10
UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
                           FORM 10-K

(Mark One)

 X   ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
     SECURITIES EXCHANGE ACT OF 1934 [FEE REQUIRED]
For the fiscal year ended December 31, 1995
OR

     TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
     SECURITIES EXCHANGE ACT OF 1934 [NO FEE REQUIRED]
For the transition period from ...........to.................
Commission file number 1-3198

                      IDAHO POWER COMPANY
     (Exact name of registrant as specified in its charter)

            IDAHO                    82-0130980
(State or other jurisdiction of   (I.R.S. Employer
incorporation or organization)  Identification No.)

1221 W. Idaho Street, Boise, Idaho   83702-5627
(Address of principal executive offices)(Zip Code)

Registrant's telephone number, including area code (208)388-2200

Securities registered pursuant to Section 12(b) of the Act:

Title of each class   Name of each exchange on which registered
Common Stock ($2.50 par value)  New York and Pacific

Securities registered pursuant to Section 12(g) of the Act:

                        Preferred Stock
                        (Title of Class)

Indicate by check mark whether the registrant (1) has filed all
reports required to be filed by Section 13 or 15(d) of the
Securities Exchange Act of 1934 during the preceding 12 months
(or for such shorter period that the registrant was required to
file such reports), and (2) has been subject to such filing
requirements for the past 90 days.

                           Yes X  No

Indicate by check mark if disclosure of delinquent filers
pursuant to Item 405 of Regulation S-K is not contained herein,
and will not be contained, to the best of registrant's knowledge,
in definitive proxy or information statements incorporated by
reference in Part III of this Form 10-K or any amendment to this
Form 10-K.

Aggregate market value of voting stock
held by nonaffiliates (January 31, 1996)          $1,182,514,000

Number of shares of common stock outstanding at February 29, 1996
37,612,351

Documents Incorporated by Reference:

Part III, Item 10 Portions of the definitive proxy statement of
          Item 11 the Registrant to be filed pursuant to
          Item 12 Regulation 14A for the 1996 Annual Meeting of
          Item 13 Shareowners to be held on May 1, 1996.

The exhibit index is located on page 69. This document contains
75 pages.

PART I


ITEM 1. BUSINESS


THE COMPANY

General -

Idaho Power Company (Company) is an electric public utility
incorporated under the laws of the state of Idaho in 1989 as
successor to a Maine corporation organized in 1915. The Company
is engaged in the generation, purchase, transmission,
distribution and sale of electric energy in an approximate 20,000-
square-mile area in southern Idaho, eastern Oregon and northern
Nevada, with an estimated population of 739,000 people. The
Company holds franchises in approximately 70 cities in Idaho and
10 cities in Oregon, and holds certificates from the respective
public utility regulatory authorities to serve all or a portion
of 28 counties in Idaho, 3 counties in Oregon and 1 county in
Nevada. The Company's results of operations, like those of
certain other utilities in the Northwest, can be significantly
affected by changing weather, precipitation and streamflow
conditions. Variations in energy usage by ultimate customers
occur from year to year, from season to season and from month to
month within a season, primarily as a result of weather
conditions. With the implementation of a power cost adjustment
mechanism (PCA) in the Idaho jurisdiction, which includes a major
portion of the operating expenses with the largest variation
potential (net power supply costs), the Company's future
operating results will be more dependent upon general regulatory,
economic, temperature conditions, and successful implementation
of Company strategic plans and less on precipitation and
streamflow conditions. As of December 31, 1995, the Company
supplied electric energy to 340,708 general business customers
and employed 1,626 people in its operations (1,522 full-time).

The Company operates 17 hydro power plants and shares ownership
in three coal-fired generating plants (see Item 2-"Properties").
The Company relies heavily on hydroelectric power for its
generating needs and is one of the nation's few investor-owned
utilities with a predominantly hydro base. The Company has
participated in the development of thermal generation in the
neighboring states of Wyoming, Oregon and Nevada using low-sulfur
coal from Wyoming and Utah.

For the twelve months ended December 31, 1995, total system
electric revenues from residential customers accounted for 35
percent of the Company's total operating revenues. Commercial
customers with less than 1,000 kW demand including street
lighting customers accounted for 19 percent, industrial customers
with 1,000 kW demand and over accounted for 20 percent and
irrigation customers accounted for 10 percent. Public utilities
and interchange arrangements accounted for 11 percent and other
operating revenues accounted for 5 percent.

The Company's principal commercial and industrial revenues are
from sales of electric power to customers involved in elemental
phosphorus production; food processing, preparation and freezing
plants; phosphate fertilizer production; electronics and general
manufacturing facilities; lumber; beet sugar refining; and
electric loads associated with the year-round recreational
business, such as lodges, condominiums, ski lifts and other
related facilities, including those at the Sun Valley resort
area.

The Company has four large special contract customers in its
Idaho retail jurisdiction - the Idaho National Engineering
Laboratory (INEL), the J. R. Simplot Company, FMC Corporation
(FMC) and Micron Technology, Inc. (Micron). The rates charged
these customers under their contracts are subject to the
jurisdiction of the Idaho Public Utilities Commission (IPUC). The
Company has contracts to supply up to 45 megawatts of capacity
and energy to the INEL in eastern Idaho, up to 38 megawatts of
capacity and energy to the J. R. Simplot Company for its chemical
fertilizer operations plant near Pocatello, Idaho and 60
megawatts (this amount escalates to 100 megawatts at July 1997)
of capacity and energy to Micron located in Boise. The contracts
for J.R. Simplot and Micron expire in different years but are
automatically renewed until one party gives notice of final
termination.  The contract for INEL does expire in 1996 and the
Company will be negotiating a new contract prior to that time.

Since 1948, the Company has supplied capacity and energy to FMC
for its elemental phosphorus production plant near Pocatello,
Idaho. Under an agreement effective on January 1, 1974, the
maximum amount of power that FMC may schedule is 250 megawatts.
The agreement is subject to renewal by FMC every two years as to
one-fourth of the power deliveries and contains annual minimum
payment guarantees giving consideration to FMC's ability to
decrease its electric demands during periods in which the Company
may request reductions specified in the agreement. Revenues from
FMC were approximately $34.5 million for energy supplied during
the twelve months ended December 31, 1995.


Competition -

Competition is increasing in the electric utility industry, due
to a variety of developments including the National Energy Policy
Act of 1992, FERC Rulemakings, state initiatives, customer
demands, etc. In response to increasing competition, the Company
maintains an active strategic planning process. The goal of this
process is to anticipate and fully integrate into Company
operations any legislative, regulatory, environmental,
competitive, or technological changes. With its low average
energy production costs, the Company is well-positioned to enter
a more competitive environment and is taking action to preserve
its low-cost competitive advantage. (see Part II, Item 7.
Management's Discussion and Analysis of Financial Condition and
Results of Operations - Competition and Strategic Planning.)

With its predominantly hydro base and low-cost thermal plants,
the Company is one of the lowest cost producers of electric
energy among the nation's investor-owned utilities. Through its
interconnections with Bonneville Power Administration (BPA) and
other utilities, the Company has access to all the major electric
systems in the West.

Some industrial and large commercial customers have the ability
to own and operate facilities to generate their own electric
energy and if such facilities are qualifying facilities, can
require the displaced electric utility to purchase the output of
such facilities at a state regulatory commission established
"avoided cost" rate (see "Rates"). The Company's rates for its
industrial customers (1,000 kW and over), excluding special
contracts, average approximately 2.9 cents per kilowatt hour (see
"Power Supply"). Some of these customers are converting waste
heat to electricity for sale to the Company while purchasing
their entire power needs at the Company's lower rates. The
Company's rates for its commercial customers (under 1,000 kW)
average approximately 4.0 cents per kilowatt hour.

The legislatures and/or the regulatory commissions in several
states have considered or are considering "retail wheeling."
Retail wheeling means the movement of electric energy produced by
another entity over an electric utility's transmission and
distribution system, to a retail customer in what was the
utility's service territory. A requirement to transmit directly
to retail customers would permit retail customers to purchase
electric capacity and energy from the electric utility in the
service area they are located or from any other electric utility
or independent power supplier.

The Idaho Legislature has not yet addressed retail wheeling but
the IPUC has started an issues dialogue process and has
established workshops for discussing retail wheeling issues among
the affected parties. The Company believes with its low-cost
energy production it is well-positioned to compete in a retail
wheeling environment if retail wheeling is adopted by one or more
of the Western states (see "Regulation").


Subsidiaries -

The Company has five wholly-owned subsidiary companies:  Ida-West
Energy Company (Ida-West), Idaho Energy Resources Co. (IERCo),
Idaho Utility Products Company (IUPCo), IDACORP, INC., and
Stellar Dynamics.

Ida-West was formed in 1989 to participate through partnership
interests in cogeneration and small power production (CSPP)
projects. Ida-West owns, through various partnerships, 50 percent
of five Idaho hydroelectric projects with a total generating
capacity of approximately 34 megawatts (MW). Third parties
unaffiliated with Ida-West own the remaining 50 percent of these
projects, thus satisfying the "qualifying facility" status under
Public Utility Regulatory Policy Act of 1978 (PURPA) guidelines.
The partnerships have obtained project financing (non-recourse to
the Company) for each of these facilities. Power purchased from
these facilities amounted to approximately $8.7 million in 1995.
To date, all power sales made by Ida-West have been to the
Company.

The Company has invested $20 million in Ida-West. Ida-West
continues to actively seek to develop new projects. (see Part II,
Item 7. Management's Discussion and Analysis of Financial
Condition and Results of Operations - Subsidiaries.)

IERCo has been in operation since 1974. Its primary purpose is to
participate as a joint venturer in the Bridger Coal Company,
which operates the mine supplying coal to the Jim Bridger plant
near Rock Springs, Wyoming (see "Fuel"). As of December 31, 1995,
the Company's total investment in IERCo was $5.6 million.

IDACORP, INC was organized in 1986 to pursue a non-regulated
diversification program. At the end of 1995 IDACORP was
participating in three affordable housing programs which provide
a return primarily by reducing federal income taxes through tax
credits and tax depreciation benefits. IUPCo was formed in 1983
to develop and market products to the utility industry. As of
December 31, 1995, the combined total investment in these
subsidiaries was $3.3 million.

Stellar Dynamics was formed in 1995 to commercialize the
Company's extensive expertise in control technology for electric
substations and power plants. Today, the market focus lies in the
integration of complex control and automation systems for both
the electric utility sector and industrial applications. Stellar
Dynamics also provides design and engineering for complete
electric substations. The geographic market for Stellar Dynamics
is mainly in the western U.S. with some emphasis in the remaining
U.S., Canada and abroad. The Company capitalized Stellar Dynamics
in January of 1996.


Research and Development and Renewable Energy Sources -

During 1995, the Company spent approximately $1.7 million on
research and development of which $1.5 million was through the
Company's membership in Electric Power Research Institute (EPRI).
EPRI's mission is to discover, develop and deliver advances in
science and technology. Some of the projects benefits to the
Company include:  electrification technologies, power quality,
electric transportation systems, EMF assessment/risk management
and air quality issues. The Company also has an internal research
and development effort called the Emerging Technology (ET)
Program. The ET program was established to maintain an active and
coordinated response to new technology of interest to the
Company.

In 1992, the Company joined Southern California Edison, the U.S.
Department of Energy and others in retrofitting an existing 10-
megawatt solar thermal experimental power plant now called Solar
Two near Barstow, California. The Company will have contributed
$630,500 by the end of 1998 and the EPRI will contribute an
additional $630,500 of matching funds, bringing the Company's
credited contribution to approximately $1.3 million. The main
benefit the Company will receive by participating in this project
is valuable experience and knowledge in solar plant design,
construction and operation.

The Company offers a Photovoltaic Service Tariff (PST) for  basic
electric service for small loads at remote sites as an
alternative to either line extensions for grid service or the use
of on-site, fossil-fuel generators. Under the PST, the customer
pays a monthly fee to receive electric service from a solar PV
system designed, installed, owned, and maintained by Idaho Power.
The program, which the Company launched in January 1993, is a
pilot offering with a $5,000,000 program limit and a $50,000
limit for individual systems. To date, Idaho Power has installed
30 solar photovoltaic (PV) systems. All of these systems are
operating as designed.

In 1994, the U.S. Air Force contracted with Idaho Power to
design, build, and maintain one of the nation's largest hybrid
solar-powered PV systems. The $1.2 million project, completed in
February 1995, provides electricity to a remote Mountain Home AFB
radar training installation near Grasmere, Idaho. Under optimal
solar conditions, the PV system produces a peak capacity of
80 kW, reducing both the need for combustion generators and the
emissions they produce. Under the terms of the contract, the
federal government owns the system and pays the Company a monthly
maintenance fee.

Through these programs, Idaho Power has gained considerable
experience in the design and maintenance of solar PV energy
systems. As a result, the Company has gained international
recognition as an industry leader in solar PV technology, and was
selected to organize and jointly host an international solar PV
conference which was held in Sun Valley, Idaho in September 1995.

The Company is studying the possible formation of a new, non-
regulated energy services company that would partner with
interested electric utilities to provide energy services to
remote locations within their service territories. This company
would work on behalf of the utilities to offer solar PV energy
systems at the lowest possible cost to the consumer. While the
domestic utility market is promising in itself, Idaho Power is
also pursuing international opportunities for its renewable
energy expertise.

Energy Efficiency -

The Company continues to promote the efficient use of electrical
energy. The Company supported legislation in Idaho that
established energy-efficient building codes for new home
construction and continues to support the adoption of even more
stringent energy codes by local government jurisdictions. In
1995, the Company expended $6.4 million on its various energy-
efficiency programs.

POWER SUPPLY

The Company is a dual-peaking system, with the larger energy peak
generally occurring in the summer. This complements the winter
peaking utilities which predominate in the Pacific Northwest.
Even though its significant hydroelectric generation can operate
to meet demand peaks, seasonal energy requirements are important
to the Company because its seasonal energy capability is
determined in part by the availability of water. In 1994, below
normal precipitation created drought conditions reducing
reservoir storage. In 1993 and 1995 however, the Company's
service territory experienced above average water years. The
system peak demand for 1995 was 2,393 megawatts set on July 28,
1995. Peak demand for 1994 and 1993 were 2,392 and 2,154
megawatts respectively.


The following table sets forth the total energy sources of the
Company for the last three years:

                                  Total Energy Sources
                                     (000's of MWH)
                       1995     %     1994     %     1993     %
Generation - net  station output -
  Hydro              9,277.2   58   6,213.2   40   8,361.7   52
  Coal-fired         4,591.9   29   7,221.8   46   6,485.5   40
Purchased and  
  interchange        2,155.9   13   2,287.0   14   1,273.8    8
     Total          16,025.0  100  15,722.0  100  16,121.0  100

In a normal water year the hydro system contributes approximately
57 percent, thermal generation accounts for 34 percent and
purchased power and other interchanges contributes the remaining
9 percent of total system requirements. Although it is too early
to predict with certainty what hydroelectric conditions will be
during 1996, preliminary reports indicate the mountain snowpack
is above normal for this time of year and the carryover reservoir
storage throughout the Snake River Basin is above average. The
Company expects to meet projected energy loads during the coming
year by utilizing its hydro and coal-fired facilities and
strategic geographic location - which provides opportunities to
purchase, sell, exchange and transmit energy.

Purchased power expenses fluctuated during the three-year period
reflecting necessity purchases from neighboring utilities during
the 1994 drought. Purchased power expenses were lower in 1995
with the return to more normal hydro conditions tempered somewhat
by economy purchases made while the market prices for off-system
sales were soft.

The Company periodically updates its load and resource
projections and now expects total Company energy requirements
over the next 10 years to grow at an annual rate of 0.8 percent.

The Company's generating facilities are interconnected through
its integrated transmission system and are operated on a
coordinated basis to achieve maximum load-carrying capability and
reliability. The transmission system of the Company is directly
interconnected with the transmission systems of the 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 Intercompany Pool, 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.

Increasing competitiveness in the electric power marketplace, the
potential ability of retail customers to choose their electric
provider and the potential for deregulation of the electric power
industry, all indicate a need for the Company to adjust its
resource acquisition policy toward a greater emphasis on resource
marketability. In order to avoid burdening the Company and its
customers with unnecessary future power supply costs and higher
rates, the Company has adopted a policy of acquiring all new
resources as close as possible to the actual time of need and
selecting the lowest cost resources meeting all of the Company's
requirements. In practice, this policy will result in the
purchase of power from others through the marketplace whenever
purchases are the lowest cost resources, and new investment in
resource ownership by the Company only when a Company-owned
resource would be cost effective in the market.

In December 1993, the Company filed with the IPUC for permission
to approve lower published prices for new CSPP contracts. In
response to the Company's filing, on January 31, 1995 the IPUC
issued an order approving lower published CSPP rates. (see Rates -
Idaho Jurisdiction and Part II, Item 7. Management's Discussion
and Analysis of Financial Condition and Results of Operations -
Regulatory Issues.)


New Projects -

Capitalizing on the Company's strategic location between the
Intermountain West and the Pacific Northwest, the Company is
considering the construction and operation of a new transmission
line that could serve as a major path for regional transfers of
power between the Northwest and desert Southwest. The Southwest
Intertie Project (SWIP) is a proposed 500-mile, 500-kV
transmission line that would interconnect the Company's system
with utilities in the Southwest. 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 utility and BLM are working on a detailed site-specific
construction, operation and maintenance plan aimed at mitigating
the environmental impact of the project. The Company intends to
retain up to a 20 percent ownership in the 1,200 megawatt line.

The Company sent participation packages to interested parties and
received capacity requests from these groups during the fourth
quarter of 1995. Ownership allocation has been completed among
the six interested parties and negotiations are in process for
the execution of the Memorandum of Agreement (MOA). At the time
of execution of the MOA, the Company is requiring each party to
pay its share of the approximately $8.5 million expended for
environmental permitting, right-of-way acquisition, and related
development activities. The SWIP owners will then form an
Executive Committee with voting rights proportional to their
share of the project. The Executive Committee will oversee
development activities for the SWIP and related projects.

The Company is positioning SWIP as an open-access transmission
opportunity for participants, in line with the Notice of Proposed
Rulemaking (NOPR) issued by the Federal Energy Regulatory
Commission (FERC).


The following tables show how the Company expects to meet its
forecast energy and peak demand requirements through 2000 from
system generation and contracted resources. Because of its
reliance upon hydroelectric generation, which varies according to
streamflows, the Company's generating system is more energy
constrained than capacity limited. Seasonal exchanges of winter-
for-summer power are included among the contracted resources to
maximize the firm load carrying capability. Exchanges are
currently made with The Montana Power Company under a 10-year
contract signed in 1987 and with Seattle City Light under an
extended contract that expires in 2003.

                                 Summer Peak Capability (MW) (a)
                               1996   1997     1998     1999    2000

Generation capability         2,681  2,681    2,681    2,681   2,681
Less net peak load            2,318  2,390    2,467    2,476   2,489
Plus contract power (b)       286      305      305      305     305
Peak capability margin        649      596      519      510     497

Percent capability margin (c)        28.0%    24.9%    21.0%   20.6%
20.0%

(a)  Based upon median hydro conditions.
(b)  Sum of exchange and CSPP contracts.
(c) Capability margin divided by the net peak load.

                                     Annual Energy Capability
                                        (000's of MWH)(a)
                            1996     1997      1998     1999    2000

Generation capability     15,246   15,187    15,476   15,530    15,726
Contracts:
  Cogeneration and small 
  power production           696      807       807      807       807
Annual firm load         (15,532) (15,635)  (16,153) (16,148)  (16,083)
Energy capability margin     410      359       130      189       450

  Percent (b)               2.6%     2.3%      0.8%     1.2%      2.8%

(a) Forecast based upon average of 67 historical water
    conditions.
(b) Energy capability margin divided by the generating
    capability. These projections have declined due to the
    Company's Bulk Power Initiative with more assumed firm sales
    replacing surplus sales and CSPP projects not coming on line.

During the 1996-2000 period, the Company plans to provide all the
energy required to serve its firm load requirements during
periods of heavy demand, reduced hydrogeneration caused by below
normal streamflow conditions, or unscheduled outages of
generating units by utilizing its hydroelectric and coal-fired
generating units and through purchases of power from neighboring
utilities or marketing entities.

CSPP Purchases -

As a result of the enactment of the PURPA and the adoption of
avoided cost standards by the IPUC, the Company has entered into
contracts for the purchase of energy from private developers.
Because the Company's service territory encompasses substantial
irrigation canal development, forest products production
facilities, mountain streams, and food processing facilities,
considerable amounts of energy are available from these sources.
Such energy comes from hydro power producers who own and operate
small plants and from cogenerators converting waste heat or steam
from industrial processes into electricity. The estimated
annualized cost for the 65 CSPP projects on-line as of December
31, 1995, is currently $45.2 million. During 1995, the Company
purchased 654.2 million kilowatt-hours of power from these
private developers at a blended price of 5.8 cents per kilowatt-
hour (see Rates).


Firm Wholesale Power Sales -

The Company has firm wholesale power sales contracts with SPPCo,
Portland General Electric Company (PGE), The Montana Power
Company (MPC), the City of Weiser, Idaho, two entities in the
state of Utah, one in the state of California and one in the
state of Oregon. These contracts are for various amounts of
energy and range from 7 to 100 average megawatts and are of
various lengths that are presently scheduled to expire between
1996 and 2009. The Company has contracts with both MPC and PGE
that expire during 1996. These contracts are for various amounts
of power depending on the time of year and range from 25 to 100
average megawatts.  The Company is actively marketing this power
to other entities as it becomes available.


