
FERC rulings. In 1996, the utilities signed a memorandum of
understanding to investigate the feasibility of developing a
regional transmission grid which would be operated by an entity
independent of power market interests. As initially studied,
IndeGO could control substantially all of the transmission
facilities in eight western states.
In November 1997, the group released a complete package of draft
legal agreements and descriptive materials for formal public
review with the intention of making a filing with FERC in 1998.
However, due to concerns with timing, costs and the status of
restructuring in Idaho, the Company has stated that it cannot
support an IndeGO filing with FERC at this time and as currently
structured. Subsequently, on March 4, 1998, seven Northwest
investor owned utilities, including the Company, issued a joint
statement concluding that it is not productive to devote further
effort to IndeGO development at this time because of critical
questions about electric restructuring and Bonneville Power
Administration participation.
Holding Company -
The Company filed an application and received approval from the
IPUC in January 1998 to form a holding company to serve as a
parent company for both Idaho Power and Ida-West. The purpose of
the holding company is to allow the Company more flexibility as
the energy industry continues to undergo rapid changes. Approval
by the IPUC was the first in a series of steps the Company must
take. The Company will be next seeking approval from federal
agencies and the public utilities commissions of Nevada, Oregon
and Wyoming. Once the Company has received all required
approvals, it then will seek its shareholders' endorsement.
Energy Trading -
The Company intends to be a competitive energy provider,
including both electricity and natural gas. In 1997, the Company
opened a gas trading offices in Houston, Texas to serve the
southern and eastern United States and Boise, Idaho to serve the
Northwest and Canadian markets. For 1997, the Company has
recorded a loss of $1.2 million in its gas trading operations,
because the cost of operations exceeded trading gains in this
start-up period. The Company is also actively participating in
the wholesale electricity markets, the results of which are
included in off-system revenue and purchased power expense.
To implement this strategy, the Board of Directors gave approval
for executive management to form a Risk Management Committee,
comprised of Company officers, 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. 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.
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. At December 31, 1997, $4.3 million of
relicensing costs were included in Construction Work in Progress.
Year 2000 Compliance -
Idaho Power, like most other companies, will be required to
modify significant portions of its computer software so that it
functions properly in the year 2000. The Company is expending
significant resources to ensure that its computer systems are
able to deal with transactions that occur in 2000 and beyond.
Failure to adequately prepare for these transactions could have a
material impact on the Company's ability to conduct its business.
Maintenance and modification costs related to this issue will be
expensed as incurred, and new software will be capitalized and
amortized over its useful life.
New Accounting Pronouncements -
In June 1997, the FASB issued SFAS No. 130, Reporting
Comprehensive Income and No. 131, Disclosures about Segments of
an Enterprise and Related Information. These statements are
effective for financial statements beginning after December 15,
1997. SFAS No. 130 establishes standards for reporting and display
of comprehensive income and its components in a full set of general
purpose financial statements. SFAS No. 131 redefines standards
for the way that public business enterprises report information
about operating segments in annual and interim financial
statements. The Company is reviewing these statements to
determine their effect on its reporting requirements.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
INDEX TO FINANCIAL STATEMENT
AND FINANCIAL STATEMENT SCHEDULE
PAGE
Management's Responsibility for Financial Statements 37
Consolidated Financial Statements:
Consolidated Balance Sheets as of December 31, 1997,
1996 and 1995 38-39
Consolidated Statements of Income for the Years
Ended December 31, 1997, 1996 and 1995 40
Consolidated Statements of Retained Earnings for the Years
Ended December 31, 1997, 1996 and 1995 41
Consolidated Statements of Capitalization as of
December 31, 1997, 1996 and 1995 42
Consolidated Statements of Cash Flows for the Years
Ended December 31, 1997, 1996 and 1995 43
Notes to Consolidated Financial Statements 44-56
Independent Auditors' Report 57
Supplemental Financial Information (Unaudited) 58
Supplemental Schedule for the Years Ended December 31,
1997, 1996 and 1995:
Schedule II- Consolidated Valuation and
Qualifying Accounts 66
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.
Joseph W. Marshall
Chairman and Chief Executive Officer
J. LaMont Keen
Vice President, Chief Financial Officer and Treasurer
IDAHO POWER COMPANY
CONSOLIDATED BALANCE SHEETS
ASSETS
December 31,
1997 1996 1995
(Thousands of Dollars)
ELECTRIC PLANT:
In service (at original cost) $2,605,697 $2,537,565 $2,481,830
Accumulated provision for (942,400) (886,885) (830,615)
depreciation
In service - Net 1,663,297 1,650,680 1,651,215
Construction work in progress 51,892 42,178 20,564
Held for future use 1,738 1,773 1,106
Electric plant - Net 1,716,927 1,694,631 1,672,885
INVESTMENTS AND OTHER PROPERTY 50,681 36,502 16,826
CURRENT ASSETS:
Cash and cash equivalents 6,905 7,928 8,468
Receivables:
Customer 63,076 34,962 33,357
Gas operations 42,128 - -
Allowance for uncollectible (1,397) (1,394) (1,397)
accounts
Notes 4,613 5,104 5,134
Employee notes receivable 4,757 4,486 4,648
Other 8,854 8,489 10,771
Accrued unbilled revenues 33,312 27,709 25,025
Materials and supplies (at 29,156 24,639 25,937
average cost)
Fuel stock (at average cost) 7,172 11,631 13,063
Prepayments 15,381 16,165 20,778
Regulatory assets associated 3,164 4,397 5,777
with income taxes
Total current assets 217,121 144,116 151,561
DEFERRED DEBITS:
American Falls and Milner water 32,055 32,260 32,440
rights
Company-owned life insurance 51,915 57,291 56,066
Regulatory assets associated 198,521 196,696 200,379
with income taxes
Regulatory assets - other 90,239 89,507 68,348
Other 47,973 44,334 43,248
Total deferred debits 420,703 420,088 400,481
TOTAL $2,405,432 $2,295,337 $2,241,753
The accompanying notes are an integral part of these statements.