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 nonfirm wheeling services for several surrounding
utilities. In November 1995, the Company filed open-access
tariffs for Point-to-Point and Network transmission service with
the FERC. The Company requested and received permission to
implement these tariffs beginning February 1, 1996.

The substance of these tariffs is to offer the same quality and
character of transmission services to anyone seeking it as the
Company utilizes in its own operation. The FERC set the proposed
rates for service under the tariffs for hearing, and the Company
may provide service at these proposed rates subject to refund.

During 1995, the Company reorganized its Power Supply Department
into power supply (generation) and power delivery (transmission)
business units to enhance the Company's ability to compete in the
wholesale electric power market and to comply with the "Standards
of Conduct" proposed by the FERC in their recent Notice of
Proposed Rulemaking.

The Company's system lies between and is interconnected to the
winter-peaking northern and summer-peaking southern regions of
the western interconnected power system. This position is
advantageous both in providing transmission service and reaching
a broad power sales market. The Company is a member of both the
Western Regional Transmission Association and the Northwest
Regional Transmission Association. These associations will help
facilitate transmission access and planning throughout the power
system.


FUEL

The Company, through Idaho Energy Resources Co., owns a one-third
interest in the Bridger Coal Company which owns the Jim Bridger
coal mine that supplies coal to the Jim Bridger generating plant
in Wyoming. The mine, located near the Jim Bridger plant,
operates under a long-term sales agreement and provides for
delivery of coal over a 51-year period that began in 1974. The
original contract of 41 years was extended for 10 years on
January 1, 1996. (see Item 2 "Properties"). The Jim Bridger Coal
Mine has sufficient reserves to provide coal deliveries pursuant
to the sales agreement. The average cost to the Company per ton
of coal burned at the Jim Bridger plant, the largest thermal
station on the Company's system, for the last three years is as
follows: 1993 - $20.99; 1994 - $19.52 and 1995 - $20.36. 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.

PGE, with whom the Company is a 10 percent participant in the
ownership and operation of the Boardman plant, has a flexible
contract with AMAX Coal Company for delivery of low sulfur coal
from its mines near Gillette, Wyoming, to Boardman Unit No. 1.
Under this contract, PGE has the option to purchase 750,000 tons
of coal annually through 1999. This agreement enables PGE and the
Company to take advantage of lower cost spot market coal for some
or all of the Boardman plant's requirements.

SPPCo, with whom the Company is a joint (50/50) participant in
the ownership and operation of the North Valmy Steam Electric
Generating plant (Valmy plant), entered into a 22-year coal
contract that began in July of 1981 with Southern Utah Fuel
Company, a subsidiary of Coastal States Energy Corporation, for
the delivery of up to 17.5 million tons of low-sulfur coal from a
mine near Salina, Utah, for Valmy Unit No. 1.

With the commercial operation of Valmy Unit No. 2 in May 1985, an
additional coal source was needed to assure an adequate supply
for both units at the Valmy plant. Accordingly, in 1986 the
Company and SPPCo signed a long-term coal supply agreement with
the Black Butte Coal Company. This contract provides for Black
Butte to supply coal to the Valmy project under a flexible
delivery schedule that allows for variations in the number of
tons to be delivered ranging from a minimum of 200,000 tons per
year to a maximum of 1,150,000 tons per year. This flexibility
will accommodate fluctuations in energy demands, hydroelectric
generating conditions and purchases of energy from CSPP
facilities.

WATER RIGHTS

The Company, except as otherwise stated herein, has valid water
rights, unlimited as to time, to the waters used in its
generating stations, which were obtained under applicable
provisions of state law. Such rights, however, are subject to
prior rights and, with respect to license provisions of certain
hydroelectric facilities and water licenses, are subject to
future upstream diversion of water for irrigation and other
consumptive use.

Over time, increased irrigation and other consumptive diversions
on the Snake River have resulted in some reduction in the
streamflows available for the Company's hydroelectric generating
facilities. In this regard, the Company has pursued a course of
action to determine and protect its water rights and their
priority consistent with the settlement agreements negotiated
with the state of Idaho signed on October 25, 1984. In 1987,
Congress passed and the President signed into law House Bill 519
which permitted implementation of the agreements and provided
that the FERC would accept the settlement agreements and that the
settlement was consistent with the terms of hydroelectric
licenses and was prudent for the purpose of determining rates
under Section 205 of the Federal Power Act during the remaining
term of certain project licenses on the Snake River.

In 1987, the Idaho Department of Water Resources filed a petition
in state district court commencing the Snake River Basin
Adjudication. This proceeding was initiated pursuant to state
statute and a determination by the Idaho Legislature that the
effective management of the Snake River basin required a
comprehensive determination of the nature, extent and priority of
all water users. The adjudication is still in its early stages,
and the process will likely continue past the turn of the
century. The Company has filed claims to its water rights within
the basin and is participating in the adjudication to insure that
its operations and water rights are not adversely impacted. The
Company does not anticipate any modification of its water rights
as a result of the adjudication process.

REGULATION

The Company is not in direct competition with any electric public
utility company or municipality within its service territory. The
Company is under the regulatory jurisdiction (as to rates,
service, accounting and other general matters of utility
operation) of the FERC, the IPUC, the Oregon Public Utilities
Commission (OPUC) and the Public Service Commission of Nevada.
The Company is also under the regulatory jurisdiction of the
IPUC, OPUC and the Public Service Commission of Wyoming as to the
issuance of securities. The Company is subject to the provisions
of the Federal Power Act as a "licensee" and "public utility" as
therein defined. The Company's retail rates are established under
the jurisdiction of the state regulatory agencies and its
wholesale and transmission rates are regulated by the FERC (see
"Rates"). Pursuant to the requirements of Section 210 of the
PURPA, the state regulatory agencies have each issued orders and
rules regulating the Company's purchase of power from CSPP
facilities.

As a licensee under the Federal Power Act, the Company and its
licensed hydroelectric projects are subject to the provisions of
Part I of the Act. All licenses are subject to conditions set
forth in the Act and regulations of the FERC thereunder,
including, but not limited to, provisions relating to
condemnation of a project upon payment of just compensation,
amortization of project investment from excess project earnings,
possible takeover of a project after expiration of its license
upon payment of net investment, severance damages, and other
matters.

The state of Oregon has a Hydroelectric Act providing for
licensing of hydroelectric projects in that state. The Company's
Brownlee, Oxbow and Hells Canyon facilities are on the Snake
River where it forms the boundary between Idaho and Oregon and
occupy land located in both states. These facilities are subject,
with respect to project property located in Oregon, to such
provisions of the Oregon Hydroelectric Act. The Company has
obtained Oregon licenses for these facilities and these licenses
are not in conflict with the Federal Power Act or the Company's
FERC license (see Item 2. Properties).

ENVIRONMENTAL REGULATION

Environmental controls at the federal, state, regional and local
levels are having a continuing impact on the Company's operations
due to the cost of installation and operation of equipment
required for compliance with such controls and the modification
of system operations to accommodate such regulation.

Based upon the requirements of present environmental laws and
regulations, the Company estimates its capital expenditures
(excluding allowance for funds used during construction) for
environmental matters for 1996 and during the period 1997-2000
will total approximately $0.6 million and $24.9 million,
respectively. Mitigation of environmental concerns due to
relicensing of hydro facilities will be a major portion of these
expenditures. The Company also anticipates spending approximately
$24 million a year in operating expenses for environmental
facilities during the 1996-2000 period. However, to the extent
regulations under federal and state environmental protection
laws, as well as the laws themselves, are changed, costs for
compliance with such laws and regulations in connection with the
Company's existing facilities and facilities under construction
are subject to change in an amount not determinable.

Air -

The Company continues to monitor Clean Air Act legislation and
its effects upon the Company and its ratepayers. The Company's
coal-fired plants in Nevada and Oregon already meet the federal
emission rate standards for sulfur dioxide (SO2) and the
Company's coal-fired plant in Wyoming meets that state's even
more stringent SO2 regulations. The Company anticipates no
material adverse effect upon its operations. The Company has
entered into a joint arrangement with PacifiCorp and Black Hills
Corporation under which certain of these companies generating
units have been accepted by the Environmental Protection Agency
as "Substitution" units for the Baldwin #2 unit owned by Illinois
Power Company. In exchange for Illinois Power naming units at the
Jim Bridger Station as "Substitution" units for Baldwin #2, the
Company sold Illinois Power a portion of the Phase I SO2
Allowances it received by having its share of the Jim Bridger
units accepted as Phase I "Substitution" units.

Water -

The Company has received National Pollutant Discharge Elimination
System Permits, as required under the Federal Water Pollution
Control Act Amendments of 1972, for the discharge of effluents
from its hydroelectric generating plants.

The state of Oregon Department of Environmental Quality
determined that the flow of water over large dams on the Columbia
and Snake Rivers could result in the supersaturation of the water
with dissolved nitrogen possibly resulting in damage to the fish
population. The Company has obtained a permit from the Oregon
Department of Environmental Quality to operate the Brownlee,
Oxbow and Hells Canyon Dams in accordance with the water quality
program of the state of Oregon.

At the Company's American Falls hydroelectric generating plant,
the Company has agreed to meet certain dissolved oxygen
standards. The Company signed amendments to the agreements
relating to the operation of the American Falls Dam and the
location of water quality monitoring facilities to provide more
accurate and reliable water quality measurements necessary to
maintain water quality standards during the May 15 to October 15
period each year downstream from the Company's plant.

The Company has also installed aeration equipment, water quality
monitors and data processing equipment as part of the Cascade
hydroelectric project to provide accurate water quality data and
increase dissolved oxygen levels as necessary to maintain water
quality standards on the Payette River.

The Company owns and finances the operation of anadromous fish
hatcheries and related facilities to mitigate the effects of its
hydroelectric dams on fish populations. In connection with its
fish facilities, the Company sponsors ongoing programs for the
control of fish disease and improvement of fish production. The
Company's anadromous fish facilities at Hells Canyon, Oxbow,
Rapid River, Pahsimeroi and Niagara Springs continue to be
operated under agreements with the Idaho Department of Fish and
Game. In 1995, the investment in these facilities was $12.1
million and the operation of these facilities pursuant to the
FERC License 1971 cost approximately $2.1 million annually.

Endangered Species -

The Company continues to review and analyze the various effects
upon its operations of the listing as threatened or endangered of
several species of salmon and Snake River mollusks. The Company
is cooperating with various governmental agencies to resolve
these issues. (see Part II, Item 7. Management's Discussion and
Analysis of Financial Condition and Results of Operation -
Environmental Issues.)

Hazardous/Toxic Wastes and Substances -

Under the Toxic Substances Control Act (TSCA), the Environmental
Protection Agency (EPA) has adopted regulations governing the
use, storage, inspection and disposal of electrical equipment
that contain polychlorinated biphenyls (PCBs). The regulations
permit the continued use and servicing of certain electrical
equipment (including transformers and capacitors) that contain
PCBs. The Company continues to meet all federal requirements of
TSCA for the continued use of equipment containing PCBs. The
Company has a program to make the 200-plus substations on its
system non-PCB. While the Company's use of equipment containing
PCBs falls well within the federal standards, the Company has
voluntarily decided to virtually eliminate these compounds from
the substation sites. This program will save costs associated
with the long-term monitoring and testing of substation equipment
and grounds for PCB contamination as well as being good for the
environment today. Total Company costs for the disposal of PCB's
from the Company's system were $0.6 million, $1.3 million and
$0.4 million for 1993, 1994 and 1995 respectively.

Electric and Magnetic Fields (EMF) -

While scientific research has yet to establish any conclusive
link between EMF and human health, the possibility has caused
public concern in the United States and abroad. Electric and
magnetic fields are found wherever there is electric current,
whether the source is a high-voltage transmission line or the
simplest of electrical household appliances. Concerns over
possible health effects have prompted regulatory efforts in
several states to limit human exposure to EMF. Depending on what
researchers ultimately discover and what regulations may be
deemed necessary, it is possible that this issue could affect a
number of industries, including electric utilities. However, at
this time it is difficult to estimate what impacts, if any, the
EMF issue could have on the Company and its operations.

RATES

Idaho Jurisdiction -

Since 1993, the Company's Power Cost Adjustment (PCA) mechanism
has allowed for it to collect, or to refund, a portion of the
differences between actual net power supply costs and those
allowed in the Company's Idaho base rates. Rates are adjusted
each May based on forecasted costs for the upcoming May-April
period. Deviations from forecasted costs are deferred with
interest and trued up the following year. With the IPUC's revenue
requirement order issued on January 31, 1995, the PCA mechanism
increased to a 90 percent recovery level from its original 60
percent. The Company filed its 1995 PCA application with the IPUC
on April 15, 1995 requesting a decrease in PCA rates for the
Idaho jurisdiction. The decrease (in effect from May 16, 1995
through May 15, 1996) was approximately $8.2 million or 1.9
percent including last year's true-up. However, PCA rates are
still in excess of base rates. At December 31, 1995, the Company
had recorded $1.0 million less in power supply costs than
projected in the 1995 forecast. The Company has deferred this
cumulative amount and will include it as a reduction in the 1996
PCA true-up.

On June 30, 1994, Idaho Power filed an application with the IPUC
to increase rates in its Idaho jurisdiction. The Company based
its application on calendar year 1993, using a thirteen-month
average rate base annualized for its new Swan Falls production
project and a year-end capitalization structure. In its
application, the Company  requested $37.1 million in general rate
relief, representing a 9.09 percent increase in rates, a 12.50
percent return on equity, and a 9.88 percent overall rate of
return. 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. IPUC
Order No. 25880 also allowed Idaho Power to realize its overall
rate structure to more closely price according to the cost to
serve different customer classes.

On May 24, 1995, Idaho Power filed another application with the
IPUC to increase rates in its Idaho jurisdiction. In August 1995,
the IPUC issued an order authorizing the Company to increase its
Idaho retail rates on an annual basis by $3.8 million (0.9
percent). This increase was uniform to all customer classes, as
well as to special contract customers. The Company originally
applied for a $6.3 million (1.5 percent) increase to recover
capital costs and related expenses associated with the
construction of a new 43.5 megawatt (MW) power plant at its Twin
Falls hydro facility, along with additional plant investments at
the Swan Falls hydro facility since the filing of its last
general rate case. The major issue in this case was whether the
reduced power supply costs resulting from the inclusion of the
Twin Falls hydro expansion would be recognized explicitly through
a reduction in base energy rates or implicitly through the PCA.
The Company reached a compromise with the IPUC staff on the
overall revenue requirement and agreed to recognize benefits up
front in base rates, instead of flowing the benefits through the
PCA. As a result, the Company's original $6.3 million request was
reduced by $1.9 million. The effect on projected Company earnings
is only 10 percent of this amount ($190,000), since all but 10
percent of the power supply cost reduction would have been passed
through to Idaho customers in the next PCA adjustment. The IPUC
action enabled the Company to begin recovering the capital costs
of a plant addition within weeks of the plant becoming
operational.

On August 3, 1995, the Company filed a proposal with the IPUC to
defer and amortize costs associated with its internal
transformation process, to accelerate amortization of regulatory
liabilities associated with accumulated deferred investment tax
credits (ADITCs) under certain conditions and to hold base rates
stable through 1998. The IPUC approved a settlement agreement
confirming the proposal, which allows the Company to accelerate
the amortization of the regulatory liabilities associated with
ADITCs whenever the Company's year-end return on equity falls
below 11.5 percent. In addition, the order allows the Company to
defer certain costs associated with its corporate reorganization
as regulatory assets and amortize them over a 10-year period.

The terms and conditions of the Order will remain in effect
through 1999. Under the Order, when the Company's actual earnings
in a given year exceed an 11.75 percent return on year-end common
equity, the Company will refund 50 percent of the excess through
its next PCA adjustment.

Other important points in the Order are: (1) the Company may
accelerate a maximum of $30 million of regulatory liabilities
associated with ADITCs over the five-year period; (2) the Company
will not be allowed to increase its Idaho general rates prior to
January 1, 2000, except under special conditions as defined in
the Settlement Agreement; and (3) Idaho Power agrees that its
quality of service will not decline as a result of corporate
reorganization. The proposed accounting treatment of deferred
investment tax credits has been submitted to the Internal Revenue
Service for approval. On November 22, 1995, the Idaho State Tax
Commission approved the accounting treatment for the Idaho
ADITCs. No accelerated ADITC was required and thus none was
utilized in 1995.

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. In
addition, the IPUC determined that negotiated rates for future
CSPP projects larger than 1 MW should be tied more closely to
values determined in the Company's integrated resource planning
(IRP) process.

Oregon Jurisdiction -

In response to the Company's April 1995 application, the OPUC
granted $1.5 million in drought-related rate relief. The OPUC
Order allows recovery of the $1.5 million through the continued
application of an existing increase authorized in July 1993 (for
1992 drought relief). The rate increase will remain in effect for
approximately 34 months beginning in July 1995. The Company had
deferred, with interest, increased power supply costs between May
1994 and December 31, 1994.

In May 1995, Idaho Power filed an application with the OPUC
seeking general rate relief of approximately $3.4 million, or a
16.65 percent increase. The Company later negotiated a Settlement
Stipulation with the OPUC staff, the Company's Oregon industrial
customers, and the Citizens Utility Board of Oregon. The
settlement grants Idaho Power a $1.3 million general rate
increase for its Oregon retail customers. The OPUC settlement
agreement became effective December 5, 1995

Other Jurisdictions -

In 1995, the Company did not file any applications for rate
relief before the FERC or in its Nevada retail jurisdiction.

CONSTRUCTION PROGRAM

The Company's construction program for the 1996-2000 period
(excluding allowances for funds used during construction) is
presently estimated to require cash funds of approximately $417.7
million as follows:

                                              1996  1997-2000(a)
                                           (Millions of Dollars)
Generating Facilities:
  Hydro                                      $   5.7 $  45.2
  Thermal                                        9.1    34.0
Total generating facilities                     14.8    79.2
Transmission lines and substations              12.8    47.8
Distribution lines and substations              42.4   146.4
General                                         20.0    51.1
  Total cash construction                       90.0   324.5
AFUDC                                             .8     2.4
  Total construction including AFUDC (b)     $  90.8 $ 326.9

(a)  Includes construction costs escalated at 1.4%, 2.2%, 3.0%
     and 3.3% annually for the years 1997-2000, respectively.
(b)  Does not include Ida-West equity investment in construction
     as Ida-West develops its construction as a participant in
     joint ventures which are not a part of the consolidated
     entity.

These estimates are subject to constant revision in light of
changing economic, regulatory and environmental factors and
patterns of conservation.

The Company has no nuclear involvement and its future
construction plans do not include development of any nuclear
generation. The Company is looking at various options that may be
available to meet the future energy requirements of its customers
which include:  (1) efficiency improvements on the Company's
generation, transmission and distribution systems, (2) purchased
power and exchange agreements with other utilities or other power
suppliers and (3) customer conservation. As additional energy
demands are placed upon the system, the project or projects best
meeting the changed requirements will be pursued.

FINANCING PROGRAM

The Company's five-year estimate of capital requirements and
sources of capital is $414.0 million outlined as follows:


                                             1996  1997-2000
                                          (Millions of Dollars)
Capital Requirements:
  Net cash construction expenditures         $  90.0   $ 324.5
  Conservation expenditures                      2.6       5.2
  Other cash expenditures                        1.4      (9.7)
     Total                                   $  94.0   $ 320.0

Sources of Capital:
  Internal generation                        $  82.6   $ 365.1
  Short-term bank loans - Net                    5.8     (41.3)
  First mortgage bonds                          30.0     110.0
  Debt repayment                               (20.6)   (112.8)
  Common stock                                   -         -
  Cash investments (increase)                   (3.8)     (1.0)
  Total (a)                                  $  94.0   $ 320.0

(a)  Does not include Ida-West financing.

These estimates are subject to constant review in light of
changing economic, regulatory and environmental factors. Any
additional securities to be sold will depend upon market
conditions and other factors, but it is the Company's objective
to maintain capitalization ratios of approximately 45 percent
common equity, 8 to 10 percent preferred stock and the balance
long-term debt. The Company will continue to take advantage of
any refinancing opportunities as they become available.

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, 1995, net earnings were 6.68
times. Additional preferred stock may be issued when earnings for
twelve consecutive months within the preceding fifteen months are
at least equal to 1.5 times (until December 31, 2000, at which
time the issuance ratio will increase to 1.75 times) the
aggregate annual interest requirements on all debt securities and
dividend requirements on preferred stock. At December 31, 1995,
the actual preferred dividend earnings coverage was 2.82 times.
If the dividends on the shares of Auction Preferred Stock were to
reach the maximum allowed, the preferred dividend earnings
coverage would be 2.59 times. The Indenture and the Company's
Restated Articles of Incorporation are exhibits to the Form 10-K
and reference is made to them for a full and complete statement
of their provisions.

ITEM 2. PROPERTIES


The Company's system includes 17 hydroelectric generating plants
located in southern Idaho and eastern Oregon (detailed below) and
an interest in three coal-fired steam electric generating plants.
The system also includes approximately 4,642 miles of high
voltage transmission lines; 21 step-up transmission substations
located at power plants; 17 transmission substations; 7
transmission switching stations; and 194 energized distribution
substations (excludes mobile substations and dispatch centers).

The Company holds licenses under the Federal Power Act for 13
hydroelectric projects from the FERC. These and the other
generating stations and their capacities are listed below:

                                  Maximum                  
                                  Non-                     
                                  Coincident  Nameplate    License
                                  Operating   Capacity kW  
                                  Capacity kW             Expiration

       Project

Properties Subject to Federal Licenses:

Lower Salmon                         70,000     60,000      1997
Bliss                                80,000     75,000      1998
Upper Salmon                         39,000     34,500      1998
Shoshone Falls                       12,500     12,500      1999
C J Strike                           89,000     82,800      2000
Upper Malad                           9,000      8,270      2004
Lower Malad                          15,000     13,500      2004
Brownlee-Oxbow-Hells Canyon       1,398,000  1,166,900      2005
Swan Falls                           25,547     25,000      2010
American Falls                      112,420     92,340      2025
Cascade                              14,000     12,420      2031
Twin Falls                           54,300     52,737      2041
Milner                               59,448     59,448      2038
                                                                
Other Generating Plants:                                        
                                                                
Other Hydroelectric                  10,400     11,300          
Jim Bridger (Coal-Fired Station)    693,333    678,077          
Valmy (Coal-Fired Station)          260,650    260,650          
Boardman (Coal-Fired Station)        53,000     53,000          

At December 31, 1995, the composite average ages of the principal
parts of the Company's system, based on dollar investment, were:
production plant, 16.3 years; transmission system and
substations, 17.6 years; and distribution lines and substations,
13.8 years. The Company considers its properties to be well
maintained and in good operating condition.

The Company owns in fee all of its principal plants and other
important units of real property, except for portions of certain
projects licensed under the Federal Power Act and reservoirs and
other easements, subject to the lien of its Mortgage and Deed of
Trust and the provisions of its project licenses, and to minor
defects common to properties of such size and character that do
not materially impair the value to, or the use by, the Company of
such properties.

As a result of various federal legislative actions and proposals
(such as the Electric Consumers Protection Act of 1986, Energy
Policy Act of 1992, Clean Water Act Reauthorization and
Endangered Species Act Reauthorization), a major issue facing the
Company is the relicensing of its hydro facilities. The
relicensing of these projects is not automatic under federal law.
The Company must demonstrate comprehensive usage of the
facilities, that it has been a conscientious steward of the
natural resource entrusted to it and that there is a strong
public interest in the Company continuing to hold the federal
licenses. Idaho Power is actively pursuing the relicensing of its
hydroelectric projects, a process that will continue for the next
10 to 15 years. The Company submitted its first applications for
license renewal to the FERC in December 1995. These first
applications seek renewal of the Company's licenses for its
Bliss, Upper Salmon Falls, and Lower Salmon Falls Hydroelectric
Projects. Although various federal requirements and issues must
be resolved through the relicensing process, the Company
anticipates that it's efforts will be successful. At this point,
however, the Company cannot predict what type of environmental or
operational requirements it may face, nor can it estimate the
eventual cost of relicensing.

Idaho Energy Resources Co. owns a one-third interest in certain
coal leases near the Jim Bridger generating plant in Wyoming from
which coal is mined and supplied to the plant.

Ida-West owns a 50 percent interest in five PURPA-qualified
facilities that have a total generating capacity of approximately
34 MW. The energy from these facilities is sold to the Company.

ITEM 3. LEGAL PROCEEDINGS

The Company is a defendant in a Superfund case entitled United
States of America vs. Pacific Hide & Fur Depot, et al., Civil No.
83-4062, pending in the United States District Court for the
District of Idaho. The suit involves PCB and PCB/lead
contamination at a scrap metal/recycling facility near Pocatello,
Idaho. The Company entered into a Partial Consent Decree which
was signed by the District Judge on September 26, 1989, wherein
the Company agreed to remediate PCBs at the site. Prior to
remediation, EPA notified the Company of the discovery of lead
and other metals contamination at levels of concern at the site.
Remediation activities were completed on October 21, 1992.

A Certification of Completion for the Operable Unit Remedial
Action dated March 31, 1993, was issued by EPA to the Company. On
August 30, 1993, Notice of the Lodging of an Amended Partial
Consent Decree was published in the Federal Register establishing
a period for public comment.

Pursuant to the Request for Public Comment, a number of
Potentially Responsible Parties (PRPs) involved with the lead
contamination at the site filed objections to the proposed
Amended Partial Consent Decree. The objections generally contend
that the government's information relating to the Company's
contribution to the lead contamination at the site is erroneous,
and that the Company's remedial efforts and related costs are
disproportionately low in relation to its liability.

The Amended Partial Consent Decree was lodged with the U. S.
District Court for the District of Idaho on December 12, 1994,
along with the EPA's Motion to Enter. The Amended Partial Consent
Decree provides that the Company is protected against any and all
claims for contribution by other PRPs, both as to the PCB and
lead contamination.

On January 24, 1995, the Company was advised that the PRP group
associated with lead contamination was objecting to the proposed
entry of the Amended Partial Consent Decree on the basis that the
Company has not paid its "fair share" of the remaining lead clean-
up costs which EPA currently estimates at approximately $5.0
million.

It was EPA's position that the Company, as an integral part of
its clean-up of the PCB contamination and PCB/lead contamination,
removed approximately 57 percent of the total lead contamination
from the entire site, even though the Company contributed only
10.5 percent of the total lead contamination.

On May 5, 1995, the Federal Magistrate entered a Report and
Recommendation to the District Judge wherein it was recommended
that the government's Motion for Entry of the Amended Partial
Consent Decree be granted. On May 18, 1995, the PRP group
associated with lead contamination filed objections to the
Magistrate's recommendations. The government filed its responses
to the objections on May 31, 1995.

On November 30, 1995, the District Judge issued a Memorandum
Decision and Order adopting the recommendations entered by the
Magistrate in the Report and Recommendation. The objecting PRPs
had the right but did not appeal the District Judge's Order to
the Ninth Circuit Court of Appeals. Based on the entry of the
Amended Consent Decree the Company will, with the EPA and the
Department of Justice, seek the Company's dismissal from the
case.

This matter has been previously reported in Form 10-K dated
March 9, 1989, March 8, 1990, March 14, 1991, March 16, 1992,
March 12, 1993, March 10, 1994, March 9, 1995 and other reports
filed with the Commission.

On February 16, 1994, an action for declaratory relief and breach
of contract entitled Idaho Power Company vs. Underwriters and
Lloyds London, et al., was filed by the Company in Federal
District Court in Pocatello, Idaho, against its solvent liability
insurers in the period of 1969 to 1974, arising out of the
insurer's denial of coverage for the Company's environmental
remediation of a hazardous waste site in Pocatello. The action
seeks a declaratory judgment that the policies cover the
Company's costs of defending claims related to the site and costs
of site remediation, and damages for the insurers' breach of the
insurance contracts based on the insurers' failure to pay such
costs.

Due to a case backlog in the Idaho District, the case was
assigned to a Federal Judge in the Eastern District of
Washington. In the action, the Company sought reimbursement for
approximately $6.1 million in indemnity and defense costs
associated with the remediation, together with prejudgment
interest and attorney fees and costs for the action.

The Company successfully settled its claim for coverage with the
Liquidation Trustee for the first layer insurer (which insurer is
now in liquidation) on several of the policies at issue,
resulting in a one-time payment of $827,500 to the Company in the
fall of 1994. In late 1995, the Company reached agreements with
two of the insurers to settle the claims against them on terms
favorable to the Company. In early 1996, the Company entered into
an oral agreement with the remaining insurers to settle its
claims with them on terms favorable to the Company, and expects
to reduce that agreement to writing and receive payment of the
sum called for by the agreement by mid-1996.

This matter has been previously reported in Form 10-K dated March
9, 1995 and other reports filed with the Commission.

On December 6, 1991, a complaint entitled Nez Perce Tribe,
Plaintiff, vs. Idaho Power Company, Defendant, Civil No. CIV 91-
0517-S-EJL, was filed against the Company in the United States
District Court for the District of Idaho.

On September 11, 1992, the Tribe filed an Amended Complaint in
which it amplified its original Complaint by asserting that
Brownlee, Oxbow and Hells Canyon Dams were "constructed, operated
and maintained in such a manner as to damage plaintiff's rights"
to harvest fish, which rights the Tribe asserts to be "present,
possessory property right(s)". As the basis for its alleged right
to recover damages from the Company, the Tribe asserts that the
Company negligently constructed, operated and maintained
Brownlee, Oxbow and Hells Canyon Dams, that the Company
negligently failed to prevent or mitigate harm to the Tribe, that
the Company intentionally and willfully destroyed, interfered
with, and dispossessed the Tribe of its property rights, and that
the Company improperly exercised dominion over the Tribe's
property, thus depriving the Tribe of its possession. The Tribe
seeks through its Amended Complaint to secure actual, incidental,
consequential and punitive damages in amounts to be proven at
trial.

On September 18, 1992, the Company filed a motion for summary
judgment in the hope of securing dismissal of the Tribe's action.
The District Court issued an Order of Reference sending the case
to a Federal Magistrate. On July 30, 1993, the Magistrate issued
a Report and Recommendation that the District Judge grant that
portion of the Company's motion for summary judgment regarding
the loss of fish.

On November 30, 1993, the District Court entered a Second Order
of Reference, in which the Court sent the case back to the
Magistrate for the Magistrate to make additional findings with
respect to the Tribe's contention that it is entitled to
compensation based on physical exclusion from its usual and
accustomed fishing places. On February 28, 1994, the Magistrate
issued a Second Report and Recommendation wherein it was
recommended that the District Court deny the Company's motion for
summary judgment as to the Tribe's claim for damages arising from
precluding the Tribe's access to its usual and accustomed fishing
places and reaffirmed its recommendation in the original Report
and Recommendation dated July 30, 1993, to grant the Company's
motion for summary judgment as to all other claims.

On September 28, 1994, the Federal District Judge issued an Order
rejecting the Second Report and Recommendation of the Magistrate
granting, in its entirety, the Company's motion for summary
judgment.

On November 8, 1994, the Tribe filed its Notice of Appeal with
the Ninth Circuit Court of Appeals. No date for oral argument on
the appeal has yet been set.

The Company and the Tribe have reached agreement on a proposed
settlement of this case. The Nez Perce Tribal Executive Committee
has approved the settlement, and the Company will submit the
proposed settlement to its Board of Directors at the March Board
meeting. If the Company's Board of Directors approves the
settlement, it will be submitted to appropriate state and federal
regulators for their approval.

This matter has been previously reported in Form 10-K dated
March 16, 1992, March 12, 1993, March 10, 1994, March 9, 1995 and
other reports filed with the Commission.

On October 6, 1994, the Company brought an action, Idaho Power
Company vs. Monsanto Company, et al., in the District Court of
the Fourth Judicial District of the State of Idaho, against
Monsanto Company, General Electric Company, Westinghouse Electric
Corporation, Schlumberger Industries, Inc., McGraw-Edison
Company, Asea Brown Boveri, Inc., and Cooper Industries, Inc. The
Complaint alleged fraudulent misrepresentation or omission of
material facts, and/or knowing failure to warn Idaho Power
Company of the hazards of PCBs, in connection with the sale,
service, replacement, maintenance and/or removal of electrical
equipment utilizing or contaminated with PCBs.

Pursuant to stipulations between the Company and the defendants,
the case was dismissed without prejudice by orders of the court
dated December 22, 1995, December 28, 1995, and January 6, 1996.

This matter has been previously reported in Form 10-K dated
March 9, 1995, and other reports filed with the Commission.

On November 30, 1995, a complaint entitled Idaho Power Company
vs. Cogeneration, Inc., Case No. 98467, was filed by the Company
in the District Court of the Fourth Judicial District of the
State of Idaho. The proceeding involves an effort by the Company
to terminate a firm energy sales agreement (FESA) for a small
hydroelectric generating plant.

As required by PURPA and the orders of the IPUC, on January 7,
1992, the Company entered into a 35-year FESA with Cogeneration,
Inc., to purchase the output of a 43-megawatt  hydroelectric
generating project known as the Auger Falls Project. The FESA for
the Auger Falls Project was approved by the IPUC on January 27,
1992. The FESA required that on or before January 1, 1994,
Cogeneration, Inc., post cash or cash equivalent security in the
amount of approximately $1.9 million to assure performance of the
FESA. Cogeneration, Inc., failed to provide the security amount.
Consistent with the FESA, the Company filed a petition for
declaratory order with the IPUC requesting that the FESA be
terminated as a result of Cogeneration, Inc.'s breach.
Cogeneration, Inc.,  cross petitioned claiming that its failure
to perform was excused by the occurrence of an event of force
majeure. On April 17, 1995, the IPUC issued its order finding
that Cogeneration, Inc.'s failure to post the cash security on
January 1, 1994, was a default under the FESA and further finding
that the posting of the liquid security was required by the
public interest. Based upon those findings, the IPUC ordered
Cogeneration, Inc., to post the cash security prior to May 1,
1995. Cogeneration, Inc., failed to comply with the Commission's
order and has never posted the $1.9 million amount required by
the FESA.

After the IPUC order became final and non-appealable, the Company
filed this complaint for declaratory relief in the District Court
of the Fourth Judicial District. The Complaint sought a
determination by the district court that Cogeneration, Inc.'s
failure to provide the cash security and its violation of the
IPUC's orders requiring that it expeditiously provide the cash
security constituted material breaches of the FESA. The Company
asked the district court to find that as a matter of law Idaho
Power was entitled to either terminate or rescind the FESA.

In response to the Company's complaint, Cogeneration, Inc., filed
counterclaims alleging that the Company, by seeking to terminate
the FESA, had breached the FESA and was attempting to monopolize
the electric generation market and drive Cogeneration, Inc., out
of business. Cogeneration, Inc., alleged damages for breach in
excess of $50 million and requested that any damages be trebled
under the anti-trust laws.

On November 30, 1995, the district judge, by memorandum decision
found that Cogeneration, Inc., had materially breached the FESA
and the Company was entitled to either rescind or terminate the
FESA.

On February 16, 1996, Cogeneration, Inc. dismissed its anti-trust
claims against the Company and on February 23, 1996, the Idaho
Supreme Court granted Cogeneration, Inc.'s request for an
expedited appeal of the district courts decision establishing an
accelerated briefing schedule and scheduling oral argument for
May 10, 1996.

While the outcome of litigation is never certain, Idaho Power
believes that Cogeneration, Inc.'s counterclaims are without
merit.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS

         None


EXECUTIVE OFFICERS OF THE REGISTRANT

The names, ages and positions of all of the executive officers of
the Company are listed below along with their business experience
during the past five years. Officers are elected annually by the
Board of Directors. There are no family relationships among these
officers, nor any arrangement or understanding between any
officer and any other person pursuant to which the officer was
elected.

                          Business Experience During
Name, Age and Position    Past Five (5) Years

J. W. Marshall, 57         Appointed August 18, 1989.
Chairman of the Board
and Chief Executive
Officer
                           
L. R. Gunnoe, 60           Appointed July 12, 1990.
President and Chief
Operating Officer
                           
Daniel K. Bowers, 48       Appointed July 10, 1986.
Vice President and
Treasurer
                           
J. LaMont Keen, 43         Appointed November 14, 1991.
Vice President and         Mr. Keen was Controller prior to
Chief Financial Officer    November 14, 1991.
                           
Douglas H. Jackson, 59     Appointed July 12, 1990.
Vice President -
Distribution
                           

C. N. Olson, 46             Appointed July 11, 1991. Mr. Olson
Vice President -            was Senior Manager - Corporate
Corporate Services          Services prior to July 11, 1991.
                            
J. B. Packwood, 52          Appointed July 13, 1989.
Vice President -
Power Supply
                            
Robert W. Stahman, 51       Appointed July 13, 1989.
Vice President, General
Counsel and Secretary
                            
Harold J. Hochhalter, 60    Appointed January 9, 1992.
Controller and Chief        Mr. Hochhalter was Manager of
Accounting Officer          Corporate Accounting and Reporting
                            prior to January 9, 1992.

PART II

ITEM 5. MARKET FOR THE REGISTRANT'S COMMON STOCK AND
         RELATED STOCKHOLDER MATTERS


The Company has paid cash dividends on its common stock in each
year since 1918. For the years of 1993, 1994 and 1995, cash
dividends per share of common stock were $1.86. At the July 1995
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
1994 and 1995, as reported by The Wall Street Journal as
composite tape transactions. The Company's year-end common stock
price was $30 per share and the number of stockholders of record
at December 31, 1995, was 30,795.


                                      1994 Quarters
Common Stock, $2.50 par value:     1st      2nd       3rd       4th
     High                       $ 30 5/8  $ 27 5/8  $ 24 7/8  $ 24 1/8
     Low                          26 7/8    21 3/4    22 1/2    22
     Dividends paid per share
      (cents)                       46.5      46.5      46.5      46.5


                                      1995 Quarters
Common Stock, $2.50 par value:     1st      2nd       3rd       4th
     High                       $ 26      $ 26 3/4  $ 27 7/8  $ 30
     Low                          23 3/8    23 5/8    23 7/8    27 1/4
     Dividends paid per share
      (cents)                       46.5      46.5      46.5      46.5

<TABLE>
<CAPTION>
ITEM 6. SELECTED FINANCIAL DATA

SUMMARY OF OPERATIONS                 1995                1994               1993                1992   
(Thousands of Dollars)
<S>                             <C>                 <C>                <C>                 <C>                            
Revenues:                                                                                               
 General business               $  461,594          $  457,354         $  428,658          $  431,818   
 Sales to other utilities           57,418              59,923             86,525              42,000   
 Other revenues                     26,609              26,381             25,219              24,274   
  Total revenues                   545,621             543,658            540,402             498,092   
Expenses:                                                                                               
 Purchased power                    54,586              60,216             45,361              58,496   
 Fuel expense                       54,691              94,888             87,855              96,710   
 Other operation and               169,959             154,742            164,388             137,547   
maintenance
 Depreciation                       67,415              60,202             58,724              59,823   
 Taxes other than income taxes      22,979              23,945             22,129              20,562   
  Total expenses                   369,630             393,993            378,457             373,138   
Income from operations             175,991             149,665            161,945             124,954   
Other income and deductions -      (14,356)            (12,160)           (12,984)            (11,133) 
Net
Interest charges - Net              55,014              52,652             53,991              52,935   
Income taxes                        48,412              34,243             36,474              23,162   
Cumulative effect of accruing                                                                           
 unbilled revenues                       -                   -                  -                   -
Net Income                          86,921              74,930             84,464              59,990   
 Dividends on preferred stocks       7,991               7,398              6,009               5,516   
Earnings on common stock            78,930              67,532             78,455              54,474   
 Dividends on common stock          69,941              69,594             67,959              65,043   
Net change to retained earnings $    8,989            $ (2,062)        $   10,496          $  (10,569) 
</TABLE>
<TABLE>
<CAPTION>
                     
CAPITALIZATION (000 omitted)                   %                   %                  %                  %
<S>                             <C>           <C>   <C>           <C>  <C>           <C>   <C>          <C>                        
First mortgage bonds            $  470,000 }   45   $  490,000 }   46  $  490,000 }   47   $  485,000 }  49
Other long-term debt               202,618             203,206            203,780             216,948   
Mandatory redeemable preferred           - }    9            - }    9           - }    9            - }   7
stock
Preferred stock                    132,181             132,456            132,751             107,874   
Common stock (incl. prem. &        452,948 }   46      452,962 }   45     439,467 }   44      412,998 }  44
exp.)
Retained earnings                  229,827             220,838            222,900             212,404   
  Total capitalization          $1,487,574    100   $1,499,462    100  $1,488,898    100   $1,435,224   100
                                                                            
Short-term borrowings           $   53,020          $   55,000         $    4,000          $    6,000   
outstanding
</TABLE>                       
<TABLE>
<CAPTION>
SUMMARY OF OPERATIONS                 1991                1990               1989                1988   
(Thousands of Dollars) (Cont'd)
<S>                             <C>                 <C>                <C>                 <C>                                      
Revenues:                                                                                               
 General business               $  409,454          $  401,350         $  397,974          $  362,050   
 Sales to other utilities           52,563              44,368             70,749              32,175   
 Other revenues                     21,176              19,217             27,438              18,096   
  Total revenues                   483,193             464,935            496,161             412,321   
Expenses:                                                                                               
 Purchased power                    51,210              43,923             43,845              43,723   
 Fuel expense                       75,161              77,606             77,127              74,528   
 Other operation and               151,593             134,126            132,114             116,230   
maintenance
 Depreciation                       57,597              55,114             53,092              51,691   
 Taxes other than income taxes      21,168              20,752             20,213              19,301   
  Total expenses                   356,729             331,521            326,391             305,473   
Income from operations             126,464             133,414            169,770             106,848   
Other income and deductions -       (9,453)            (11,666)           (10,005)             (6,552) 
Net
Interest charges - Net              56,901              52,605             52,997              50,762   
Income taxes                        21,144              23,234             42,041              13,558   
Cumulative effect of accruing                                                                           
 unbilled revenues                       -                   -                  -                   -
Net Income                          57,872              69,241             84,737              49,080   
 Dividends on preferred stocks       4,904               4,279              4,285               4,293   
Earnings on common stock            52,968              64,962             80,452              44,787   
 Dividends on common stock          63,197              63,197             62,177              61,159   
Net change to retained earnings $  (10,229)         $    1,765         $   18,275          $  (16,372) 
</TABLE>