IDAHO POWER COMPANY
CONSOLIDATED BALANCE SHEETS
CAPITALIZATION AND LIABILITIES
December 31,
1997 1996 1995
(Thousands of Dollars)
CAPITALIZATION:
Common stock equity:
Common stock - $2.50 par
value (shares authorized $ 94,031 $ 94,031 $ 94,031
50,000,000; shares
outstanding - 37,612,351)
Premium on capital stock 362,328 362,297 363,044
Capital stock expense (3,840) (3,842) (4,127)
Retained earnings 259,299 242,088 229,827
Total common stock equity 711,818 694,574 682,775
Preferred stock 106,697 106,975 132,181
Long-term debt 703,684 738,550 672,618
Total capitalization 1,522,199 1,540,099 1,487,574
CURRENT LIABILITIES:
Long-term debt due within one 30,072 71 20,517
year
Notes payable 57,516 54,016 53,020
Accounts payable 69,064 36,370 40,483
Accounts payable gas operations 42,874 - -
Taxes accrued 24,295 17,304 15,409
Interest accrued 17,918 15,886 14,785
Deferred income taxes 3,164 4,397 5,777
Other 13,703 12,439 12,867
Total current liabilities 258,606 140,483 162,858
DEFERRED CREDITS:
Regulatory liabilities associated
with deferred investment tax 70,196 71,283 70,507
credits
Deferred income taxes 423,736 411,890 408,394
Regulatory liabilities 34,072 35,028 34,554
associated with income taxes
Regulatory liabilities - other 509 616 789
Other 96,114 95,938 77,077
Total deferred credits 624,627 614,755 591,321
COMMITMENTS AND CONTINGENT
LIABILITIES (Note 8)
TOTAL $2,405,432 $2,295,337 $2,241,753
The accompanying notes are an integral part of these statements.
IDAHO POWER COMPANY
CONSOLIDATED STATEMENTS OF INCOME
Year Ended December 31,
1997 1996 1995
(Thousands of Dollars)
REVENUES:
Total general business $480,458 $484,145 $461,594
Off system sales 243,874 70,222 57,418
Other revenues 24,171 24,078 26,609
Total revenues 748,503 578,445 545,621
EXPENSES:
Operation:
Purchased power 219,200 69,038 54,586
Fuel expense 71,271 63,334 54,691
Power cost adjustment (6,032) (6,859) 7,292
Other 137,458 132,667 126,714
Maintenance 48,722 42,731 35,953
Depreciation 71,973 69,705 67,415
Taxes other than income taxes 21,162 20,658 22,979
Total expenses 563,754 391,274 369,630
INCOME FROM OPERATIONS 184,749 187,171 175,991
OTHER INCOME:
Allowance for equity funds used 34 46 (16)
during construction
Gas trading activities - Net (1,181) - -
Other - Net 15,402 12,488 14,372
Total other income 14,255 12,534 14,356
INTEREST CHARGES:
Interest on long-term debt 53,215 52,165 51,147
Other interest 7,546 5,183 5,309
Total interest charges 60,761 57,348 56,456
Allowance for borrowed funds
used during (503) (353) (1,442)
construction
Net interest charges 60,258 56,995 55,014
INCOME BEFORE INCOME TAXES 138,746 142,710 135,333
INCOME TAXES 46,472 52,092 48,412
NET INCOME 92,274 90,618 86,921
Dividends on preferred stock 5,176 7,463 7,991
EARNINGS ON COMMON STOCK $ 87,098 $ 83,155 $ 78,930
AVERAGE COMMON SHARES
OUTSTANDING (000) 37,612 37,612 37,612
EARNINGS PER SHARE OF
COMMON STOCK $ 2.32 $ 2.21 $ 2.10
The accompanying notes are an integral part of these statements.
IDAHO POWER COMPANY
CONSOLIDATED STATEMENTS OF RETAINED EARNINGS
Year Ended December 31,
1997 1996 1995
(Thousands of Dollars)
RETAINED EARNINGS
Beginning of year $242,088 $229,827 $220,838
NET INCOME 92,274 90,618 86,921
Total 334,362 320,445 307,759
DIVIDENDS:
Preferred stock 5,176 7,463 7,991
Common stock (per share: $1.86) 69,887 69,924 69,941
Total dividends 75,063 77,387 77,932
PREFERRED STOCK REDEMPTION - 970 -
RETAINED EARNINGS
End of year $259,299 $242,088 $229,827
The accompanying notes are an integral part of these statements.