<TABLE>
<CAPTION>
CAPITALIZATION (000 omitted)                   %                   %                  %                  %
<S>                             <C>           <C>   <C>           <C>  <C>           <C>   <C>          <C>
First mortgage bonds            $  435,000 }   48   $  367,500 }   46  $  377,000 }   47   $  392,000 }  47
Other long-term debt               194,981             194,159            165,551             164,426   
Mandatory redeemable preferred           - }    8            - }    5           - }    5            - }   5
stock
Preferred stock                    108,191              58,761             58,923              59,126   
Common stock (incl. prem. &        356,824 }   44      358,078 }   49     357,986 }   48       357,866 } 48
exp.)
Retained earnings                  222,973             233,241            231,476             213,201   
  Total capitalization          $1,317,969    100   $1,211,739    100  $1,190,936    100   $1,186,619   100
Short-term borrowings           $   48,500          $   48,280         $   31,000          $   37,000   
outstanding
</TABLE>                       
<TABLE>
<CAPTION>

SUMMARY OF OPERATIONS                 1987                1986               1985    
(Thousands of Dollars) (Cont'd)
                                                                                    
<S>                             <C>                 <C>                <C>                     
Revenues:                                                                            
 General business               $  343,899          $  336,480         $  336,705    
 Sales to other utilities           35,447              54,987             98,980    
 Other revenues                     15,251              17,394             15,495    
  Total revenues                   394,597             408,861            451,180    
Expenses:                                                                            
 Purchased power                    30,234              31,849             16,188    
 Fuel expense                       65,934              31,260             81,961    
 Other operation and               114,235             114,407            125,728    
maintenance
 Depreciation                       50,929              49,308             45,595    
 Taxes other than income taxes      19,072              18,539             16,790    
  Total expenses                   280,404             245,363            286,262    
Income from operations             114,193             163,498            164,918    
Other income and deductions -      (13,115)            (17,064)           (20,352)  
Net
Interest charges - Net              51,843              51,206             47,891    
Income taxes                        27,246              50,923             52,556    
Cumulative effect of accruing                                                        
 unbilled revenues                 (11,302)                  -                  -
Net Income                          59,521              78,433             84,823    
 Dividends on preferred stocks       4,298              10,553             12,447    
Earnings on common stock            55,223              67,880             72,376    
 Dividends on common stock          61,159              59,755             56,277    
Net change to retained earnings $   (5,936)         $    8,125         $   16,099    
</TABLE>
<TABLE>
<CAPTION>
CAPITALIZATION (000 omitted)                   %                   %                  %
<S>                             <C>           <C>   <C>           <C>  <C>           <C>           
First mortgage bonds            $  407,000 }   47   $   432,000 }  47  $  467,000 }   47
Other long-term debt               160,003              153,887           149,074    
Mandatory redeemable preferred           - }    5             - }   5      63,000 }    9
stock
Preferred stock                     59,238               59,403            60,585    
Common stock (incl. prem. &        357,797 }   48       357,708 }  48     355,007 }   44
exp.)
Retained earnings                  229,573              235,509           230,558    
  Total capitalization          $1,213,611    100   $ 1,238,507   100  $1,325,224    100
Short-term borrowings           $    4,000          $     5,000        $        -    
outstanding
</TABLE>

FINANCIAL STATISTICS                1995        1994        1993         1992   
                                                      
Income from operations as a                                  
percent
 of total revenues                  32.3%       27.5%       30.0%       25.1% 
Times interest charges earned:                                   
 Before tax                          3.26        3.01        3.14        2.50   
 After tax                           2.40        2.38        2.50        2.08   
Market-to-book ratio                 165%        131%        170%        159% 
Payout ratio                          89%        103%         87%        120% 
Return on year-end common                                   
 equity                            11.56%      10.02%       1.84%       8.71%
Common stock data:                                      
 Earnings per average share                                                    
  outstanding                  $     2.10  $     1.80  $     2.14  $     1.55
 Dividends declared per share  $     1.86  $     1.86  $     1.86  $     1.86   
 Book value per share          $    18.15  $    17.91  $    17.86  $    17.28   
 Average shares outstanding        37,612      37,499      36,675      35,116   
(000 omitted)
 Common shareowners                30,795      26,209      26,870      27,834   
 * Includes cumulative effect                       
of accounting change
                                                             
CUSTOMER DATA                                                        
                                                                     
General business data:                                               
 Energy sales - kWh                                                         
  (000,000 omitted)                11,983      12,194      11,406      11,606
 Number of customers              340,708     330,308     317,772     307,567   
Residential customer data:                                                    
 Number of customers              282,797     274,187     263,682     255,022   
 Average kWh use per customer      13,475      14,159      14,587      13,856   
 Average rate per kWh (cents)        5.16        4.83        4.82        4.80   
                                                                           
OTHER STATISTICS                                                          
                                                                              
Total assets (000 omitted)     $2,241,753  $2,191,816  $2,097,417  $1,862,307   
Gross plant additions (000     
 omitted)                      $   87,297  $  107,667  $  116,972  $  118,920   
Number of employees (full-time)     1,522       1,609       1,654       1,638   

FINANCIAL STATISTICS (Cont'd)       1991        1990        1989        1988   
                                                                                
Income from operations as a                                                     
 percent of total revenues          26.2%       28.7%       34.2%       25.9% 
Times interest charges earned:                                                
 Before tax                          2.34        2.72        3.30        2.18   
 After tax                              1        2.29        2.53        1.93   
Market-to-book ratio                 168%        148%        169%        138% 
Payout ratio                         119%         97%         77%        137% 
Return on year-end common           9.14%      10.99%      13.65%       7.84% 
equity
Common stock data:                                                          
 Earnings per average share    $     1.56  $     1.91  $     2.37  $     1.32   
outstanding
 Dividends declared per share  $     1.86  $     1.86  $     1.83  $     1.80   
 Book value per share          $    17.07  $    17.40  $    17.35  $    16.81   
 Average shares outstanding 
 000 omitted)                      33,977      33,977      33,977      33,977   
Common shareowners                 28,069      29,080      30,291      32,225   
 
 * Includes cumulative effect 
   accounting change

CUSTOMER DATA

General business data:
 Energy sales - kWh  
  (000,000 omitted)                11,266      11,086      11,069      10,563
 Number of customers              297,808     291,800     284,363     279,529   
Residential customer data:   
 Number of customers              246,689     241,790     236,008     232,650   
 Average kWh use per customer      14,845      14,281      14,923      14,364   
 Average rate per kWh (cents)        4.72        4.73        4.69        4.47   

OTHER STATISTICS 

Total assets (000 omitted)     $1,773,674  $1,680,110  $1,625,120  $1,608,935   
Gross plant additions (000     $  135,904  $   80,117  $   62,094  $   64,358   
omitted)
Number of employees (full-time)     1,626       1,574       1,528       1,500   


FINANCIAL STATISTICS (Cont'd)       1987        1986        1985   

Income from operations as a
 percent of total revenues          28.9%       40.0%       36.6%  
Times interest charges earned:
 Before tax                          2.76*       3.40        3.61
 After tax                           2.10*       2.46        2.61
Market-to-book ratio                 127%        150%        133%
Payout ratio                         111%         88%         78%
Return on year-end common           9.40%      11.44%      12.36%
equity
Common stock data: 
 Earnings per average share    $     1.63* $     2.00  $     2.16
outstanding
 Dividends declared per share  $     1.80  $     1.76  $     1.68
 Book value per share          $    17.29  $    17.46  $    17.29
 Average shares outstanding        33,977      33,961      33,544
(000 omitted)
 Common shareowners                33,733      34,456      35,959 
 * Includes cumulative effect
of accounting change

CUSTOMER DATA 

General business data: 
 Energy sales - kWh
  (000,000 omitted)                10,175       9,938      10,366 
 Number of customers              276,249     274,129     272,155 
Residential customer data:      
 Number of customers              230,486     228,921     227,562  
 Average kWh use per customer      13,785      14,541      15,432 
 Average rate per kWh (cents         4.34        4.21        3.98

OTHER STATISTICS

Total assets (000 omitted)     $1,602,311  $1,621,887  $1,646,847
Gross plant additions (000     $   38,929  $   50,257  $   74,064
omitted)
Number of employees (full-time)     1,521       1,524       1,568


ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF
        FINANCIAL CONDITION AND RESULTS OF OPERATIONS

OVERVIEW

Idaho Power Company's consolidated financial statements represent
the Company and its five wholly-owned subsidiaries: Idaho Energy
Resources Company (IERCo); Ida-West Energy Company (Ida-West);
IDACORP, Inc.; Idaho Utility Products Company (IUPCo); and
Stellar Dynamics. This discussion uses the terms Idaho Power and
the Company interchangeably to refer to Idaho Power Company and
its subsidiaries.

EARNINGS PER SHARE AND BOOK VALUE

Three primary factors affected earnings per share in 1995:  the
resolution of rate cases in Idaho and Oregon, improved
precipitation and streamflow conditions, and successful cost-
cutting measures. In January 1995, the Company completed its
general revenue requirements case in Idaho with a $17.2 million
(4.2 percent) increase in rates. The Company later reached
settlements with the Idaho Public Utilities Commission (IPUC) on
the Twin Falls case ($3.8 million) and with the Oregon Public
Utility Commission (OPUC) on general rate relief ($1.3 million).
These rate increases were partially offset by weather conditions
that reduced residential and irrigation energy demands. An
unusually warm winter and a cool summer created a surplus energy
market in which prices on sales for resale dropped to record
lows. However, abundant precipitation within the Company's
service territory allowed Idaho Power to capitalize on its low-
cost hydroelectric generating system, dramatically reducing fuel
expenses and purchased power costs. Finally, the Company
instituted aggressive cost containment and efficiency measures to
manage capital and operating expenses. Total operating expenses
were down $24.4 million, while construction expenditures were
reduced $26.6 million from 1994 amounts.

Earnings per share of common stock in 1995 totaled $2.10, up from
the $1.80 earned in 1994 and only slightly lower than the $2.14
earned in 1993. The 1995 earnings equate to an 11.6 percent
earned return on year-end common equity, as compared to the 10.0
percent earned in 1994 and the 11.8 percent earned in 1993. At
December 31, 1995, the book value per share of common stock was
$18.15.

Results of Operations

     Energy Demand and Customer Growth

Milder winter and spring temperatures reduced 1995 residential
loads for heating and cooling, while the wet, cool spring reduced
irrigation loads. In contrast, 1994 was characterized by a
prolonged period of high summer temperatures that led to sharp
increases in energy demand and led to a record peak system load.

While energy demand was down, the Company continued its growth of
new customers by adding 10,400 new general business customers
during 1995. This increase marks 1995 as the Company's fourth
best year in terms of customer growth, coming on the heels of
1994's record-setting growth of 12,536 new general business
customers. During 1995, Idaho Power added 8,610 residential
customers, 1,636 commercial and industrial customers, and 154
irrigation customers.

     Economy

Idaho's economy continues to grow at a healthy pace. For the
twelve months ending September 1995, non-agricultural employment
in Idaho rose 4.4 percent, making Idaho the eighth fastest
growing state in the nation. Idaho's per capita income grew by
5.8 percent in 1994 and by an average 6.3 percent through the
first half of 1995.

While job and income growth have kept Idaho near the top of the
national rankings during 1995, monthly employment gains from 1994
levels reveal a slackening in the rate of job growth. In
addition, some of Idaho's larger employers announced plans for
restructuring and consolidation. Idaho's September 1995 non-
agricultural employment was up 1.9 percent, while manufacturing,
trade, and services employment posted gains of 1.5 percent, 3.2
percent, and 2.6 percent respectively when compared to September
1994. Non-agricultural employment growth in the Boise
Metropolitan Statistical Area remains relatively high, with a net
increase of 4.2 percent (7,300 jobs) between September 1994 and
September 1995.

Further restructuring within the forest products industry, a
slowing of residential construction activity (due to a lower
level of economic activity), and changes slated for the Idaho
National Engineering Laboratory (INEL) near Idaho Falls should
keep Idaho's employment growth in 1996 and 1997 within the 2.5
percent to 3.0 percent range, as compared to the average of 6.9
percent experienced during 1993 and 1994.

The number of residential customers in Idaho Power's service area
grew by 3.4 percent in 1993, 4.0 percent in 1994, and 3.1 percent
in 1995. Over the next five years, the Company projects that the
number of new households in its service area will grow by an
average annual rate of 2.4 percent.

     Revenues

For the three-year period 1993-1995, the Company received an
average 86 percent of its operating revenues from electric sales
in Idaho, 5 percent in Oregon, less than 1 percent in Nevada, and
9 percent from the wholesale market. For the same three-year
period, the average percentages of total operating revenues by
customer category were as follows:

  -    34 percent from residential customers;
  -    30 percent from a combination of irrigation customers,
       street lighting customers, and commercial  customers with less
       than 1,000 kW demand;
  -    19 percent from industrial customers with demand of 1,000 kW
       or greater;
  -    13 percent from sales to other utilities and interchange
       arrangements; and
  -    4 percent from miscellaneous revenue.

The Company's energy sales to general business customers fell 1.7
percent in 1993, increased 6.9 percent in 1994, but decreased 1.7
percent in 1995. The sales increase in 1994 reflects the strong
economic growth in Idaho Power's service territory; increases in
new customers served; and hot, dry summer weather. In 1995,
residential usage was down 1.5 percent, due to the mild weather,
even with an increase of new customers during the year. The
declines in 1993 and 1995 may be traced to wet spring weather
that reduced irrigation kilowatt-hour sales in those years by
28.8 percent and 25.2 percent respectively. In addition,
temporary operational changes made in 1993 by two of the
Company's large industrial customers lowered their energy
consumption. FMC Corporation periodically curtailed 1993
operations at its elemental phosphorous production plant in
response to market conditions for its product. The INEL also
reduced its 1993 electrical usage. However, both FMC and INEL
returned to a higher level of operation during 1994. Those two
entities, along with Boise's Micron Technology, increased their
energy usage in 1995.

General business revenues represent approximately 83 percent of
the Company's total operating revenues. For 1993, general
business revenues were $428.7 million, for 1994 $457.4 million,
and for 1995 $461.6 million. The 1994 increase reflects above-
normal summer temperatures that increased irrigation revenues by
$16.2 million (33.2 percent). The 1995 increase reflects rate
increases during the year and increased sales to some industrial
customers. The number of general business customers served
increased by 33,141 (10.8 percent) during the three-year period.
The average residential customer used 14,587 kilowatt-hours (kWh)
of electricity in 1993, 14,159 kWh in 1994, and 13,475 kWh in
1995, primarily due to varied weather patterns.

Total operating revenues increased by $42.3 million (8.5 percent)
in 1993, $3.3 million (0.6 percent) in 1994, and $2.0 million
(0.4 percent) in 1995. Increased opportunity sales to other
utilities created the 1993 increase in total operating revenue.
Customer growth, coupled with above-normal summer temperatures,
accounted for the 1994 increase. However, that increase was
offset by a decline in opportunity sales caused by reduced
streamflows. The increase for 1995 reflects the continuing
strength of economic growth in the Company's service territory,
the continued increase in new customers, and rate increases in
the Idaho jurisdiction. The 1995 increase was partially offset by
reduced revenues from sales for resale.

     Off-System Sales

Revenues from sales to other utilities rose $44.5 million in
1993, declined $26.6 million in 1994, and declined by an
additional $2.5 million in 1995. Off-system sales are composed of
firm sales (long-term contracts) and opportunity sales made on a
when-available basis. The volume and price of these sales depend
on the Company's firm energy demand, hydroelectric generating
conditions in its service territory, and market conditions
throughout the West. Revenues from firm sales to other utilities
totaled $45.4 million in 1993, $53.6 million in 1994, and $45.2
million in 1995. Revenues from opportunity sales to other
utilities totaled $41.1 million in 1993, $6.3 million in 1994,
and $12.2 million in 1995. The return to more normal
hydroelectric generating conditions in 1993 increased the volume
of sales and revenue dramatically, while drought conditions
reduced opportunity sales in 1994. In 1995, improved
hydroelectric generating conditions created an increase in
opportunity energy sales. However, reduced demand on the energy
market cut the prices of such sales by 53 percent when compared
to those received in 1994.

     Expenses

Total operating expenses rose by $5.3 million in 1993 and $15.5
million in 1994, but decreased by $24.4 million in 1995. The 1993
rise in operating expenses reflects the deferral of certain 1992
drought-related net power supply costs to 1993, as authorized by
the IPUC. Maintenance expenses also increased in 1993 with that
year's return to improved hydroelectric operating conditions. The
added expense for 1994 reflects drought conditions, which
increased the Company's reliance on thermal generation and
purchased power. The decrease in 1995 may be traced to improved
hydroelectric operating conditions, which lowered purchased power
and fuel expenses by $5.6 million and $40.2 million respectively.

Purchased power expenses fluctuated during the three-year period.
This situation reflects necessity purchases from neighboring
utilities during the 1994 drought, and increased purchases in
1993 from cogeneration and small power production (CSPP) projects
as  hydroelectric generating conditions improved. Purchased power
expenses were lower in 1995 with the return to more normal hydro
conditions. The decrease was tempered by economy purchases made
while the market prices for off-system sales were soft and
increased purchases from CSPP projects.

All other operation and maintenance expenses fluctuated during
the three-year period, with a cumulative increase of $32.4
million. These variations are due, in part, to increases in
payroll and benefits, changes in operation and maintenance due to
water conditions, but were partially reduced by the successful
efforts of the Company's employees to manage operating costs.

Depreciation expense was up for the three-year period by $7.6
million (12.7 percent), due to a greater plant investment base.
Taxes other than income taxes rose $2.4 million (11.8 percent) as
a result of additional property taxes and taxes on the increased
generation and sale of hydroelectric power.


     Interest Charges

Interest charges on long-term debt fluctuated during the three-
year period, with a cumulative decrease of $1.0 million. This
decrease reflects the maturity, early redemption, and issuance of
several series of first mortgage bonds at reduced or lower
interest rates. The Company took advantage of declining interest
rates during 1993 to refinance several higher-cost bond issues.
These refinancings reduced the overall cost of debt and annual
interest expense by an amount that largely offset the cost of
additional financing (see Note 5 of Notes to Consolidated
Financial Statements).

Interest on short-term debt rose during the three-year period due
to fluctuating interest rates during the three-year period, as
well as to a higher level of short-term borrowings. At December
31, 1995, the Company's short-term borrowings totaled $53.0
million (see Note 7 of Notes to Consolidated Financial
Statements).

     Income Taxes

In August 1993, the U.S. Congress enacted the Omnibus Budget
Reconciliation Act. Among other things, the Act raised the
statutory corporate federal income tax rate from 34 percent to 35
percent, retroactive to January 1, 1993. Accordingly, taxes on
current income were computed at the higher rate. Also in 1993,
the Company settled with the Internal Revenue Service (IRS)
federal income tax liabilities for the 1987-1990 tax years. In
1994, the Company settled federal income tax liabilities for the
1991-1992 tax years, except for immaterial amounts relating to a
partnership.

     Precipitation and Streamflows

Idaho Power analyzes precipitation and streamflow conditions
based on the effect on Brownlee Reservoir, primary water source
for the three Hells Canyon hydroelectric projects. In normal
years, these three projects combine to produce about half of the
Company's generated electricity. In 1994, below-normal
precipitation created drought conditions and reduced the amount
of water flowing into the Company's reservoir system. However, in
1993 and 1995, Idaho Power's service territory experienced above
average water years. Between April and July 1995, the Company
recorded 6.6 million acre feet (MAF) of water flowing into
Brownlee Reservoir. This figure is 110 percent of 1993's 6.0 MAF,
236 percent of 1994's 2.8 MAF, and 138 percent of the 66-year
median of 4.8 MAF.

The early indications for 1996 are promising. As of February 1,
1996, reservoir storage above Brownlee Reservoir was at 81
percent of capacity compared to a normal of 62 percent The
average snow water equivalent for the Snake River above Brownlee
Reservoir was 116 percent of the 30-year average, compared to 114
percent of the average at this time last year.


     Energy Requirements

With precipitation and streamflow conditions above normal in
1995, hydroelectric generation accounted for 58 percent of the
Company's total energy requirements. This figure is an
improvement over 1993's 52 percent, and is substantially higher
than 1994's 40 percent. During 1995, thermal generation accounted
for 29 percent of total energy requirements, while purchased
power and other interchange supplied 13 percent. Under
historically normal conditions, the Company's hydro system
supplies approximately 57 percent of its total energy
requirements, with thermal generation accounting for 34 percent
and purchased power and other interchanges contributing the
remaining 9 percent.

The Company expects to meet 1996's projected energy loads by
using its hydro and coal-fired facilities and its strategic
geographic location, which presents excellent opportunities to
purchase, sell, exchange, and transmit Northwest energy.

     Regulatory Issues

       Power Cost Adjustment

Since 1993, the Idaho Power's Power Cost Adjustment (PCA)
mechanism has allowed the Company to collect or to refund the
differences between actual net power supply costs and those
allowed in the Company's Idaho base rates. Deviations from
forecasted costs are deferred with interest and trued up in the
following year. With the IPUC's revenue requirement order on
February 1, 1995, the PCA mechanism increased to a 90 percent
recovery level from its original 60 percent. The Company filed
its 1995 PCA application with the IPUC on April 15, 1995,
requesting a decrease in PCA rates for the Idaho jurisdiction.
The decrease (in effect from May 16, 1995 through May 15, 1996)
was approximately $8.2 million (1.9 percent), including last
year's true-up, still in excess of base rates. At December 31,
1995, the Company had recorded $1.0 million less in power supply
costs then projected in the 1995 forecast. The Company has
deferred this cumulative amount and will include it as a
reduction in the 1996 PCA true-up.

       General Revenue Requirement Case

On June 30, 1994, Idaho Power filed an application with the IPUC
to increase rates in its Idaho jurisdiction. The Company based
its application on calendar year 1993, using a thirteen-month
average rate base annualized for its new Swan Falls production
project and a year-end capitalization structure. In its
application, the Company  requested $37.1 million in general rate
relief, representing a 9.09 percent increase in rates, a 12.50
percent return on equity, and a 9.88 percent overall rate of
return. 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. The Company
originally applied for a $6.3 million (1.5 percent) increase to
recover capital costs and related expenses associated with the
construction of a new 43.5 megawatt (MW) power plant at its Twin
Falls hydro facility, along with additional plant investments at
the Swan Falls hydro facility since the filing of its last
general rate case.

The major issue in this case was whether the reduced power supply
costs resulting from the inclusion of the Twin Falls hydro
expansion would be recognized explicitly through a reduction in
base energy rates or implicitly through the PCA. The Company
reached a compromise with the IPUC staff on the overall revenue
requirement and agreed to recognize benefits up front in base
rates, instead of flowing the benefits through the PCA. As a
result, the Company's original $6.3 million request was reduced
by $1.9 million. The effect on projected Company earnings is only
10 percent of this amount ($190,000), since all but 10 percent of
the power supply cost reduction would have been passed through to
Idaho customers in the next PCA adjustment. The IPUC action
enabled the Company to recover the capital costs of a plant
addition within weeks of the plant becoming operational.

       Regulatory Settlement

On August 3, 1995, the Company filed a proposal with the IPUC to
defer and amortize costs associated with its internal
transformation process and acceleration of amortization of
regulatory liabilities associated with accumulated deferred
investment tax credits (ADITCs). The IPUC approved a settlement
agreement confirming the proposal, which allows the Company to
accelerate the amortization of the regulatory liabilities
associated with ADITCs whenever the Company's year-end return on
equity falls below 11.5 percent. In addition, the order allows
the Company to defer certain costs associated with its corporate
reorganization as regulatory assets and amortize them over a 10-
year period.

The terms and conditions of the Order will remain in effect
through 1999. Under the Order, when the Company's actual earnings
in a given year exceed an 11.75 percent return on year-end common
equity, the Company will refund 50 percent of the excess through
its next PCA adjustment.

Other important points in the Order are: (1) the Company may
accelerate a maximum of $30 million of regulatory liabilities
associated with ADITCs over the five-year period; (2) the Company
will not be allowed to increase its Idaho general rates prior to
January 1, 2000, except under special conditions as defined in
the Settlement Agreement; and (3) Idaho Power agrees that its
quality of service will not decline as a result of corporate
reorganization. The proposed accounting treatment of deferred
investment tax credits has been submitted to the IRS for
approval. On November 22, 1995, the Idaho State Tax Commission
approved the accounting treatment for the Idaho ADITCs. No
accelerated ADITC was recognized in 1995.

       Cogeneration and Small Power Production Contracts

In September 1993, the Company submitted a detailed position
paper to its state regulators and other interested parties. This
report outlined proposed changes in the Company's resource
acquisition policy. In light of the potential deregulation of the
electric utility industry and a more competitive power supply
marketplace, Idaho Power's position was that current resource
acquisition policies had to be changed to avoid burdening the
Company and its customers with unnecessary future power supply
costs. In December 1993, the Company filed with the IPUC for
permission to approve lower published prices for new CSPP
contracts. In response to the Company's filing,  the IPUC issued
an order on January 31, 1995, approving lower published CSPP
rates. In addition, the IPUC determined that negotiated rates for
future CSPP projects larger than 1 MW should be tied more closely
to values determined in the Company's integrated resource
planning (IRP) process.

       Oregon General Rate Relief

In May 1995, Idaho Power filed an application with the OPUC
seeking general rate relief of approximately $3.4 million, or a
16.65 percent increase. The Company later negotiated a Settlement
Stipulation with the OPUC staff, the Company's Oregon industrial
customers, and the Citizens Utility Board of Oregon. The
settlement grants Idaho Power a $1.3 million general rate
increase for its Oregon retail customers. The OPUC approved the
settlement agreement on November 28, 1995.

       Drought-Related Rate Relief

In response to the Company's April 1995 application, the OPUC
granted $1.5 million in drought-related rate relief. The OPUC
Order allows recovery of the $1.5 million through the continued
application of an existing increase authorized in July 1993 (for
1992 drought relief). The rate increase will remain in effect for
approximately 34 months beginning in July 1995. The Company had
deferred, with interest, increased power supply costs between May
1994 and December 31, 1994.

     Subsidiaries

       Ida-West Energy Company

This wholly-owned subsidiary of the Company owns, through various
partnerships, 50 percent of five Idaho hydroelectric projects
with a total generating capacity of approximately 34 megawatts
(MW). Third parties unaffiliated with Ida-West own the remaining
50 percent of these projects, thus satisfying the "qualifying
facility" status under PURPA guidelines. The partnerships have
obtained project financing (non-recourse to the Company) for each
of these facilities.

As a part of its Resource Contingency Program, the Bonneville
Power Administration (BPA) requested proposals to provide up to
800 average  MW of energy options. Ida-West, along with two
partners, submitted a proposal for a 227 MW gas-fired
cogeneration project to be located near Hermiston, Oregon. On
June 4, 1993, BPA selected three projects_including that of the
partnership_for participation in the program. The partnership and
BPA signed an option development agreement granting BPA an option
to acquire energy and capacity from the project any time during a
five-year option hold period after all option development period
tasks, including permitting, have been completed. The option also
entitles the partnership to BPA reimbursement for certain
development costs, based on the achievement of certain
milestones. This option includes an exclusive right to acquire
energy and capacity from a second 233 MW unit at the site during
the same five-year option hold period. In March 1994, BPA and the
partnership reached an additional agreement on the power purchase
contract, setting forth the terms and conditions by which BPA
will purchase energy and capacity from the project upon exercise
of the option. The partnership expects to complete development
period tasks during the first quarter of 1996. Project financing
for construction costs would be non-recourse to the Company.

The Company has invested $20 million in Ida-West. Ida-West
continues an active search for new projects.

       IDACORP, Inc.

Through this wholly-owned subsidiary, the Company is
participating in three 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.

Liquidity and Capital Resources

     Cash Flow

The Company's net cash generation from operations totaled $437.9
million for the three-year period 1993-1995. After deducting
common and preferred dividends of $227.7 million, net cash
generation from operations provided approximately $210.2 million
for the Company's construction program and other capital
requirements.

Internal cash generation after dividends provided 54 percent of
the Company's total capital requirements in 1993, 41 percent in
1994, and 101 percent in 1995. The Company projects that internal
cash generation after dividends will provide approximately 90
percent of total capital requirements in 1996 and over 100
percent during the five-year period 1996-2000. Idaho Power
expects to continue financing its construction program and other
capital requirements with both internally generated funds and, to
the extent necessary, externally financed capital. During the
forecast period, the Company also has first mortgage bond
maturities of $20.0 million in 1996, $30.0 million in 1998, and
$80.0 million in 2000. At January 1, 1996, the Company's lines of
credit maintained with various banks totaled $85.0 million (see
Note 7 of Notes to Consolidated Financial Statements).

     Construction Program

The Company's consolidated cash construction expenditures totaled
$122.9 million in 1993, $110.5 million in 1994, and $84.0 million
in 1995. Approximately 36 percent of these expenditures were for
generation facilities, 15 percent for transmission facilities, 38
percent for distribution facilities, and 11 percent for general
plant and equipment.

       Swan Falls Project

Early in the spring of 1994, the Company completed testing of the
renovated Swan Falls Hydroelectric Project and declared both
units available for commercial operation. Additional work to
preserve the old powerhouse as an historical site began during
the year, with work to establish a museum on the site scheduled
for completion in 1996.

       Twin Falls Project

In July 1995, the Company completed testing of the new expansion
turbine at its Twin Falls Hydroelectric Project and declared the
unit available for commercial operation. This project added 43.5
MW of capacity to the Company's generation system and a second
powerhouse to the Twin Falls site.

       Southwest Intertie Project

Idaho Power is continuing to study the economic feasibility of
constructing the Southwest Intertie Project (SWIP) to capitalize
on its strategic location between the Intermountain West and the
Pacific Northwest. 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, interconnecting the
Company's system with those of utilities in California and the
Southwest. In December 1994, the U.S. 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. Idaho Power
intends to retain up to 20 percent of ownership and capacity in
the 1,200 MW project. The SWIP may be built in segments as
warranted by demand for its transmission services. Idaho Power
and the BLM are working on a detailed, site-specific
construction, operation, and maintenance plan aimed at mitigating
the environmental impact of the project.

The Company sent participation packages to interested parties and
received capacity requests from these groups during the fourth
quarter of 1995. Ownership allocation has been completed between
the six interested parties and negotiations are in process for
the execution of the Memorandum of Agreement (MOA). At the time
of execution of the MOA the Company is requiring each party to
pay its share of the approximately $8.5 million expended for
environmental permitting, right-of-way acquisition, and related
development activities. The SWIP owners will then form an
Executive Committee with voting rights proportional to their
share of the project. The Executive Committee will oversee
development activities for the SWIP and related projects.

The Company is positioning SWIP as an open-access transmission
opportunity for participants, in line with the Notice of Proposed
Rulemaking (NOPR) issued by the Federal Energy Regulatory
Commission (FERC).

     Financing Program

       Capital Structure

The Company's capital structure (as illustrated in Selected
Financial Data) fluctuated during the three-year period, with
common equity growing to 46 percent, preferred staying at 9
percent, and long-term debt falling to 45 percent. The Company's
objective is to maintain capitalization ratios of approximately
45 percent common equity, 8-10 percent preferred stock, and the
balance in long-term debt. The Company's pre-tax interest
coverage ratios were 3.14 times in 1993, 3.01 times in 1994, and
3.26 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.

       Common Stock

During the period of January 1992 through May 1994, the Company
issued original issue shares of common stock for its Dividend
Reinvestment and Stock Purchase Plan, and for its Employee
Savings Plan. During 1993 and 1994, common shares totaling
898,528 and 527,296, respectively, were issued to these plans.
During 1995 no original issue shares were issued pursuant to
these plans. The Company used the net proceeds from these issues
for its ongoing construction program.

     Environmental Issues

       Salmon Recovery Plan

Work continues on the development of a comprehensive and
scientifically credible plan to ensure the long-term survival of
anadromous fish runs on the Columbia and Lower Snake Rivers.

In mid-August 1994, the federal government changed its
designation of the Fall Chinook Salmon from Threatened to
Endangered. The Company does not anticipate that the new
designation will have any major effects on its operations. In
September 1991, the Company modified operations at its three-dam
Hells Canyon Hydroelectric Complex to protect the Fall Chinook
downstream during spawning and juvenile emergence. From its
start, the Company's Fall Chinook program has exceeded the
protection requirements for threatened species, affording the
fish the same high level of protection due an endangered species.

In March of 1995, the National Marine Fisheries Service (NMFS)
released a Proposed Recovery Plan  for the listed Snake River
Salmon. The NMFS accepted public comment on the Plan through
December of 1995. As drafted, the Plan would not require any
change to the Company's current operations for salmon. Pending
completion of a final recovery plan by the NMFS, the U.S. Army
Corps of Engineers and other governmental agencies operating
federally-owned dams and reservoirs on the Snake and Columbia
Rivers will continue to consult with the NMFS regarding ongoing
system operations. These interim operations are not expected to
change the Company's current operations for salmon.

The Northwest Power Planning Council (NWPPC)  issued its recovery
plan for Snake River anadromous fish, the Strategy for Salmon, on
December 15, 1994. The NWPPC plan calls on the U. S. Bureau of
Reclamation (BOR) to acquire 500,000 acre-feet of water within
the Snake River Basin by 1996, and an additional 500,000 acre-
feet by 1998. The water is to be acquired from willing sellers.
Thus far, the BOR has indicated it does not intend to comply with
the request to acquire 1,000,000 acre-feet of additional water.
However, if the BOR does comply and successfully implements the
request, its movement of additional water could have a material
impact on the Company's Power supply costs. The strategy for
Salmon also calls for the Company to contribute 427,000 acre-feet
of water from Brownlee Reservoir as required in the NMFS Proposed
Recovery Plan. The Company is presently negotiating with BPA to
obtain reimbursement for the costs associated with lost
generation and the storing of energy resulting from the release
of the 427,000 acre-feet.

       Nez Perce Lawsuit

On December 6, 1991, the Nez Perce Tribe filed a civil action
against the Company in the U.S. District Court for the District
of Idaho. The Tribe alleged that the Company's construction,
operation, and maintenance of the three-dam Hells Canyon
Hydroelectric Project prevented anadromous fish from reaching
their traditional spawning areas, destroyed certain fish runs,
and denied access to certain of the Tribe's usual and accustomed
fishing places. These actions allegedly deprived the Nez Perce
Tribe of its treaty rights to take fish from the Columbia and
Snake Rivers. The Tribe is seeking compensatory and punitive
damages, each in an amount to be proven at trial.

Idaho Power maintains that the suit is without merit and asked
the federal court to issue a summary judgment dismissing the
action. The Company believes that the responsibility for concerns
expressed by the Nez Perce Tribe lies with the United States
government. The Hells Canyon Project was licensed by the federal
government, was built in accordance with federally approved
plans, and is operated subject to federal regulation. The Company
has complied with the government's requirements to mitigate any
effects that the Project may have had on the fisheries.

On January 19, 1993, the Court took the Company's motion for
summary judgment under advisement. On July 30, 1993, U.S.
Magistrate Judge Larry Boyle issued a Report and Recommendation
to the District Judge. Judge Boyle recommended that the District
Judge grant that portion of the Company's motion for summary
judgment regarding the loss of fish and deny the portion of its
motion dealing with the Tribe's claim to compensation for
exclusion from its usual and accustomed fishing sites. On March
21, 1994, U.S. District Judge Harold L. Ryan upheld Judge Boyle's
recommendation regarding fish losses and took the question of
compensation for exclusion from fishing sites under advisement.
On September 28, 1994, after reviewing responses and objections
on that issue, Judge Ryan rejected the Tribe's claim and granted
the final portion of the company's motion for summary judgment.
The Tribe has appealed Judge Ryan's decision to the Ninth Circuit
Court of Appeals and the case has been fully briefed and
submitted to the Court. No date has been set for oral argument on
the appeal.

The Company and the Tribe have reached agreement on a proposed
settlement of this case. The Nez Perce Tribal Executive Committee
has proposed a settlement and the Company will submit the
proposed settlement to its Board of Directors at the March board
meeting. If the Company's Board of Directors approves the
settlement, it will be submitted to appropriate State and Federal
regulators for their approval.

       Threatened and Endangered Snails

In mid-December 1992, the U.S. Fish and Wildlife Service (USFWS)
listed five species of Snake River snails as Threatened and
Endangered Species. Since that time, the Company has included
this possibility in all of its discussions regarding relicensing
and new hydro development.

The listing specifically mentions the impact that fluctuating
water levels related to hydroelectric operations may have on the
snails' habitat. Although most of the hydro facilities on that
reach of the Snake River are baseload facilities, some of them do
provide limited load-following capability. At present, there is
no certainty as to the effects, if any, that water fluctuations
caused by these facilities may have on the snails. While it is
possible that the listing could affect how Idaho Power operates
its existing hydroelectric facilities on the middle reach of the
Snake River, the Company believes that such changes will be minor
and will not present any undue hardship.

In 1995, as a part of its federal hydro relicensing process,
Idaho Power obtained a permit from the USFWS to study five
species of endangered Snake River snails. The Company's
biologists will conduct this study over the next three years,
focusing on potential snail habitat in the middle Snake River.
The Company's objective is to  gain scientific insight into how
or if these snails are affected by a variety of factors,
including hydropower production, water quality, and irrigation
run-off. The study will review how these and other factors
influence the status of the various colonies and their respective
habitats.

       Mountaineer Cleanup

In May 1993, the Company was notified that Bridger Coal Company
(BCC) was a potential contributor to a Superfund site involving
waste motor oil delivered to Mountaineer Refinery in Wyoming.
Idaho Energy Resources Company (IERCo), a wholly-owned subsidiary
of Idaho Power, owns one-third of BCC. In November 1993, BCC
agreed to be included on the list of parties potentially
responsible for this site. The estimated cleanup costs totaled
approximately $4.0 million. BCC's portion of the cleanup costs,
based on the amount of oil delivered to the site, was estimated
to be approximately 4.63 percent ($185,200). However, because
additional contributors are likely to be added to the list of
potentially responsible parties, BCC's final share of the cleanup
costs is likely to be considerably less. Most of the cleanup has
been completed, with the exception of a two-year program to
monitor ground water. To date, BCC has expended $84,700 in
cleanup costs and continues to carry $42,750 as an unfunded
liability as of December 31, 1995. IERCo is responsible for one-
third of BCC's share of the cleanup costs.

       Clean Air

Idaho Power has analyzed the Clean Air Act's effects on the
Company and its ratepayers. The Company's coal-fired plants in
Oregon and Nevada already meet the federal emission rate
standards for sulfur dioxide (SO2) and Idaho Power's coal-fired
plant in Wyoming meets that state's even more stringent SO2
regulations. Therefore, the Company foresees no adverse effects
on its operations with regard to SO2 emissions.

During 1994, the Company, together with PacifiCorp and Black
Hills Corporation, entered into Phase I substitution agreements
with Illinois Power Company. The agreements designate Units 1, 2,
3, and 4 of the Company's Jim Bridger thermal facility, together
with facilities owned by PacifiCorp and Black Hills Corporation,
as substitution units for Illinois Power's Baldwin #2. The
substitution agreements will allow the Company to grandfather in
less restrictive Phase I nitrous oxide emission requirements at
the Jim Bridger units. As a part of the agreements, the Company
negotiated the sale of a number of its Phase I SO2 emission
allowances to Illinois Power.

       Electric and Magnetic Fields

While scientific research has yet to establish any conclusive
link between electric and magnetic fields (EMFs) and human
health, the possibility has caused public concern in the United
States and abroad. Electric and magnetic fields exist wherever
there is electric current, whether the source is a high-voltage
transmission line or the simplest of electrical household
appliances. Concerns over possible health effects have prompted
regulatory efforts in several states to limit human exposure to
EMFs. Depending on what researchers ultimately discover and any
necessary regulations, it is possible that this issue could
affect a number of industries, including electric utilities.
However, it is difficult at this time to estimate what effects,
if any, the EMF issue could have on the Company and its
operations.

     Competition and Strategic Planning

Competition is increasing in the electric utility industry, due
to a variety of developments. In response, Idaho Power continues
to proceed with a strategic planning process. The goal of this
process is to anticipate and fully integrate into Company
operations any legislative, regulatory, environmental,
competitive, or technological changes. With its low energy
production costs, Idaho Power is well-positioned to enter a more
competitive environment and is taking action to preserve its low-
cost competitive advantage.

The Company believes that the future of the electric utility
industry will be characterized by the right of customers to
choose their own electric service provider. To remain successful,
Idaho Power must continue to provide value to its shareholders in
the face of this new competitive environment. The Company's
vision involves three strategies for creating this value:
selective and efficient use of capital; an enhanced customer
orientation; and innovative, efficient operations. Because future
prices for power will be determined more by market forces and
less by regulatory administration, the Company must be very
selective and efficient in the use and allocation of capital.
Idaho Power will invest in improving and expanding its core
business, in developing new opportunities beyond its current
service territory, and in continuing to develop non-regulated
opportunities consistent with the Company's core competencies.

Based on this vision and the Company's efforts to increase
shareholder and customer value, Idaho Power is transforming its
operations to improve both efficiency and customer service. Teams
of employees are redesigning work processes. In some cases, these
improved processes are successfully in place. During 1995, Idaho
Power announced plans for voluntary and involuntary separation
packages in the event of workforce reductions resulting from its
reorganization efforts. The packages include compensation based
on years of service and address medical benefits and transition
services. The Company is reorganizing on a department-by-
department basis and anticipates that this redesign effort will
continue at least through 1996.

To accommodate this redesign effort and to implement its vision,
Idaho Power filed a new regulatory proposal with the IPUC on
August 3, 1995 (see Regulatory Settlement). The IPUC approved a
Settlement Stipulation that provides for a general rate freeze
through the end of 1999 and allows the accelerated amortization
of regulatory liabilities associated with accumulated deferred
investment tax credits (ADITCs), as necessary, to provide a
minimum return on actual year-end common equity of 11.5 percent.
The rate freeze and the accelerated amortization of regulatory
liabilities associated with ADITCs gives the Company time to
pursue and to implement its efficiency and growth initiatives
with the assurance of at least a reasonable level of financial
performance without the need to change customer prices.