IDAHO POWER COMPANY
CONSOLIDATED STATEMENTS OF CAPITALIZATION
December 31,
1997 % 1996 % 1995 %
(Thousands of Dollars)
COMMON STOCK EQUITY
Common stock $ 94,031 $ 94,031 $ 94,031
Premium on capital stock 362,328 362,297 363,044
Capital stock expense (3,840) (3,842) (4,127)
Retained earnings 259,299 242,088 229,827
Total common stock 711,818 47 694,574 45 682,775 46
equity
PREFERRED STOCK
4% preferred stock 16,697 16,975 17,181
7.68% Series, serial 15,000 15,000 15,000
preferred stock
8.375% Series, serial - - 25,000
preferred stock
7.07% Series, serial 25,000 25,000 25,000
preferred stock
Auction rate preferred 50,000 50,000 50,000
stock
Total preferred stock 106,697 7 106,975 7 132,181 9
LONG-TERM DEBT
First mortgage bonds:
5 1/4 % - - 20,000
Series due 1996
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 30,000 -
6.85 % Series due 2002 27,000 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 % 50,000 50,000 50,000
Series due 2027
9.52 % Series due 2031 25,000 25,000 25,000
Total first mortgage 527,000 527,000 490,000
bonds
Amount due within one year (30,000) - (20,000)
Net first mortgage 497,000 527,000 470,000
bonds
Pollution control revenue
bonds:
5.90 % Series due 2003 - - 24,200
6.0 % Series due 2007 - - 24,000
7 1/4 % 4,360 4,360 4,360
Series due 2008
7 5/8 % Series 1983 - - - 68,100
1984 due 2013 - 2014
8.30 %Series 1984 due 49,800 49,800 49,800
2014
6.05 %Series 1996A due 68,100 68,100 -
2026
Variable rate Series 24,200 24,200 -
1996B due 2026
Variable rate Series 24,000 24,000 -
1996C due 2026
Total pollution control 170,460 170,460 170,460
revenue bonds
Amount due within one year - - (450)
Net pollution control 170,460 170,460 170,010
revenue bonds
REA notes 1,561 1,632 1,700
Amount due within one year (72) (71) (67)
Net REA notes 1,489 1,561 1,633
Subsidiary debt 4,316 9,000 -
American Falls bond 20,355 20,560 20,740
guarantee
Milner Dam note guarantee 11,700 11,700 11,700
Unamortized (1,636) (1,731) (1,465)
premium/discount - Net
Total long-term debt 703,684 46 738,550 48 672,618 45
TOTAL CAPITALIZATION $1,522,199 100 $1,540,099 100 $1,487,574 100
The accompanying notes are an integral part of these statements.
IDAHO POWER COMPANY
CONSOLIDATED STATEMENTS OF CASH FLOWS
Year Ended December 31,
1997 1996 1995
(Thousands of Dollars)
OPERATING ACTIVITIES:
Cash received from operations:
Retail revenues $483,402 $490,504 $468,821
Wholesale revenues 217,017 66,551 59,260
Other revenues 28,700 24,469 22,825
Fuel paid (67,165) (59,798) (61,741)
Purchased power paid (180,988) (70,302) (52,526)
Other operation & maintenance (183,589) (177,055) (154,209)
paid
Interest paid (include long and (53,822) (53,273) (54,303)
short-term debt only)
Income taxes paid (41,786) (45,050) (40,402)
Taxes other than income taxes (27,542) (23,455) (22,939)
paid
Other operating cash receipts (830) 21,824 3,634
and payments - Net
Net cash provided by 173,397 174,415 168,420
operating activities
FINANCING ACTIVITIES:
First mortgage bonds issued - 57,000 -
PC bond fund requisitions/other (4,864) 128,534 -
long-term debt
Short-term borrowings - Net 3,500 1,000 (2,000)
Long-term debt retirement (70) (140,069) (519)
Preferred stock retirement (168) (26,530) (151)
Dividends on preferred stock (5,531) (7,850) (7,888)
Dividends on common stock (69,886) (69,923) (69,967)
Other sources/uses 431 (4,144) (781)
Net cash used in financing (76,588) (61,982) (81,306)
activities
INVESTING ACTIVITIES:
Additions to utility plant (94,499) (93,645) (83,965)
Conservation (2,104) (3,839) (5,688)
Increase in investments - (20,153) -
Other (1,229) 4,664 3,259
Net cash used in investing (97,832) (112,973) (86,394)
activities
Change in cash and cash (1,023) (540) 720
equivalents
Cash and cash equivalents 7,928 8,468 7,748
beginning of year
Cash and cash equivalents $ 6,905 $ 7,928 $ 8,468
end of year
RECONCILIATION OF NET INCOME TO NET
CASH PROVIDED BY OPERATING
ACTIVITIES:
Net income $ 92,274 $ 90,618 $ 86,921
Adjustments to reconcile net
income to net cash:
Depreciation 71,973 69,705 67,415
Deferred income taxes 7,065 7,201 11,698
Investment tax credit - Net (1,087) 776 (1,086)
Allowance for funds used (537) (399) (1,425)
during construction
Postretirement benefits (7,574) 1,340 (2,857)
funding (excl pensions)
Changes in operating assets
and liabilities:
Accounts receivable (70,384) 866 (7,279)
Fuel inventory 4,459 1,432 (1,753)
Accounts payable 75,568 (4,113) 8,420
Taxes accrued 6,991 1,895 (985)
Interest accrued 2,032 1,101 30
Other - Net (7,383) 3,993 9,321
Net cash provided by $173,397 $174,415 $168,420
operating activities
The accompanying notes are an integral part of these statements.
IDAHO POWER COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Principles of Consolidation - The consolidated financial
statements include the accounts of the Company and its wholly-
owned or controlled subsidiaries. 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 have 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 1997, 1996, and 1995 were 5.8 percent, 6.1 percent and
6.1 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.
Under terms and conditions of the Regulatory Settlement with the
Idaho Public Utilities Commission, (IPUC), 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. In 1997 and 1996, the Company set aside
approximately $8.7 million and $4.9 million of revenues for the
benefit of its Idaho customers.
Power Cost Adjustment - The Company has a Power Cost Adjustment
(PCA) mechanism that provides for annual adjustments to the rates
charged to Idaho retail customers. These adjustments are based
on forecasts of net power supply costs, and take effect annually
on May 16. The difference between the actual costs incurred and
the forecasted costs are deferred, with interest, and trued-up in
the next annual rate adjustment.
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 2.93 percent in 1997, 2.89 percent in 1996 and 2.90
percent in 1995 and are considered adequate to amortize the
original cost over the estimated service lives of the properties.
Gas Operations -The Company intends to be a competitive energy
provider, including both electricity and gas. In April 1997 the
Company opened a gas trading office in Houston, Texas to serve
the southern and eastern United States gas markets and a Boise,
Idaho office that serves the Northwest and Canadian markets. The
following table shows gas trading activities for the year ended
December 31, 1997 (thousands of dollars):
Gas revenues $127,874
Cost of gas (127,788)
Administrative and general expenses (1,267)
Gas trading activities - Net $ (1,181)
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, 1996 or 1997.
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 and market
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. These statutory and
conforming regulations may result in increased wholesale and retail
competition. Due to the Company's low cost structure, it is well
positioned to compete in the evolving utility market place. However,
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 1997,1996 and 1995:
1997 1996 1995
Assets Liabilities Assets Liabilities Assets Liabilities
(Millions of Dollars)
Income taxes $201.7 $ 34.1 $201.1 $ 35.0 $206.2 $ 34.6
Conservation 42.4 - 40.3 - 36.3 -
Employee benefits 6.5 - 7.4 - 8.3 -
PCA deferral and 16.6 - 9.6 - 2.1 -
amortization
Other 24.7 0.5 32.2 0.6 21.6 0.7
Deferred investment - 70.2 - 71.3 - 70.5
tax credits
Total $291.9 $104.8 $290.6 $106.9 $274.5 $105.8
At December 31, 1997, the Company had $17.0 million of regulatory
assets that were not earning a return on investment excluding the
$201.7 million that relates to income taxes.
In the event that recovery of costs 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.
Derivative Financial Instruments - Idaho Power uses financial
instruments such as commodity futures, options and swaps to hedge
against exposure to commodity price risk in the electricity and
natural gas markets. The objective of the Company's hedging
program is to mitigate the risk associated with the purchase and
sale of natural gas and electricity. The Company's accounting
for derivative financial instruments that are used to manage risk
is in accordance with the concepts established in SFAS No. 80
Accounting for Futures Contracts, American Institute of Certified
Public Accountants Statement of Position 86-2, Accounting for
Options; and various EITF pronouncements.
Deferral (hedge) accounting is used if certain hedging criteria
are met and is applied only if the derivative reduces the risk of
the underlying hedged item and is designated at inception as a
hedge with respect to the hedged item. Additionally, the derivative
must result in payoffs that are expected to be inversely correlated
to those of the hedged item.
Gains and losses from derivatives that reduce the commodity price
risk related to electricity are recognized as purchased power
expenses when the hedged transaction occurs. Gains and losses
from derivatives that reduce the commodity price risk related to
natural gas are recognized as a component of gas trading
activities when the hedged transaction occurs. Cash flows from
derivatives are recognized in the statement of cash flows and are
in the same category as that of the hedged item.
Company policy also allows the use of financial instruments noted
above for trading purposes in support of Company operations.
Gains or losses on financial instruments that are used for
trading purposes, or otherwise do not qualify for hedge
accounting, are recognized in income on a current basis. At
December 31, 1997, open trade equity on future positions was
immaterial.
As the Company increases its level of trading it is exposed to
increasing potential for credit risk in the event of non-
performance by counterparties . The Company monitors this risk
and has established guidelines to mitigate this risk.
New Accounting Pronouncements - In June 1997, the FASB issued
SFAS No. 130, Reporting Comprehensive Income and No. 131,
Disclosures about Segments of an Enterprise and Related
Information. These statements are effective for financial
statements beginning after December 15, 1997. SFAS No. 130
establishes standards for reporting and display of comprehensive
income and its components in a full set of general purpose
financial statements. SFAS No. 131 redefines standards for the
way that public business enterprises report information about
operating segments in annual and interim financial statements.
The Company is reviewing these statements to determine their
affect on its reporting requirements.