     Contract Cancellation

On June 3, 1994, the IPUC approved the buyout and cancellation of
a January 22, 1993 Firm Energy Sales Agreement (FESA) with
Meridian Generating Company, L. P. (MGC). The FESA was a 25-year
agreement with MGC for the output from a 54 MW natural gas-fired
combined cycle cogeneration facility located in Meridian, Idaho.
The Company estimates that the revenue requirement savings, net
of cancellation charges paid to MGC, are between $130 and $170
million.

     Western Regional Transmission Association

The FERC has approved the formation of a transmission association
of western electric power suppliers and buyers. The members of
this association organized to provide one another with comparable
electricity transmission services. Idaho Power is a charter
member of the new organization, called the Western Regional
Transmission Association (WRTA). The WRTA is the first group of
its kind in the United States, and is indicative of changes
forthcoming in the electric utility industry. The primary
purposes of the WRTA will be to facilitate open access to
transmission services and to resolve related disputes. These
concerns are among the fundamental issues being addressed as the
electric utility industry becomes more competitive and less
regulated, in accordance with the National Energy Policy Act of
1992. The 43 members of the WRTA own about 70 percent of the
transmission system in the U.S. portion of the Western Systems
Coordinating Council.

     FERC Proposed Rule

On March 29, 1995, the FERC issued a NOPR on Open-Access Non-
Discriminatory Transmission Services by Public and Transmitting
Utilities, and a supplemental NOPR on Recovery of Stranded Costs.
These NOPRs would require utilities owning transmission lines to
file non-discriminatory rates available to all buyers and sellers
of electricity, would require the utilities to use that tariff
for their own wholesale sales and purchases, and would allow the
utilities to recover stranded costs. In addition, the Company has
submitted to the FERC an open-access transmission tariff for its
existing transmission facilities. The Company anticipates that
the final rules could take effect in 1996.

     Accounting Issues

In March 1995, the Financial Accounting Standards Board (FASB)
issued SFAS No. 121, "Accounting for the Impairment of Long-Lived
Assets and for Long-Lived Assets to be Disposed Of", which is
effective in 1996. This standard requires that long-lived assets
be reviewed for impairment whenever events or changes in
circumstances indicate that the carrying amount may not be
recoverable. An impairment loss would be recognized if the sum of
the estimated future undiscounted cash flows to be generated by
an asset is less than its carrying value. The amount of the loss
would be based on a comparison of book value to fair value. SFAS
No. 121 also amends SFAS No. 71, "Accounting for the Effects of
Certain Types of Regulation," to require write-off of a
regulatory asset if it is no longer probable that future revenues
will recover the cost of the asset. SFAS No. 121 does not affect
Idaho Power at this time. However, the Company will review the
standard on an ongoing basis.

In October 1995,  the FASB issued SFAS No. 123, "Accounting for
Stock-Based Compensation." This standard establishes a fair-value
method of accounting for stock options and other equity
instruments. It permits entities to continue applying the
intrinsic-value method included in Statements of the Accounting
Principles Board (APB-25), but requires the entities to disclose
information in accordance with SFAS 123 if they choose to
continue using the intrinsic-value method. Among the information
that entities must disclose is  the pro-forma amount of net
income and earnings per share as if the fair-value method was
used. The disclosure requirements are applicable for financial
statements for fiscal years beginning after December 15, 1995.
The Company has chosen to use the APB-25 intrinsic-value method,
but has estimated compensation costs applicable to its Restricted
Stock Plan and accrued them as a compensation expense in 1995.

     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 relicensing process, the Company
anticipates that its efforts will be successful. At this point,
however, the Company cannot predict what type of environmental or
operational requirements it may face, nor can it estimate the
eventual cost of relicensing.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA


INDEX TO FINANCIAL STATEMENTS
AND FINANCIAL STATEMENT SCHEDULES



                                                             PAGE

Management's Responsibility for Financial Statements          41

Consolidated Financial Statements:

 Consolidated Balance Sheets as of December 31, 1995,
  1994 and 1993                                             42-43

 Consolidated Statements of Income for the Years
  Ended December 31, 1995, 1994 and 1993                      44

 Consolidated Statements of Retained Earnings for
  the Years Ended December 31, 1995, 1994 and 1993            45

 Consolidated Statements of Capitalization as of
  December 31, 1995, 1994 and 1993                            46

 Consolidated Statements of Cash Flows for the Years
  Ended December 31, 1995, 1994 and 1993                      47

 Notes to Consolidated Financial Statements                 48-58

Independent Auditors' Report                                  59

Supplemental Financial Information (Unaudited)                60

Supplemental Schedule for the Years Ended December 31,
 1995, 1994 and 1993:

   Schedule II-  Consolidated Valuation and
   Qualifying Accounts                                        67


 MANAGEMENT'S RESPONSIBILITY FOR FINANCIAL STATEMENTS


The management of Idaho Power Company is responsible for the
preparation and presentation of the information and
representations contained in the accompanying financial
statements. The financial statements have been prepared in
conformance with generally accepted accounting principles for a
rate regulated enterprise. Where estimates are required to be
made in preparing the financial statements, management has
applied its best judgment as to the adequacy of the estimates
based upon all available information.

The Company maintains systems of internal accounting controls and
related policies and procedures. The systems are designed to
provide reasonable assurance that all assets are protected
against loss or unauthorized use. Also, the systems provide that
transactions are executed in accordance with management's
authorization and properly recorded to permit preparation of
reliable financial statements. The systems are supported by a
staff of corporate accountants and internal auditors who, among
other duties, evaluate and monitor the systems of internal
accounting control in coordination with the independent auditors.
The staff of internal auditors conduct special and operational
audits in support of these accounting controls throughout the
year.

The Board of Directors, through its Audit Committee comprised
entirely of outside directors, meets periodically with
management, internal auditors and the Company's independent
auditors to discuss auditing, internal control and financial
reporting matters. To ensure their independence, both the
internal auditors and independent auditors have full and free
access to the Audit Committee.

The financial statements have been audited by Deloitte & Touche
LLP, the Company's independent auditors, who were responsible for
conducting their audit in accordance with generally accepted
auditing standards.


/s/ Joseph W. Marshall             /s/ J. LaMont Keen
Joseph W. Marshall                 J. LaMont Keen
Chairman and                       Vice President and Chief
Chief Executive Officer            Financial Officer


               /s/ Harold J. Hochhalter
               Harold J. Hochhalter
               Controller and Chief Accounting Officer



IDAHO POWER COMPANY
CONSOLIDATED BALANCE SHEETS
ASSETS

                                                    December 31,
                                            1995       1994         1993
                                               (Thousands of Dollars)

 ELECTRIC PLANT (Notes 1, 5 and 10):
 In service (at original cost)          $2,481,830   $2,383,898   $2,249,723
 Accumulated provision for depreciation   (830,615)    (775,033)    (728,979)
  In service - Net                       1,651,215    1,608,865    1,520,744
 Construction work in progress              20,564       46,628       92,682
 Held for future use                         1,106        1,150        2,958
 
    Electric plant - Net                 1,672,885    1,656,643    1,616,384
 
 INVESTMENTS AND OTHER PROPERTY             16,826       18,034       20,772
 
 CURRENT ASSETS:
 Cash and cash equivalents (Note 1)          8,468        7,748        8,228
 Receivables:
  Customer                                  33,357       31,889       29,741
  Allowance for uncollectible accounts      (1,397)      (1,377)      (1,377)
  Notes                                      5,134        4,962        5,616
  Employee notes receivable                  4,648        5,444        5,909
  Other                                     10,770        4,316        1,858
 Accrued unbilled revenues (Note 1)         25,025       29,115       25,583
 Materials and supplies 
   (at average cost)                        25,937       24,141       23,372
 Fuel stock (at average cost)               13,063       11,310       11,553
 Prepayments (Note 9)                       20,778       21,398       20,975
 Regulatory assets associated
  with income taxes (Note 1)                 5,777        5,674        4,914
 
    Total current assets                   151,561      144,620      136,372
 
 DEFERRED DEBITS:
 American Falls and Milner water rights     32,440       32,605       32,755
 Company-owned life insurance (Note 9)      56,066       49,510       45,294
 Regulatory assets associated with 
  income taxes (Note 1)                    200,379      179,311      171,569
 Regulatory assets - other (Note 1)         68,348       67,713       35,036
 Other                                      43,248       43,380       39,235
 
    Total deferred debits                  400,481      372,519      323,889
 
    TOTAL                               $2,241,753   $2,191,816   $2,097,417

The accompanying notes are an integral part of these statements.


IDAHO POWER COMPANY
CONSOLIDATED BALANCE SHEETS
CAPITALIZATION AND LIABILITIES

                                                    December 31,
                                           1995        1994        1993
                                              (Thousands of Dollars)

 CAPITALIZATION (See Page 44):
 Common stock equity (Note 3):
  Common stock - $2.50 par value 
    (shares authorized 50,000,000; 
    shares outstanding 1995 - 
    37,612,351, 1994 - 37,612,351
    and 1993 - 37,085,055              $   94,031   $   94,031   $   92,713
  Premium on capital stock                363,044      363,063      350,882
  Capital stock expense                    (4,127)      (4,132)      (4,128)
  Retained earnings                       229,827      220,838      222,900
 
    Total common stock equity             682,775      673,800      662,367
 Preferred stock (Note 4)                 132,181      132,456      132,751
 Long-term debt (Note 5)                  672,618      693,206      693,780
 
    Total capitalization                1,487,574    1,499,462    1,488,898
 
 CURRENT LIABILITIES:
 Long-term debt due within one year        20,517          517          466
 Notes payable (Note 7)                    53,020       55,000        4,000
 Accounts payable                          40,483       32,063       31,912
 Taxes accrued                             15,409       16,394       15,452
 Interest accrued                          14,785       14,755       14,920
 Accumulated deferred income taxes 
 (Notes 1 & 2)                              5,777        5,674        4,914
 Other                                     12,866       12,574       13,731
 
    Total current liabilities             162,858      136,977       85,395
 
 DEFERRED CREDITS:
 Regulatory liabilities associated
  with accumulated deferred 
  investment tax credits (Notes 
  1 and 2)                                 70,507       71,593       72,013
 Accumulated deferred income taxes
  (Notes 1 and 2)                         408,394      375,252      353,366
 Regulatory liabilities associated
  with income taxes (Note 1)               34,554       35,090       34,968
 Regulatory liabilities - other 
 (Note 1)                                     789          626        4,235
 Other (Note 9)                            77,076       72,816       58,542
 
    Total deferred credits                591,321      555,377      523,124
 
 COMMITMENTS AND CONTINGENT
 LIABILITIES (Note 8)
 
    TOTAL                              $2,241,753   $2,191,816   $2,097,417
 
The accompanying notes are an integral part of these statements.


IDAHO POWER COMPANY
CONSOLIDATED STATEMENTS OF INCOME

                                             Year Ended December 31,
                                              1995       1994       1993
                                    (Thousands of Dollars)

  REVENUES (Note 1)                         $545,621   $543,658   $540,402
  EXPENSES:
  Operation:
    Purchased power (Notes 8 and 10)          54,586     60,216     45,361
    Fuel expense (Note 10)                    54,691     94,888     87,855
    Power cost adjustment (Note 1)             7,292    (12,076)    (1,551)
    Other                                    126,714    123,328    122,803
  Maintenance                                 35,953     43,490     43,136
  Depreciation (Note 1)                       67,415     60,202     58,724
  Taxes other than income taxes               22,979     23,945     22,129
    Total expenses                           369,630    393,993    378,457
  
  INCOME FROM OPERATIONS                     175,991    149,665    161,945
  
  OTHER INCOME:
  Allowance for equity funds used
    during construction (Note 1)                 (16)     1,680      3,060
  Other - Net                                 14,372     10,480      9,924
     Total other income                       14,356     12,160     12,984
  
  INTEREST CHARGES:
  Interest on long-term debt                  51,146     51,172     53,706
  Other interest (Notes 1 and 7)               5,309      3,261      2,750
     Total interest charges                   56,456     54,433     56,456
   Allowance for borrowed funds used during
    construction (Note 1)                     (1,442)    (1,781)    (2,465)
     Net interest charges                     55,014     52,652     53,991
 
 INCOME BEFORE INCOME TAXES                  135,333    109,173    120,938
 
 INCOME TAXES (Notes 1 and 2)                 48,412     34,243     36,474
 
 NET INCOME                                   86,921     74,930     84,464
 Dividends on preferred stock (Note 4)         7,991      7,398      6,009
 
 EARNINGS ON COMMON STOCK                   $ 78,930   $ 67,532   $ 78,455
 
 AVERAGE COMMON SHARES
 OUTSTANDING (000)                            37,612     37,499     36,675
   
 EARNINGS PER SHARE OF
 COMMON STOCK (Note 3)                      $   2.10   $   1.80   $   2.14

The accompanying notes are an integral part of these statements.



IDAHO POWER COMPANY
CONSOLIDATED STATEMENTS OF RETAINED EARNINGS

                                                Year Ended December 31,
                                              1995       1994       1993
                                                (Thousands of Dollars)

 RETAINED EARNINGS
 Beginning of year                          $220,838   $222,900   $212,404
 
 NET INCOME                                   86,921     74,930     84,464
 
 Total                                       307,759    297,830    296,868
 
 DIVIDENDS:
 Preferred stock (Note 4)                      7,991      7,398      6,009
 Common stock (per share: 
 1995 - 1993 - $1.86) (Note 3)                69,941     69,594     67,959
 
    Total dividends                           77,932     76,992     73,968
 
 RETAINED EARNINGS
 End of year                                $229,827   $220,838   $222,900

The accompanying notes are an integral part of these statements.



IDAHO POWER COMPANY
CONSOLIDATED STATEMENTS OF CAPITALIZATION

                                                   December 31,
                                     1995    %     1994     %     1993    %
                                              (Thousands of Dollars)
 
 COMMON STOCK EQUITY (Note 3):
 Common stock                    $   94,031     $   94,031     $   92,713
 Premium on capital stock           363,044        363,063        350,882
 Capital stock expense               (4,127)        (4,132)        (4,128)
 Retained earnings                  229,827        220,838        222,900
    Total common stock equity       682,775  46    673,800  45    662,367  44
 PREFERRED STOCK (Note 4):
 4% preferred stock                  17,181         17,456         17,751
 7.68% Series, serial preferred 
 stock                               15,000         15,000         15,000
 8.375% Series, serial preferred 
 stock                               25,000         25,000         25,000
 Auction rate preferred stock        50,000         50,000         50,000
 7.07% Series, serial 
 preferred stock                     25,000         25,000         25,000
    Total preferred stock           132,181   9    132,456   9    132,751   9
 LONG-TERM DEBT (Note 5):
 First mortgage bonds:
  5 1/4 % Series due 1996            20,000*        20,000         20,000
  5.33  % Series due 1998            30,000         30,000         30,000
  8.65  % Series due 2000            80,000         80,000         80,000
  6.40  % Series due 2003            80,000         80,000         80,000
  8   % Series due 2004              50,000         50,000         50,000
  9.50  % Series due 2021            75,000         75,000         75,000
  7.50  % Series due 2023            80,000         80,000         80,000
  8 3/4 % Series due 2027            50,000         50,000         50,000
  9.52  % Series due 2031            25,000         25,000         25,000
    Total first mortgage bonds      490,000        490,000        490,000
 *Amount due within one year        (20,000)           -              -
    Net first mortgage bonds        470,000        490,000        490,000
 Pollution control revenue bonds:
  5.90  % Series due 2003            24,200*        24,650*        25,050*
  6.0   % Series due 2007            24,000         24,000         24,000
  7 1/4 % Series due 2008             4,360          4,360          4,360
  7 5/8 % Series 1983 - 1984 
  due 2013 - 2014                    68,100         68,100         68,100
  8.30  % Series 1984 due 2014       49,800         49,800         49,800
    Total pollution control 
    revenue bonds                   170,460        170,910        171,310
 *Amount due within one year           (450)          (450)          (400)
    Net pollution control revenue 
    bonds                           170,010        170,460        170,910
 REA notes                            1,700          1,768          1,834
 Amount due within one year             (67)           (67)           (66)
    Net REA notes                     1,633          1,701          1,768
 American Falls bond guarantee       20,740         20,905         21,055
 Milner Dam note guarantee           11,700         11,700         11,700
 Unamortized premium/discount-
  Net (Note 1)                       (1,466)        (1,560)        (1,653)
    Total long-term debt            672,618  45    693,206  46    693,780  47
 TOTAL CAPITALIZATION            $1,487,574 100 $1,499,462 100 $1,488,898 100
The accompanying notes are an integral part of these statements.


IDAHO POWER COMPANY
CONSOLIDATED STATEMENTS OF CASH FLOWS
                                                   Year Ended December 31,
                                                  1995      1994      1993
                                                   (Thousands of Dollars)
 OPERATING ACTIVITIES:
 Cash received from operations:
  Retail revenues                               $468,821   $457,202  $434,625
  Wholesale revenues                              59,260     62,110    84,726
  Other revenues                                  22,825     23,711    23,411
 Fuel paid                                       (61,741)   (94,530)  (83,885)
 Purchased power paid                            (52,526)   (62,592)  (50,246)
 Other operation & maintenance paid             (154,209)  (171,774) (162,014)
 Interest pd. (incl. long and short-term 
 debt only)                                      (54,303)   (52,376)  (56,348)
 Income taxes paid                               (40,402)   (16,518)  (32,512)
 Taxes other than income taxes paid              (22,939)   (21,698)  (22,165)
 Other operating cash receipts and payments 
 - Net                                             3,644      2,122     8,213
     Net cash provided by operating activities   168,430    125,657   143,805
 FINANCING ACTIVITIES:
 First mortgage bonds issued                        -         -       188,136
 PC bond fund requisitions/other long-term debt     -         -         5,594
 Common stock issued                                -        13,402    26,781
 Preferred stock issued                             -         -        24,781
 Short-term borrowings - Net                      (2,000)   51,000    (2,140)
 Long-term debt retirement                          (519)     (466) (191,878)
 Preferred stock retirement                         (151)     (166)      (65)
 Dividends on preferred stock                     (7,888)   (7,565)   (5,914)
 Dividends on common stock                       (69,967)  (69,594)  (67,959)
 Other sources                                      (781)     -         -
     Net cash - financing activities             (81,306)  (13,389)  (22,664)
 INVESTING ACTIVITIES:
 Additions to utility plant                      (83,965) (110,523) (122,949)
 Conservation                                     (5,688)   (6,830)   (6,687)
 Other                                             3,249     4,605    11,757
     Net cash - investing activities             (86,404) (112,748) (117,879)
 Change in cash and cash equivalents                 720      (480)    3,262
 Cash and cash equivalents beginning of year       7,748     8,228     4,966
     Cash and cash equivalents end of year      $  8,468  $  7,748  $  8,228
 RECONCILIATION OF NET INCOME TO NET
 CASH PROVIDED BY OPERATING
 ACTIVITIES:
 Net income                                     $ 86,921  $ 74,930  $ 84,464
 Adjustments to reconcile net income to net cash:
  Depreciation                                    67,415    60,202    58,724
  Deferred income taxes                           11,539    14,265     5,997
  Investment tax credit - Net                     (1,086)   (1,064)   (1,583)
  Allowance for funds used during construction    (1,425)   (3,461)   (5,525)
  Postretirement benefits funding 
  (excl pensions)                                 (2,857)   (5,182)   (7,481)
  Changes in operating assets and liabilities:
    Accounts receivable                            5,285      (635)    2,360
    Fuel inventory                                (7,050)      358     3,970
    Accounts payable                               2,061    (2,376)   (4,885)
    Taxes payable                                 (2,519)    7,296    (1,141)
    Interest payable                               2,100     1,656    (1,010)
  Other - Net                                      8,046   (20,332)    9,915
    Net cash provided by operating activities   $168,430  $125,657  $143,805

The accompanying notes are an integral part of these statements.


IDAHO POWER COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES:

PRINCIPLES OF CONSOLIDATION - The consolidated financial statements
include the accounts of the Company and its wholly-owned subsidiaries,
Idaho Energy Resources Co (IERCo), Ida-West Energy Company (Ida-West),
IDACORP, Inc., Idaho Utility Products Company (IUPCo), and Stellar
Dynamics. All significant intercompany transactions and balances have
been eliminated in consolidation.

SYSTEM OF ACCOUNTS - The Company is an electric utility and its
accounting records conform to the Uniform System of Accounts prescribed
by the Federal Energy Regulatory Commission (FERC) and adopted by the
public utility commissions of Idaho, Oregon, Nevada and Wyoming.

ELECTRIC PLANT - The cost of additions to electric plant in service
represents the original cost of contracted services, direct labor and
material, allowance for funds used during construction and indirect
charges for engineering, supervision and similar overhead items.
Maintenance and repairs of property and replacements and renewals of
items determined to be less than units of property are charged to
operations. For property replaced or renewed the original cost plus
removal cost less salvage is charged to accumulated provision for
depreciation while the cost of related replacements and renewals is
added to electric plant.

ALLOWANCE FOR FUNDS USED DURING CONSTRUCTION (AFDC) - The allowance, a
non-cash item, represents the composite interest costs of debt, shown
as a reduction to interest charges, and a return on equity funds, shown
as an addition to other income, used to finance construction. While
cash is not realized currently from such allowance, it is realized
under the ratemaking process over the service life of the related
property through increased revenues resulting from higher rate base and
higher depreciation expense. Based on the uniform formula adopted by
the FERC, the Company's weighted average monthly AFDC rates for 1995,
1994 and 1993 were 6.1 percent, 8.2 percent and 9.6 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.