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 1997 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 1997 1996 1995
statutory federal income tax (Thousands of Dollars)
rate and the effective rate is as
follows:
Computed income taxes based on
statutory federal income tax rate $ 48,561 $ 49,949 $ 47,367
Change in taxes resulting from:
Investment tax credits (2,887) (2,835) (2,837)
Repair allowance (2,800) (2,800) (3,150)
Current state income taxes 3,587 2,823 3,275
Depreciation 5,766 5,945 5,493
Affordable housing tax (4,519) (1,777) -
credits
Other (1,236) 787 (1,736)
Total provision for federal and $ 46,472 $ 52,092 $ 48,412
state income taxes
Effective tax rate 33.5 % 36.5 % 35.8 %
The provision for income taxes
consists of the following:
Income taxes currently payable:
Federal $ 35,038 $ 40,379 $ 33,456
State 5,456 3,746 4,503
Total 40,494 44,125 37,959
Income taxes deferred - Net of
amortization:
Federal 6,717 6,877 10,904
State 348 314 635
Total 7,065 7,191 11,539
Investment tax credits:
Deferred 1,800 3,611 1,751
Restored (2,887) (2,835) (2,837)
Total (1,087) 776 (1,086)
Total provision for income $ 46,472 $ 52,092 $ 48,412
taxes
The tax effects of significant
items comprising the Company's
net deferred tax liability
are as follows:
Deferred tax assets:
Regulatory liability $ 34,072 $ 35,028 $ 34,554
Advances for construction 18,665 17,736 14,823
Other 16,536 13,550 10,498
Total 69,273 66,314 59,875
Deferred tax liabilities:
Property, plant and equipment 251,938 245,652 237,655
Regulatory asset 201,685 201,093 206,156
Investment tax credit 70,196 71,283 70,507
Conservation programs 14,377 13,720 11,746
Other 28,173 22,136 18,489
Total 566,369 553,884 544,553
Net deferred tax liabilities $ 497,096 $ 487,570 $ 484,678
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 1997,
1996 and 1995 were as follows:
Common Stock
$2.50 Premium on
Shares Par Value Capital Stock
(Thousands of Dollars)
Balance at December 31, 1994 37,612,351 $94,031 $363,063
Gain on reacquired 4% - - 117
preferred stock
Restricted stock plan - - (136)
Balance at December 31, 1995 37,612,351 94,031 363,044
Gain on reacquired 4% - - 83
preferred stock
Restricted stock plan - - (102)
Preferred stock redemption - - (728)
Balance at December 31, 1996 37,612,351 94,031 362,297
Gain on reacquired 4% - - 104
preferred stock
Restricted stock plan - - (73)
Balance at December 31, 1997 37,612,351 $94,031 $362,328
As of December 31, 1997, 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, 1997, 1996 and 1995 were as follows:
Shares Outstanding at Call Price
December 31, Per Share
1997 1996 1995
Preferred stock:
Cumulative, $100 par value:
4% preferred stock
(authorized 215,000 shares) 166,972 169,753 171,813 $104.00
Serial preferred stock,
7.68% Series (authorized 150,000 150,000 150,000 $102.97
(150,000 shares)
Serial preferred stock,
cumulative, without
par value; total of
3,000,000 shares authorized:
8.375% Series, $100 stated
value,(authorized 250,000 - - 250,000
shares)
7.07% Series, $100 stated
value, (authorized 250,000 250,000 250,000 250,000 $103.535 to $100.00
shares) (a)
Auction rate preferred
stock, $100,000 stated 500 500 500 $100,000.00
value, (authorized 500
shares)(b)
Total 567,472 570,253 822,313
(a) The preferred stock is not redeemable prior to July 1, 2003.
(b) Dividend rate at December 31, 1997 was 4.29% and ranged
between 3.93% and 4.29% during the year.
During 1997, 1996 and 1995 the Company reacquired and retired
2,781; 2,060; and 2,743 shares of 4% preferred stock resulting in
a net addition to premium on capital stock of $104,202; $82,900;
and $117,346; respectively. As of December 31, 1997 the overall
effective cost of all outstanding preferred stock was 5.66
percent.
On November 7, 1996, the Company redeemed the $25,000,000
principal amount of 8.375% Series, serial preferred stock without
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 $970,000 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
2002 are $30,000,000 in 1998, $0 in 1999, $80,000,000 in 2000,
$30,000,000 in 2001 and $27,000,000 in 2002. 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 $25,000,000 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, 1997, 1996
and 1995 the overall effective cost of all outstanding first
mortgage bonds and pollution control revenue bonds was 7.84
percent, 7.73 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 $758,221,000 in 1997,
$773,760,000 for 1996 and $731,168,000 for 1995. The total
estimated fair value of investments and other property was
$54,122,000 in 1997, $36,502,000 in 1996 and $16,826,000 in 1995.
The estimated fair values for long-term debt and investments are
based upon quoted market prices of the same or similar issues.
7. NOTES PAYABLE:
At January 1, 1998, 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 pays 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,
1997 1996 1995
(Thousands of Dollars)
Balance at end of year $57,516 $54,016 $53,020
Effective annual interest rate 6.1 % 5.7 % 6.0 %
at end of year
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 $3.1 million at December 31, 1997. 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, 1997, the Company
purchased 935,347 (MWH) at a cost of $56.0 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 maintains annual incentive plans
for its employees tied to corporate performance goals approved by
the Compensation Committee of the Board of Directors. For the
years 1997, 1996 and 1995 total incentive incurred for the plans
was $6,313,078, $2,467,334 and $2,898,785, respectively.