POWER COST ADJUSTMENT- The Company has in place, in its Idaho
jurisdiction, a Power Cost Adjustment (PCA) mechanism which allows
Idaho's retail customer rates to be adjusted annually to reflect the
Idaho share of forecasted net power supply costs. Deviations from
forecasted costs are deferred with interest and then adjusted (trued-
up) in the subsequent year.

DEPRECIATION - All electric plant is depreciated using the straight-
line method. Annual depreciation provisions as a percent of average
depreciable electric plant in service approximated 2.90 percent in
1995, 2.93 percent in 1994 and 2.92 percent in 1993 and are considered
adequate to amortize the original cost over the estimated service lives
of the properties.

INCOME TAXES - The Company follows the liability method of computing
deferred taxes on all temporary differences between book and tax basis
of assets and liabilities and adjust deferred tax liabilities and
assets for enacted changes in tax laws or rates. Consistent with orders
and directives of the Idaho Public Utilities Commission (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 plant additions. ITC earned on regulated assets are
deferred and amortized to income over the estimated service lives of
the related properties and credits earned on non-regulated assets or
investments are recognized in the year earned.

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 subject to Internal Revenue Service (IRS) and the Idaho State
Tax Commission (STC) approvals. The IRS application for approval has
been filed and the STC has 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.

CASH AND CASH EQUIVALENTS - For purposes of reporting cash flows, cash
and cash equivalents include cash on hand and highly liquid temporary
investments with original maturity dates of three months or less.

REGULATION OF UTILITY OPERATIONS - The Company follows Statement of
Accounting Standards (SFAS) No. 71, "Accounting for the Effects of
Certain Types of Regulation", and its financial statements reflect the
effects of the different ratemaking principles followed by the various
jurisdictions regulating the Company. Pursuant to SFAS 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 1995, 1994 and 1993:

                          1995               1994               1993
                     Assets Liabilities Assets Liabilities Assets Liabilities
                                      (Millions of Dollars)
  
  Income taxes       $206.2   $ 34.6    $185.0   $ 35.1    $176.5   $ 35.0
  Conservation         36.3               29.7               21.2
  Employee benefits     8.3                9.5                7.4
  Other                23.7      0.7      28.5      0.6       6.4      4.2
  Accumulated 
   deferred investment 
   tax credits         70.5               71.6               72.0
    Total            $274.5   $105.8    $252.7   $107.3    $211.5   $111.2

The regulatory environment is becoming more complex resulting from the
expanding effects of competition. In the event that recovery of cost
through rates becomes unlikely or uncertain, this may force the Company
away from the cost of service ratemaking and 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. At December 31,
1995, the Company had $17.6 million of regulatory assets that were not
earning a return on investment excluding the $206.2 million that
relates to income taxes.

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 1995 have been reclassified to conform with the current year's
presentation. Net income was not affected by these reclassifications.

2. INCOME TAXES:
                                                   1995       1994      1993
                                                     (Thousands of Dollars)
 A reconciliation between the 
 statutory federal income tax rate 
 and the effective rate is as follows:
 Computed income taxes based on
  statutory federal income tax rate             $ 47,367  $ 38,210   $ 42,328
 Change in taxes resulting from:
  AFUDC                                             (504)   (1,211)    (1,798)
  Investment tax credits                          (2,837)   (3,351)    (2,898)
  Repair allowance                                (3,150)   (1,575)    (2,975)
  Elimination of amounts provided
    in prior years                                (1,963)   (2,607)    (4,686)
  Current state income taxes                       3,275     1,496      2,693
  Depreciation                                     5,493     2,812      4,116
  Other                                              731       469      (306)
 Total provision for federal and state 
  income taxes                                  $ 48,412  $ 34,243  $ 36,474
 Effective tax rate                                35.8%     31.4%     30.2%
The provision for income taxes consists of the following:
 Income taxes currently payable:
  Federal                                       $ 33,456  $ 19,617  $ 27,892
  State                                            4,503     1,425     4,168
    Total                                         37,959    21,042    32,060
 Income taxes deferred - Net of amortization:
  Federal                                         10,904    12,595     5,928
  State                                              635     1,670        69
    Total                                         11,539    14,265     5,997
 Investment and other tax credits:
  Deferred                                         1,751     1,643     1,315
  Restored                                        (2,837)   (2,707)   (2,898)
    Total                                         (1,086)   (1,064)   (1,583)
 Total provision for income taxes               $ 48,412  $ 34,243  $ 36,474
The tax effects of significant items comprising the
 Company's net deferred tax liability are as follows:
 Deferred tax Liabilities:
  Property, plant and equipment                 $237,655  $225,444  $217,343
  Regulatory asset                               206,156   184,986   176,483
  Investment tax credit                           70,507    71,593    72,013
  Conservation programs                           11,746     4,704     2,739
  Other                                           18,489    17,811    11,384
    Total                                        544,553   504,538   479,962
 Deferred tax assets:
  Regulatory liability                            34,554    35,090    34,968
  Advances for construction                       14,823    10,542     8,103
  Other                                           10,498     6,387     6,598
    Total                                         59,875    52,019    49,669
 Net deferred tax liabilities                   $484,678  $452,519  $430,293


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 for.


3. COMMON STOCK:

Changes in shares of the common stock of the Company for 1995, 1994 and
1993 were as follows:

                                              Common Stock
                                                      $2.50 Par  Premium on 
                                             Shares   Value      Capital Stock
                                                    (Thousands of Dollars)
  Balance at December 31, 1992              36,186,527   $90,466   $326,338
   Gain on reacquired 4% preferred
    stock (Note 4)                                -         -            50
  Stock purchase plans                         898,528     2,247     24,494
  
  Balance at December 31, 1993              37,085,055    92,713    350,882
  Gain on reacquired 4% preferred
    stock (Note 4)                                -         -           126
  Stock purchase plans                         527,296     1,318     12,055
  
  Balance at December 31, 1994              37,612,351    94,031    363,063
  Gain on reacquired 4% preferred
    stock (Note 4)                                -         -           117
  Restricted Stock Plan (Note 9)                  -         -          (136)
  
  Balance at December 31, 1995              37,612,351   $94,031   $363,044

During the period of January 1993 through May 1994, the Company issued
original issue shares of common stock for its Dividend Reinvestment and
Stock Purchase Plan and the Employee Savings Plan. During 1993 and 1994
common shares totaling 898,528 and 527,296 respectively, were issued to
these plans.

As of December 31, 1995, the Company had 2,791,321 of its authorized
but unissued shares of common stock reserved for future issuance under
its Dividend Reinvestment and Stock Purchase Plan and Employee Savings
Plan.

On January 11, 1990, the Board of Directors adopted a Shareowner Rights
Plan (Plan). Under the Plan, the Company declared a distribution of one
Preferred Stock Right (Right) for each of the Company's outstanding
Common shares held on January 29, 1990 or issued thereafter. The Rights
are currently not exercisable and will be exercisable only if a person
or group (Acquiring Person) either acquires ownership of 20 percent or
more of the Company's Voting Stock or commences a tender offer that
would result in ownership of 20 percent or more. The Company may redeem
the Rights at a price of $0.01 per Right anytime prior to acquisition
by an Acquiring Person of a 20 percent position.

Following the acquisition of a 20 percent position, each Right will
entitle its holder, subject to regulatory approval, to purchase for $85
that number of shares of Common Stock or Preferred Stock having a
market value of $170.

If after the Rights become exercisable, the Company is acquired in a
merger or other business combination, 50 percent or more of its
consolidated assets or earnings power are sold or the Acquiring Person
engages in certain acts of self-dealing, each Right entitles the holder
to purchase for $85, shares of the acquiring company's Common Stock
having a market value of $170. Any Rights that are or were held by an
Acquiring Person become void if either of these events occurs. The
Rights expire on January 11, 2000.


4. PREFERRED STOCK:

The number of shares of preferred stock outstanding at December 31,
1995, 1994 and 1993 were as follows:

                                       Shares Outstanding at
                                            December 31,       Call Price
                                       1995     1994     1993   Per Share
  Preferred stock:
   Cumulative, $100 par value:
  
    4% preferred stock (authorized
     215,000 shares)                  171,813  174,556  177,506      $104.00
  
    Serial preferred stock, 7.68%
     Series (authorized 150,000 
     shares)                          150,000  150,000  150,000      $102.97
  
   Serial preferred stock, cumulative,
    without par value; total of 
    3,000,000 shares authorized:
  
    8.375% Series, $100 stated value,
    (authorized 250,000 shares)(a)    250,000  250,000  250,000  $105.58 
                                                                   to $100.37
  
    7.07% Series, $100 stated value,
     (authorized 250,000 shares)(b)   250,000  250,000  250,000  $103.535 
                                                                  to $100.354
  
    Auction rate preferred stock,
     $100,000 stated value,
     (authorized 500 shares)(c)           500      500      500  $100,000.00
  
   Total                              822,313  825,056  828,006  

(a)   Not redeemable prior to October 1, 1996.
(b)   Not redeemable prior to July 1, 2003.
(c)   Dividend rate at December 31, 1995 was 4.49% and ranged between
      4.36%  and 4.71% during the year.

During 1995, 1994 and 1993 the Company reacquired and retired 2,743;
2,950 and 1,229 shares of 4% preferred stock resulting in a net
addition to premium on capital stock of $117,346, $126,066 and $50,151
respectively. As of December 31, 1995 the overall effective cost of all
outstanding preferred stock was 6.28 percent.


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 2000
are $20,000,000 in 1996, $30,000,000 in 1998 and $80,000,000 in 2000.
Sinking fund requirements for the first mortgage bonds outstanding at
December 31, 1995 are $5,398,000 per year. These requirements may be
met by the deposit of cash, deposit of bonds, or by certification of
property additions at the rate of 167% of requirements. The Company's
practice is to certify additional property to meet the sinking fund
requirements. In September 1993, 1994, and 1995 $400,000, $400,000 and
$450,000 respectively, of the 5.90% Series, Pollution Control Revenue
Bonds, were retired pursuant to sinking fund requirements for those
years. Sinking fund requirements during the five-year period ending
2000 for pollution control bonds outstanding at December 31, 1995 are
$450,000 in 1996 and $500,000 in 1997 through 2000. At December 31,
1993, 1994 and 1995, the overall effective cost of all outstanding
first mortgage bonds and pollution control revenue bonds for all three
years was 8.02 percent.


6. FAIR VALUE OF FINANCIAL INSTRUMENTS:

The estimated fair value of the Company's financial instruments have
been determined by the Company using available market information and
appropriate valuation methodologies. The use of different market
assumptions and/or estimation methodologies may have a material effect
on the estimated fair value amounts.

Cash and cash equivalents, customer and other receivables, notes
payable, accounts payable, interest accrued, and taxes accrued are
reported at their carrying value as these are a reasonable estimate of
their fair value. The total estimated fair value of long-term debt was
approximately $762,575,000 for 1993, $682,647,000 for 1994 and
$731,168,000 for 1995. The estimated fair values for long-term debt are
based upon quoted market prices of the same or similar issues.


7. NOTES PAYABLE:

At January 1, 1996, the Company had regulatory authority to incur up to
$150,000,000 of short-term indebtedness. Under this authority, total
lines of credit maintained with various banks amounted to $85,000,000.
Under annual borrowing arrangements with these banks, the Company is
required to pay a fee of 8/100 of 1 percent on the available and
committed lines of credit. Commercial paper may be issued in an amount
not to exceed 25 percent of revenues for the latest twelve-month period
subject to the $150,000,000 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,
                                              1995      1994      1993
                                              (Thousands of Dollars)
  Balance at end of year                     $53,020   $55,000   $4,000
  Effective annual interest rate 
  at end of year                                6.0%      6.1%     6.9%   

  (a)   Effective rate has been inflated by the commitment fees being
        larger than the interest paid for the year.
        If the commitment fees were excluded the effective annual interest
        rate at end of the year would have been 3.6%.

8. COMMITMENTS AND CONTINGENT LIABILITIES:

Commitments under contracts and purchase orders relating to the
Company's program for construction and operation of facilities amounted
to approximately $2,600,000 at December 31, 1995. 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 65 on-line cogeneration
and small power production facilities with contracts ranging from 1 to
32 years. Under these contracts the Company could be required to
purchase up to 782,000 (MWH) annually. During the fiscal year ended
December 31, 1995, the Company purchased 654,000 (MWH) at a cost of
$38.0 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 Plan - The Company implemented two annual incentive plans
effective January 1, 1995. The Executive Annual Incentive Plan and the
Employee Incentive Plan tie a portion of each employee's compensation
to achieving annual operational and financial goals. The plans share
common goals designed to promote safety, control capital expenditures,
control operation and maintenance expenses and increase annual earnings
per share. At December 31, 1995 the Company had recorded $2,898,785 of
incentive for the Plans.

Restricted Stock Plan - The 1994 Restricted Stock Plan ("Plan")
approved by shareholders at the May 1994 Annual Meeting was implemented
January 1, 1995 as an equity-based long-term incentive plan. The
performance-based grant approach and administrative guidelines for the
Plan were developed by the Compensation Committee of the Board of
Directors ("Committee") during 1994. At December 31, 1995, there were
370,000 shares reserved for the Plan. The first grant under the Plan
was made to all officers during January 1995. For the first grant, the
Committee has selected a three-year restricted period beginning January
1, 1995, through December 31, 1997, with a single financial performance
goal of Cumulative Earnings Per Share ("CEPS"). Final award amounts
will depend on the attainment by the Company of the CEPS performance
goal established by the Committee and may be prorated in the event of
death, disability or retirement of an officer based on the number of
whole months of service the officer completes during the Restricted
Period.  Upon the officer's termination of employment during the
Restricted Period for any other reason, all such shares will be
forfeited by the officer to the Trustee.

During 1995, the Company purchased and granted 9,480 shares of the
Company's common stock for this Plan. Of this amount 360 shares were
forfeited in 1995. Restricted stock awards are compensatory awards and
the Company accrued compensation expense of $91,200 for 1995 (which was
charged to operations) based upon the market value of the earned
shares.

Pension Plan - The Company maintains a trusteed noncontributory defined
benefit pension plan for all employees who work 1,000 hours or more
during a calendar year. The benefits under the plan are based on years
of service and the employee's final average earnings. The Company's
policy is to fund with an independent corporate trustee at least the
minimum required under the Employee Retirement Income Security Act of
1974 but not more than the maximum amount deductible for income tax
purposes. The Company funded $5.9 million in 1995, $5.5 million in 1994
and $5.0 million in 1993. The plan's assets held by the trustee consist
primarily of listed stocks (both U.S. and foreign), fixed income
securities and investment grade real estate.

Deferred Compensation Plan - The Company has a nonqualified, deferred
compensation plan for certain senior management employees and directors
that provides for supplemental retirement and death benefit payments to
the participant and his or her family. The plan is being financed by
life insurance policies, of which the Company is the beneficiary, with
premiums being paid by the Company. These policies have accumulated
cash values of $53.0, $47.1 and $42.4 million at December 31, 1995,
1994 and 1993, respectively, which do not qualify as plan assets in the
actuarial computation of the funded status. Based upon SFAS No. 87, the
Company has recorded a net liability of $21.5 million as of December
31, 1995.

The following tables set forth the amounts recognized in the Company's
financial statements and the funded status of both plans in accordance
with accounting standard SFAS No. 87, "Employers' Accounting for
Pensions."

Plan Costs for the Year:                    1995       1994      1993
                                              (Thousands of Dollars)
Pension plan:
  Service cost                             $ 5,167   $ 6,049   $ 4,496
  Interest cost                             12,998    12,263    11,688
  Actual return on plan assets             (45,990)      312   (23,322)
  Deferred gain (loss) on plan assets       31,489   (15,584)    9,848
   Net cost                                $ 3,664   $ 3,040   $ 2,710
  Approximate percentage included in
   operating expenses                          65%       67%       66%

Net deferred compensation plan costs 
  charged to other income (including 
  life insurance and SFAS No. 87
  liability accrual)(a)                    $    37   $   508   $ 1,372

(a)  These charges to the Income Statement have been reduced by
     gains from the Company-Owned Life Insurance of $2,320; $2,724, and
     $1,638, for 1995, 1994 and 1993, respectively.

Funded status and significant assumptions as of December 31:
<TABLE>
<CAPTION>
                                                                      Deferred
                                        Pension Plan              Compensation Plan
                                     1995     1994      1993      1995      1994       1993
                                                  (Thousands of Dollars)

<S>                               <C>       <C>       <C>       <C>       <C>       <C>
Actuarial present value of 
 benefit obligations:
 Vested benefit obligation        $145,334  $128,162  $134,292  $ 21,530  $ 19,148  $ 24,024
 Accumulated benefit 
  obligation                      $150,688  $132,766  $139,270  $ 21,530  $ 19,148  $ 24,027
 Projected benefit obligation     $193,133  $167,103  $179,895  $ 22,111  $ 19,681  $ 30,114
Plan assets at fair value          204,760   165,839   169,920      -         -         -
Plan assets in excess of (or 
 less than) projected benefit 
 obligation                         11,627    (1,264)   (9,975)  (22,111)  (19,681)  (30,114)
Unrecognized net (gain) loss 
 from past experience different 
 from that assumed                  (8,341)    6,040    17,295     4,389     2,173     7,295
Unrecognized prior service cost      5,941     6,365     1,460    (3,097)   (3,516)    2,546
Unrecognized net (asset) 
 obligation existing at date of 
 initial adoption (19.5 year 
 straight-line amortization)        (2,493)   (2,756)   (3,019)    5,827     6,440     7,053
Minimum liability adjustment          -         -         -       (6,538)   (4,564)  (10,807)
Net asset (liability) included 
 in the balance sheet             $  6,734  $  8,385  $  5,761  $(21,530) $(19,148) $(24,027)

Discount rate to compute 
 projected benefit obligation        7.25%      8.0%      7.0%      7.25%      8.0%      7.0%
Rate for future compensation 
 increases                            4.5        4.5       4.5       4.5        4.5       4.5
Expected long-term rate of 
 return on plan assets                9.0        9.0       9.0        -          -         -
</TABLE>
Supplemental Employee Retirement Plan (SERP) - The Company has a
nonqualified SERP that provides benefits in excess of Internal
Revenue Service limits (Section 401 (a) (17) of the Internal
Revenue Code) for highly paid individuals. The projected benefit
obligation of this plan was $1,581,000, $857,000 and $525,000 at
December 31, 1995, 1994 and 1993, respectively, with accrued
pension costs of $682,000, $396,000 and $226,000. The Company's
net periodic pension cost of this plan was $184,000, $125,000 and
$36,000 for the same periods.

Savings Plan - The Company has an Employee Savings Plan whereby,
for each $1 of employee contribution up to 6 percent of their
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 to any or all of seven investment options. The
Company's contribution amounted to $2,426,840 in 1995, $2,410,200
in 1994 and $2,283,200 in 1993.

Postretirement Benefits - The Company maintains a defined benefit
postretirement plan (consisting of health care and life
insurance) that covers all employees who were enrolled in the
active group plan at the time of retirement, their spouses and
qualifying dependents. The plan provides for payment of hospital
services, physician services, prescription drugs, dental services
and various other health services, some of which have annual or
lifetime limits, after subtracting payments by Medicare or other
providers and after a stated deductible and co-payments have been
met. Participants become eligible for the benefits if they retire
from the Company after reaching age 55 with 15 years of service
or after 30 years of service. The plan is contributory with
retiree contributions adjusted annually. For those retirees that
were age 65 or older at December 31, 1992 the plan is
noncontributory. The Company also provides life insurance of one
times salary for pre-65 retirees and $20,000 for post-65 retirees
with the retirees paying a portion of the cost.

The following tables set forth the amounts to be recognized in
the Company's financial statements for year-end 1995, 1994 and
1993 and the funded status of the plan in accordance with
accounting standard SFAS No. 106 as of December 31:
   
                                              1995      1994      1993
Postretirement Benefit Cost:                   (Thousands of Dollars)
 Service Cost                               $   763   $   855   $   750
 Interest Cost                                3,571     3,334     3,610
 Actual return on plan assets                (1,116)   (1,114)     (860)
 Amortization of transition obligation 
 20 year amortization)                        2,040     2,040     2,040
 Net amortization and deferral                 -         -         -
 Regulatory assets                              506    (1,907)   (3,548)
 Voluntary severance program                     64      -         -
  Net cost                                  $ 5,828   $ 3,208   $ 1,992


                                              1995      1994      1993
Funded Status:                                 (Thousands of Dollars)
 Accumulated postretirement benefit 
 obligation (APBO)                         $(48,928) $(45,001) $(48,290)
 Plan assets at fair value                   15,920    12,116    11,840
 APBO in excess of plan assets              (33,008)  (32,885)  (36,450)
 Unrecognized gain/losses                       378       773     4,670
 Unrecognized transition obligation          34,680    36,720    38,760
 Prepaid postretirement benefit cost       $  2,050  $  4,608  $  6,980

Discount rate                                 7.50%     8.25%     7.25%
Medical and dental inflation rate             6.75      7.25      6.75
Long-term plan assets expected return          9.0       9.0      9.0


A one percent change in the medical inflation rate would change
the APBO by 7.2 percent and the postretirement expense for 1995
by 8.6 percent.