Restricted Stock Plan - The Company applies APB Opinion No. 25
and related interpretations in accounting for its plans.
Statement of Financial Accounting Standards No. 123 "Accounting
for Stock-Based Compensation" (SFAS 123) was issued and, if fully
adopted, changes the method for recognition of cost on plans
similar to those of the Company. Adoption of the fair value
based method of accounting provisions of SFAS 123 is optional;
however, proforma disclosures as if the Company adopted this
method are required.
In 1994 a Restricted Stock Plan ("Plan") approved by the
Company's shareholders was implemented January 1, 1995 as an
equity-based long-term incentive plan. At December 31, 1997,
there were 370,000 shares of common stock reserved for the Plan.
Grants are made to certain key employees. Each grant has a three-
year restricted period with final award amounts depending on the
attainment by the Company of a cumulative earnings per share
performance goal.
Restricted stock awards are compensatory awards and the Company
accrues compensation expense (which is charged to operations)
based upon the market value of the granted shares. For the years
1997, 1996 and 1995, total compensation accrued for the plan was
$538,664, $184,153 and $91,200, respectively.
A summary of restricted stock activity by the Company for the
years 1997, 1996 and 1995 is as follows:
1997 1996 1995
Shares outstanding January 1, 18,140 9,120 -
Shares granted in January 20,225 9,740 9,480
Shares forfeited - (720) (360)
Shares issued - - -
Shares outstanding - end of
year 38,365 18,140 9,120
Weighted average fair value
of stock on grant date $ 31.25 $ 30.25 $ 24.25
Had compensation cost for the Company's grants of restricted
stock been determined consistent with the fair value based method
provisions of SFAS 123, the Company's net income, earnings on
common stock and earnings per share of common stock for 1997,
1996 and 1995 would not be significantly different from such
amounts as reported.
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 or
1997 but funded $5.9 million in 1995. 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 $24.7 million as of December 31, 1997.
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 1997 1996 1995
Pension plan: (Thousands of Dollars)
Service cost $ 6,152 $ 6,273 $ 5,167
Interest cost 14,445 13,647 12,998
Actual return on plan assets (37,730) (30,214) (45,990)
Deferred gain (loss) on plan 17,643 12,230 31,489
assets
Net cost $ 510 $ 1,936 $ 3,664
Approximate percentage
included in 66 % 67 % 65 %
operating expenses
Net deferred compensation plan
costs (gain) charged
to other income (including $ (984) $ 794 $ 37
life insurance and SFAS
No. 87 liability accrual) (a)
(a) These charges to the Income Statement include gains from the
company-owned life insurance policies of $3,409; $1,697 and
$2,320 for 1997, 1996 and 1995, respectively.
Funded status and significant assumptions as of December 31:
Pension Plan Deferred Compensation Plan
1997 1996 1995 1997 1996 1995
(Thousands of Dollars)
Actuarial present
value of benefit
obligations:
Vested benefit $170,163 $155,3463 $145,334 $ 24,657 $ 21,840 $ 21,530
obligation
Accumulated
benefit
obligation $175,779 $158,349 $150,688 $ 24,657 $ 21,840 $ 21,530
obligation
Projected benefit $224,073 $202,049 $193,133 $ 25,067 $ 22,370 $ 22,111
obligation
Plan assets at fair
value 256,893 230,479 204,760 - - -
Plan assets in
excess of (or less
than)projected 32,820 28,430 11,627 (25,067) (22,370) (22,111)
benefit obligation
Unrecognized net(gain)
loss from past
experience different (25,734) (20,995) (8,341) 5,569 4,376 4,389
from that assumed
assumed
Unrecognized prior
service cost 5,093 5,517 5,941 (1,893) (2,762) (3,097)
Unrecognized net
(asset) obligation
existing at
date of initial (1,967) (2,230) (2,493) 4,601 5,214 5,827
adoption (19.5 year
straight-line
amortization)
Minimum liability - - - (7,867) (6,298) (6,538)
adjustment
Net asset (liability)
included in the $ 10,212 $ 10,722 $ 6,734 $(24,657) $(21,840) $(21,530)
balance sheet
Discount rate to
compute projected
benefit obligation 7.10% 7.35% 7.25% 7.10% 7.35% 7.25%
Rate for future
compensation 4.5 4.5 4.5 4.5 4.5 4.5
increases
Expected long-term
rate of return on
plan assets 9.0 9.0 9.0 - - -
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 $2,411,324 in 1997, $2,285,904
in 1996 and $2,426,840 in 1995.
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 1997, 1996 and 1995 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:
1997 1996 1995
(Thousands of Dollars)
Postretirement Benefit Cost:
Service Cost $ 713 $ 794 $ 763
Interest Cost 3,029 3,172 3,571
Actual return on plan assets (1,511) (1,410) (1,116)
Amortization of transition 2,040 2,040 2,040
obligation (20-year amortization)
Net amortization and deferral (327) (57) -
Regulatory assets - - 506
Voluntary severance program - - 64
Net cost $ 3,944 $ 4,539 $ 5,828
Funded Status:
Accumulated postretirement benefit $(43,459) $(44,439) $(48,928)
obligation (APBO)
Plan assets at fair value 19,493 17,341 15,920
APBO in excess of plan assets (23,966) (27,098) (33,008)
Unrecognized prior service cost (1,127) - -
Unrecognized gain/losses (8,910) (6,496) 378
Unrecognized transition obligation 30,600 32,640 34,680
Prepaid/(accrued) postretirement $ (3,403) $ (954) $ 2,050
benefit cost
Discount rate 7.35 % 7.50 % 7.50 %
Medical and dental inflation rate 6.75 6.75 6.75
Long-term plan assets expected 9.0 9.0 9.0
return
A one percent change in the medical inflation rate would change
the APBO by 7.0 percent and the post retirement expense for 1997
by 8.7 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 $462,000 in
1997, $1,390,800 in 1996 and $1,754,300 in 1995. The Company was
not required to contribute to the plan in 1996 or 1997 but funded
$916,200 in 1995 which was 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.
Postemployment 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 $3.1 million and a
regulatory asset of $2.6 million which represents the costs
associated with post employment benefits at December 31, 1997.
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 1997, 1996 and 1995.
1997 1996 1995
(Thousands of Dollars)
Production $1,333,768 $1,323,090 $1,350,239
Transmission 378,190 371,123 330,812
Distribution 715,091 688,232 648,549
General and Other 178,648 155,120 152,230
Total In Service 2,605,697 2,537,565 2,481,830
Less accumulated provision 942,400 886,885 830,615
for depreciation
In Service - Net $1,663,297 $1,650,680 $1,651,215
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, 1997 are as follows:
Company Ownership
Electric Accumulated
Name of Plant Location Plant In Provision for % MW
Service Depreciation
(Thousands of
Dollars)
Jim Bridger Rock Springs, $ 382,886 $ 178,781 33 693
Units 1-4 WY
Boardman Boardman, OR 61,098 30,046 10 53
Valmy Units 1 Winnemucca, NV 299,763 121,140 50 261
and 2
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 $40,712,000 in
1997, $34,974,000 in 1996 and $44,278,000 in 1995.
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 $ 9,776,000 in
1997 $8,953,000 in 1996 and $8,696,000 in 1995.
INDEPENDENT AUDITORS' REPORT
To The Board of Directors and Shareowners
Idaho Power Company
Boise, Idaho
We have audited the accompanying consolidated financial
statements of Idaho Power Company and its subsidiaries listed in
the accompanying index to financial statements and financial
statement 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
schedule 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, 1997, 1996 and
1995, 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 30, 1998
IDAHO POWER COMPANY
SUPPLEMENTAL FINANCIAL INFORMATION, UNAUDITED
QUARTERLY FINANCIAL DATA:
The following unaudited information is presented for each quarter
of 1997, 1996 and 1995 (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
1997
Revenues $155,447 $166,975 $217,174 $208,908
Income from operations 59,073 41,778 43,877 40,025
Income taxes 16,361 9,126 10,715 10,270
Net income 30,380 20,042 21,141 20,715
Dividends on preferred 1,394 665 1,422 1,696
stock
Earnings on common stock 28,986 19,377 19,719 19,019
Earnings per share of 0.77 0.52 0.52 0.51
common stock
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 1,952 1,927 1,954 1,632
stock
Earnings on common stock 28,259 21,106 17,197 16,593
Earnings per share of 0.75 0.56 0.45 0.44
common stock
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 2,026 2,006 1,976 1,982
stock
Earnings on common stock 18,701 15,582 21,795 22,851
Earnings per share of 0.50 0.41 0.58 0.61
common stock
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, 1997.
(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)(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)(ii) 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
*4(b) Instruments relating to American
Falls bond guarantee. (see Exhibits
10(f) and 10(f)(i)).
Exhibit File Number As Exhibit
*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).
*4(e)(i) Amendment, dated as of January 30,
1998, related to agreement filed as
exhibit 4(e).
*4(f) Agreement and Plan of Exchange
dated as of February 2, 1998
between Idaho Power Company, and
Idaho Power Holding Company.
*10(a) 2-51762 5(a) Agreement, dated April 20, 1973,
between the Company and FMC
Corporation.
*10(a)(i) 2-57374 5(b) Letter Agreement, dated October 22,
1975, relating to agreement filed
as Exhibit 10(a).
*10(a)(ii) 2-62034 5(b)(i) Letter Agreement, dated
December 22, 1976, relating to
agreement filed as Exhibit 10(a).
*10(a)(iii) 33-65720 10(a) Letter Agreement, dated
December 11, 1981, relating to
agreement filed as Exhibit 10(a).
*10(b) 2-49584 5(b) Agreements, dated September 22,
1969, between the Company and
Pacific Power & Light Company
relating to the operation,
construction and ownership of the
Jim Bridger Project.
*10(b)(i) 2-51762 5(c) Amendment, dated February 1, 1974,
relating to operation agreement
filed as Exhibit 10(b).
*10(c) 2-49584 5(c) Agreement, dated as of October 11,
1973, between the Company and
Pacific Power & Light Company.
*10(d) 2-49584 5(d) Agreement, dated as of October 24,
1973, between the Company and Utah
Power & Light Company.
*10(d)(i) 2-62034 5(f)(i) Amendment, dated January 25, 1978,
relating to agreement filed as
Exhibit 10(d).
*10(e) 33-65720 10(b) Coal Purchase Contract, dated as of
June 19, 1986, among the Company,
Sierra Pacific Power Company and
Black Butte Coal Company.
*10(f) 2-57374 5(k) Contract, dated March 31, 1976,
between the United States of America
and American Falls Reservoir
District, and related Exhibits.
*10(f)(i) 33-65720 10(c) Guaranty Agreement, dated March 1,
1990, between the Company and West
One Bank, as Trustee, relating to
$21,425,000 American Falls
Replacement Dam Bonds of the
American Falls Reservoir District,
Idaho.
Exhibit File Number As Exhibit
*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).
*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.
Exhibit File Number As Exhibit
*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 1-3198 10(n)(iv) The Revised Security Plans for
Form 10-K Senior Management Employees and for
for 1996 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 States of America
Department of Energy acting by and
through the Bonneville Power
Administration, and the Company.
*10(p) 33-65720 10(g) Power Sales Contact, dated
August 25, 1981, including
amendments, among the United States
of America Department of Energy
acting by and through the Bonneville
Power Administration, and the
Company.
*10(q) 33-65720 10(h) Framework Agreement, dated October
1, 1984, between the State of Idaho
and the Company relating to the
Company's Swan Falls and Snake River
water rights.
*10(q)(i) 33-65720 10(h)(i) Agreement, dated October 25, 1984,
between the State of Idaho and the
Company relating to the agreement
filed as Exhibit 10(q).
*10(q)(ii) 33-65720 10(h)(ii) Contract to Implement, dated October
25, 1984, between the State of Idaho
and the Company relating to the
agreement filed as Exhibit 10(q).
*10(r) 33-65720 10(i) Agreement for Supply of Power and
Energy, dated February 10, 1988,
between the Utah Associated
Municipal Power Systems and the
Company.
*10(s) 33-65720 10(j) Agreement Respecting Transmission
Facilities and Services, dated
March 21, 1988 among PC/UP&L Merging
Corp. and the Company including a
Settlement Agreement between
PacifiCorp and the Company.
*10(s)(i) 33-65720 10(j)(i) Restated Transmission Services
Agreement, dated February 6, 1992,
between Idaho Power Company and
PacifiCorp.
*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.
1 Compensatory Plan
Exhibit File Number As Exhibit
*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.
10(y) Executive Employment Agreement dated
November 20, 1996 between Idaho
Power Company and Richard R. Riazzi.
12 Statement Re: Computation of Ratio
of Earnings to Fixed Charges.
12(a) Statement Re: Computation of
Supplemental Ratio of Earnings to
Fixed Charges.
12(b) Statement Re: Computation of Ratio
of Earnings to Combined Fixed
Charges and Preferred Dividend
Requirements.
12(c) Statement Re: Computation of
Supplemental Ratio of Earnings to
Combined Fixed Charges and Preferred
Dividend Requirements.
21 Subsidiaries of Registrant.
23 Independent Auditors' Consent.
27 Financial Data Schedule.
IDAHO POWER COMPANY
SCHEDULE II - CONSOLIDATED VALUATION AND QUALIFYING ACCOUNTS
Years Ended December 31, 1997, 1996 and 1995
Column A Column Column C Column D Column E
B Additions
Charged
Balance At Charged (Credited) Balance At
Beginning to to Other Deduction (1) End of Period
Classification Of Period Income Accounts
(Thousands of Dollars)
1997:
Reserves Deducted From
Applicable Assets:
Reserve for $ 1,394 $ - $ 3,384 (2) $ 3,381 $ 1,397
uncollectible accounts
Other Reserves:
Injuries and $ 1,500 $ - $ - $ - $ 1,500
damages reserve
Miscellaneous
operating reserves $ 6,648 $ 763 $11,112 $ 1,395 $17,128
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
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 12, 1998 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 12,1998
Joseph W. Marshall Chief Executive Officer
and Director
By: /s/Jan B. Packwood President and Chief "
Jan B. Packwood Operating
Officer and Director
By: /s/J. LaMont Keen Vice President, Chief "
J. LaMont Keen Financial
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
4(e)(i) Amendment, dated as of 68
January 30, 1998, related to
agreement filed as exhibit
4(e).
4(f) Agreement and Plan of 70
Exchange dated February 2,
1998 between Idaho Power
Company, and Idaho Power
Holding Company.
10(y) Executive Employment 75
Agreement dated November 20,
1996 between Idaho Power
Company and Richard Riazzi.
12 Statement Re: Computation of 97
Ratio of Earnings to Fixed
Charges
12(a) Statement Re: Computation of 98
Supplemental Ratio of
Earnings to Fixed Charges
12(b) Statement Re: Computation of 99
Ratio of Earnings to Combined
Fixed Charges and Preferred
Dividend Requirements
12(c) Statement Re: Computation of 100
Supplemental Ratio of
Earnings to Combined Fixed
Charges and Preferred
Dividend Requirements.
21 Subsidiaries of Registrant 101
23 Independent Auditors' 102
Consent.
27 Financial Data Schedule 103