The Company has a retiree medical benefits funding program which
consists of life insurance policies on active employees of which
the Company is the beneficiary, and a qualified Voluntary
Employees Beneficiary Association (VEBA) Trust. The net charge to
other income for the life insurance policies was $1,754,300 in
1995, $776,400 in 1994 and $632,500 in 1993. The funding to the
VEBA was $916,200 in 1995, $743,600 in 1994 and $2,692,000 in
1993 and recorded as a prepayment. The VEBA trust represents plan
assets which are invested in variable life insurance policies,
Trust Owned Life Insurance (TOLI), on active employees. Inside
buildup in the TOLI policies is tax deferred and tax free if the
policy proceeds are paid to the Trust as death benefits. The
investment return assumption reflects an expectation that
investment income in the VEBA will be substantially tax free.

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 postemployment 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
postemployment benefits are included in the Company's rates. The
Company has recorded a liability of $3.7 million and a regulatory
asset of $3.4 million which represents the costs associated with
postemployment benefits at December 31, 1995. The Company
received IPUC Order No. 25880 authorizing the amortization of the
regulatory asset over a 10-year period.


10.ELECTRIC PLANT IN SERVICE AND JOINTLY-OWNED PROJECTS:

The following table sets out the major classifications of the
Company's electric plant in service and accumulated provision for
depreciation for the years 1995, 1994, and 1993.

  Electric Plant in Service:         1995      1994      1993
                                      (Thousands of Dollars)
  Production                       $1,350,239   $1,303,572   $1,229,237
  Transmission                        330,812      308,055      298,201
  Distribution                        648,549      625,149      582,604
  General and other                   152,230      147,122      139,681
    Total in service                2,481,830    2,383,898    2,249,723
    Accumulated provision for 
    depreciation                     (830,615)    (775,033)    (728,979)
    In service - Net               $1,651,215   $1,608,865   $1,520,744

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, 1995 are as follows:

                                              Company Ownership
                                     Electric   Accumulated
                                     Plant In   Provision for
Name of Plant/Location               Service    Depreciation     %    MW
                                      (Thousands of Dollars)
  
Jim Bridger Units 1-4   
  Rock Springs, WY                   $379,008   $159,721        33    693
Boardman       
  Boardman, OR                         60,368     26,087        10     53
Valmy Units 1 & 2                  
  Winnemucca, NV                      299,189    105,612        50    261

The Company's wholly-owned subsidiary, IERCO, is a joint venturer
in Bridger Coal Company, which operates the mine supplying coal
for the Jim Bridger steam generation plant. Coal purchased by the
Company from the joint venture amounted to $44,278,000 in 1995,
$46,097,000 in 1994 and $45,424,000 in 1993.

The Company has contracts to purchase the energy from five PURPA
Qualified Facilities which are 50 percent owned by Ida-West.
Power purchased from these facilities amounted to $8,695,800 in
1995, $7,139,000 in 1994 and $5,975,093 in 1993.




INDEPENDENT AUDITORS' REPORT

Board of Directors and Shareowners of Idaho Power Company:

We have audited the accompanying consolidated balance sheets and
statements of capitalization of Idaho Power Company and its
subsidiaries listed in the accompanying index to financial
statements and financial statement schedules at Item 8.  These
financial statements and financial schedules are the
responsibility of the Company's management.  Our responsibility
is to express an opinion on the financial statements and
financial schedules based on our audits.

We conducted our audits in accordance with generally accepted
auditing standards. Those standards require that we plan and
perform the audit to obtain reasonable assurance about whether
the financial statements are free of material misstatement. An
audit includes examining, on a test basis, evidence supporting
the amounts and disclosures in the consolidated financial
statements. An audit also includes assessing the accounting
principles used and significant estimates made by management, as
well as evaluating the overall financial statement presentation.
We believe that our audits provide a reasonable basis for our
opinion.

In our opinion, such consolidated financial statements present
fairly, in all material respects, the consolidated financial
position of Idaho Power Company and subsidiaries at December 31,
1995, 1994, and 1993, 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,
present fairly in all material respects the information set forth
therein.

Deloitte & Touche LLP
Portland, Oregon

January 31, 1996

IDAHO POWER COMPANY
SUPPLEMENTAL FINANCIAL INFORMATION, UNAUDITED


QUARTERLY FINANCIAL DATA:

The  following  unaudited  information is presented  for  each  quarter
of  1995,  1994  and  1993  (in thousands of dollars,  except  for  per
share  amounts).  In  the  opinion  of  the  Company,  all  adjustments
necessary  for  a  fair  statement of such  amounts  for  such  periods
have   been  included.  The  results  of  operation  for  the   interim
periods   are  not  necessarily  indicative  of  the  results   to   be
expected  for  the  full  year. Accordingly, earnings  information  for
any  three  month  period  should not be  considered  as  a  basis  for
estimating  operating  results  for a full  fiscal  year.  Amounts  are
based  upon  quarterly  statements and the  sum  of  the  quarters  may
not equal the annual amount reported.

                                             Quarter Ended
                                March 31  June 30   Sept 30   Dec 31

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    23,772    24,833
 Dividends on preferred stock      2,026     2,006     1,976     1,982
 Earnings on common stock         18,701    15,582    21,796    22,851
 Earnings per share of common  
  stock                             0.50      0.41      0.58      0.61

1994
 Revenues                        128,810   128,541   151,031   135,277
 Income from operations           37,408    33,984    33,609    44,663
 Income taxes                      9,406     6,554     8,150    10,133
 Net income                       18,260    17,030    16,289    23,351
 Dividends on preferred stock      1,789     1,819     1,862     1,928
 Earnings on common stock         16,471    15,211    14,427    21,423
 Earnings per share of common
  stock                             0.44      0.41      0.38      0.57

1993
 Revenues                        140,809   129,471   134,577   135,545
 Income from operations           41,479    38,980    34,286    47,201
 Income taxes                     10,610     9,270     9,108     7,486
 Net income                       21,347    18,524    16,427    28,166
 Dividends on preferred stock      1,345     1,318     1,565     1,781
 Earnings on common stock         20,002    17,206    14,862    26,385
 Earnings per share of common
  stock                             0.55      0.47      0.40      0.71


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, 1995.

(c)  Exhibits.

     * Previously Filed and Incorporated Herein by Reference

              File         As           
Exhibit       Number       Exhibit
                                        
*3(a)         33-00440     4(a)(xiii)   Restated Articles of Incorporation
                                        of the Company as filed with the
                                        Secretary of State of Idaho on
                                        June 30, 1989.
                                        
*3(a)(i)      33-65720     4(a)(i)      Statement of Resolution
                                        Establishing Terms of 8.375%
                                        Serial Preferred Stock, Without
                                        Par Value (cumulative stated value
                                        of $100 per share), as filed with
                                        the Secretary of State of Idaho on
                                        September 23, 1991.

*3(a)(ii)     33-65720     4(a)(ii)     Statement of Resolution
                                        Establishing Terms of Flexible
                                        Auction Series A, Serial Preferred
                                        Stock, Without Par Value
                                        (cumulative stated value of
                                        $100,000 per share), as filed with
                                        the Secretary of State of Idaho on
                                        November 5, 1991.
*3(a)(iii)    33-65720     4(a)(iii)    Statement of Resolution
                                        Establishing Terms of 7.07% Serial
                                        Preferred Stock, Without Par Value
                                        (cumulative stated value of $100
                                        per share), as filed with the
                                        Secretary of State of Idaho on
                                        June 30, 1993.
                                        
*3(b)         33-41166     4(b)         Waiver resolution to Restated
                                        Articles of Incorporation adopted
                                        by Shareholders on May 1, 1991.
                                        
*3(c)         33-00440     4(a)(xiv)    By-laws of the Company amended on
                                        June 30, 1989, and presently in
                                        effect.
                                        
*4(a)(i)      2-3413       B-2          Mortgage and Deed of Trust, dated
                                        as of October 1, 1937, between the
                                        Company and Bankers Trust Company
                                        and R. G. Page, as Trustees.
                                        
*4(a)(ii)                               Supplemental Indentures to
                                        Mortgage and Deed of Trust:
                   
                                        Number           Dated
                                                         
              1-MD         B-2-a        First            July 1, 1939
              2-5395       7-a-3        Second           November 15, 1943
              2-7237       7-a-4        Third            February 1, 1947
              2-7502       7-a-5        Fourth           May 1, 1948
              2-8398       7-a-6        Fifth            November 1, 1949
              2-8973       7-a-7        Sixth            October 1, 1951
              2-12941      2-C-8        Seventh          January 1, 1957
              2-13688      4-J          Eighth           July 15, 1957
              2-13689      4-K          Ninth            November 15, 1957
              2-14245      4-L          Tenth            April 1, 1958
              2-14366      2-L          Eleventh         October 15, 1958
              2-14935      4-N          Twelfth          May 15, 1959
              2-18976      4-O          Thirteenth       November 15, 1960
              2-18977      4-Q          Fourteenth       November 1, 1961
              2-22988      4-B-16       Fifteenth        September 15, 1964
              2-24578      4-B-17       Sixteenth        April 1, 1966
              2-25479      4-B-18       Seventeenth      October 1, 1966
              2-45260      2(c)         Eighteenth       September 1, 1972
              2-49854      2(c)         Nineteenth       January 15, 1974
              2-51722      2(c)(i)      Twentieth        August 1, 1974
              2-51722      2(c)(ii)     Twenty-first     October 15, 1974
              2-57374      2(c)         Twenty-second    November 15, 1976
              2-62035      2(c)         Twenty-third     August 15, 1978
              33-34222     4(d)(iii)    Twenty-fourth    September 1, 1979
              33-34222     4(d)(iv)     Twenty-fifth     November 1, 1981
              33-34222     4(d)(v)      Twenty-sixth     May 1, 1982
              33-34222     4(d)(vi)     Twenty-seventh   May 1, 1986
              33-00440     4(c)(iv)     Twenty-eighth    June 30, 1989
              33-34222     4(d)(vii)    Twenty-ninth     January 1, 1990
              33-65720     4(d)(iii)    Thirtieth        January 1, 1991
              33-65720     4(d)(iv)     Thirty-first     August 15, 1991
              33-65720     4(d)(v)      Thirty-second    March 15, 1992
              33-65720     4(d)(vi)     Thirty-third     April 1, 1993
              1-3198       4            Thirty-fourth    December 1, 1993
             Form 8-K
             Dated
             12/17/93

*4(b)                                   Instruments relating to American
                                        Falls bond guarantee. (see
                                        Exhibits 10(f) and 10(f)(i)).
                                        
*4(c)         33-65720     4(f)         Agreement to furnish certain debt
                                        instruments.
                                        
*4(d)         33-00440     2(a)(iii)    Agreement and Plan of Merger dated
                                        March 10, 1989, between Idaho
                                        Power Company, a Maine
                                        Corporation, and Idaho Power
                                        Migrating Corporation.
                                        
*4(e)         33-65720     4(e)         Rights Agreement dated January 11,
                                        1990, between the Company and
                                        First Chicago Trust Company of New
                                        York, as Rights Agent (The Bank of
                                        New York, successor Rights Agent).
                                         
*10(a)        2-51762      5(a)         Agreement, dated April 20, 1973,
                                        between the Company and FMC
                                        Corporation.
                                        
*10(a)(i)     2-57374      5(b)         Letter Agreement, dated
                                        October 22, 1975, relating to
                                        agreement filed as Exhibit 10(a).
                                         
*10(a)(ii)    2-62034      5(b)(i)      Letter Agreement, dated
                                        December 22, 1976, relating to
                                        agreement filed as Exhibit 10(a).
                                        
*10(a)(iii)   33-65720     10(a)        Letter Agreement, dated
                                        December 11, 1981, relating to
                                        agreement filed as Exhibit 10(a).
                                        
*10(b)        2-49584      5(b)         Agreements, dated September 22,
                                        1969, between the Company and
                                        Pacific Power & Light Company
                                        relating to the operation,
                                        construction and ownership of the
                                        Jim Bridger Project.
                                        
*10(b)(i)     2-51762      5(c)         Amendment, dated February 1, 1974,
                                        relating to operation agreement
                                        filed as Exhibit 10(b).
                                        
*10(c)        2-49584      5(c)         Agreement, dated as of October 11,
                                        1973, between the Company and
                                        Pacific Power & Light Company.
                                        
*10(d)        2-49584      5(d)         Agreement, dated as of October 24,
                                        1973, between the Company and Utah
                                        Power & Light Company.
                                        
*10(d)(i)     2-62034      5(f)(i)      Amendment, dated January 25, 1978,
                                        relating to agreement filed as
                                        Exhibit 10(d).
                                        
*10(e)        33-65720     10(b)        Coal Purchase Contract, dated as
                                        of June 19, 1986, among the
                                        Company, Sierra Pacific Power
                                        Company and Black Butte Coal
                                        Company.
                                        
*10(f)        2-57374      5(k)         Contract, dated March 31, 1976,
                                        between the United States of
                                        America and American Falls
                                        Reservoir District, and related
                                        Exhibits.
                                        
*10(f)(i)     33-65720     10(c)        Guaranty  Agreement, dated
                                        March 1, 1990, between the Company
                                        and West One Bank, as Trustee,
                                        relating to $21,425,000 American
                                        Falls Replacement Dam Bonds of the
                                        American Falls Reservoir District,
                                        Idaho.
                                        
*10(g)        2-57374      5(m)         Agreement, effective April 15,
                                        1975, between the Company and The
                                        Washington Water Power Company.
                                        
*10(h)        2-62034      5(p)         Bridger Coal Company Agreement,
                                        dated February 1, 1974, between
                                        Pacific Minerals, Inc., and Idaho
                                        Energy Resources Co.
                                        
*10(i)        2-62034      5(q)         Coal Sales Agreement, dated
                                        February 1, 1974, between Bridger
                                        Coal Company and Pacific Power &
                                        Light Company and the Company.
                                        
*10(i)(i)     33-65720     10(d)        Second Restated and Amended Coal
                                        Sales Agreement, dated March 7,
                                        1988, among Bridger Coal Company
                                        and PacifiCorp (dba Pacific
                                        Power & Light Company) and the
                                        Company.
                                        
*10(j)        2-62034      5(r)         Guaranty Agreement, dated as of
                                        August 30, 1974, with Pacific
                                        Power & Light Company.
                                         
*10(k)        2-56513      5(i)         Letter Agreement, dated January
                                        23, 1976, between the Company and
                                        Portland General Electric Company.
                                        
*10(k)(i)     2-62034      5(s)         Agreement for Construction,
                                        Ownership and Operation of the
                                        Number One Boardman Station on
                                        Carty Reservoir, dated as of
                                        October 15, 1976, between Portland
                                        General Electric Company and the
                                        Company.
                                         
*10(k)(ii)    2-62034      5(t)         Amendment, dated September 30,
                                        1977, relating to agreement filed
                                        as Exhibit 10(k).
                                        
*10(k)(iii)   2-62034      5(u)         Amendment, dated October 31, 1977,
                                        relating to agreement filed as
                                        Exhibit 10(k).
                                         
*10(k)(iv)    2-62034      5(v)         Amendment, dated January 23, 1978,
                                        relating to agreement filed as
                                        Exhibit 10(k).
                                        
*10(k)(v)     2-62034      5(w)         Amendment, dated February 15,
                                        1978, relating to agreement filed
                                        as Exhibit 10(k).
                                        
*10(k)(vi)    2-68574      5(x)         Amendment, dated September 1,
                                        1979, relating to agreement filed
                                        as Exhibit 10(k).
                                        
*10(l)        2-68574      5(z)         Participation Agreement, dated
                                        September 1, 1979, relating to the
                                        sale and leaseback of coal
                                        handling facilities at the Number
                                        One Boardman Station on Carty
                                        Reservoir.
                                        
*10(m)        2-64910      5(y)         Agreements for the Operation,
                                        Construction and Ownership of the
                                        North Valmy Power Plant Project,
                                        dated December 12, 1978, between
                                        Sierra Pacific Power Company and
                                        the Company.
                                        
*10(n)(i)1    1-3198       10(n)(i)     The Revised Security Plans for
              Form 10-K                 Senior Management Employees and
              for 1994                  for Directors-a non-qualified,
                                        deferred compensation plan
                                        effective November 30, 1994.
_________________
1
Compensatory Plan

*10(n)(ii)1   1-3198       10(n)(ii)    The Executive Annual Incentive
              Form 10-K                 Plan for senior management
              for 1994                  employees 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(o)        33-65720     10(f)        Residential Purchase and Sale
                                        Agreement, dated August 22, 1981,
                                        among the United Stated of America
                                        Department of Energy acting by and
                                        through the Bonneville Power
                                        Administration, and the Company.
                                        
*10(p)        33-65720     10(g)        Power Sales Contact, dated
                                        August 25, 1981, including
                                        amendments, among the United
                                        States of America Department of
                                        Energy acting by and through the
                                        Bonneville Power Administration,
                                        and the Company.
                                        
*10(q)        33-65720     10(h)        Framework Agreement, dated October
                                        1, 1984, between the State of
                                        Idaho and the Company relating to
                                        the Company's Swan Falls and Snake
                                        River water rights.
                                        
*10(q)(i)     33-65720     10(h)(i)     Agreement, dated October 25, 1984,
                                        between the State of Idaho and the
                                        Company relating to the agreement
                                        filed as Exhibit 10(q).
                                         
*10(q)(ii)    33-65720     10(h)(ii)    Contract to Implement, dated
                                        October 25, 1984, between the
                                        State of Idaho and the Company
                                        relating to the agreement filed as
                                        Exhibit 10(q).
                                        
*10(r)        33-65720     10(i)        Agreement for Supply of Power and
                                        Energy, dated February 10, 1988,
                                        between the Utah Associated
                                        Municipal Power Systems and the
                                        Company.
                                        
*10(s)        33-65720     10(j)        Agreement Respecting Transmission
                                        Facilities and Services, dated
                                        March 21, 1988 among PC/UP&L
                                        Merging Corp. and the Company
                                        including a Settlement Agreement
                                        between PacifiCorp and the
                                        Company.
                                        
*10(s)(i)     33-65720     10(j)(i)     Restated Transmission Services
                                        Agreement, dated February 6, 1992,
                                        between Idaho Power Company and
                                        PacifiCorp.
*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

*10(v)        33-65720     10(m)        Agreement Regarding the Ownership,
                                        Construction, Operation and
                                        Maintenance of the Milner
                                        Hydroelectric Project (FERC No.
                                        2899), dated January 22, 1990,
                                        between the Company and the Twin
                                        Falls Canal Company and the
                                        Northside Canal Company Limited.
                                        
*10(v)(i)     33-65720     10(m)(i)     Guaranty Agreement, dated February
                                        10, 1992, between the Company and
                                        New York Life Insurance Company,
                                        as Note Purchaser, relating to
                                        $11,700,000 Guaranteed Notes due
                                        2017 of Milner Dam Inc.
                                        
*10(w)        33-65720     10(n)        Agreement for the Purchase and
                                        Sale of Power and Energy, dated
                                        October 16, 1990, between the
                                        Company and The Montana Power
                                        Company.
                                        
*10(x)        1-3198       10(x)        Agreement for design of substation
              Form 10-Q                 dated October 4, 1995, between the
              for 9/30/95               Company and Micron Technology,
                                        Inc.
                                        
12                                      Statement Re:  Computation of
                                        Ratio of Earnings to Fixed
                                        Charges.
                                        
12(a)                                   Statement Re:  Computation of
                                        Supplemental Ratio of Earnings to
                                        Fixed Charges.
                                        
12(b)                                   Statement Re:  Computation of
                                        Ratio of Earnings to Combined
                                        Fixed Charges and Preferred
                                        Dividend Requirements.
                                        
12(c)                                   Statement Re:  Computation of
                                        Supplemental Ratio of Earnings to
                                        Combined Fixed Charges and
                                        Preferred Dividend Requirements.
                                        
*21           1-3198       21           Subsidiaries of Registrant
              Form 10-K
              for 1994
                                        
23                                      Independent Auditors' Consent.
                                     
27                                      Financial Data Schedule

IDAHO POWER COMPANY
SCHEDULE II - CONSOLIDATED VALUATION AND QUALIFYING ACCOUNTS

Years Ended December 31, 1995, 1994 and 1993

Column A                 Column B        Column C        Column D    Column E
                                         Additions
                                              Charged                Balance
                         Balance At  Charged  (Credited)             At
                         Beginning   to       to Other   Deductions  End Of
Classification           Of Period   Income   Accounts      (1)      Period
                                        (Thousands of Dollars)
                                                                       
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                                                
     reserve             $1,500      $1,364   $   -      $1,364      $1,500
   Miscellaneous                                                       
     operating reserves  $  940      $  460   $ (176)    $   81      $1,143

1994:                                                                  
 Reserves Deducted From                                                
  Applicable Assets:
   Reserve for                                                         
     uncollectible
     accounts            $1,377      $1,360   $1,018(2)  $2,378      $1,377
  Other Reserves:                                                      
   Injuries and damages                                                
     reserve             $1,500      $1,804   $   -      $1,804      $1,500
   Miscellaneous                                                       
     operating reserves  $  748      $  429   $ (156)    $   81      $  940
                                                                       
1993:                                                                  
 Reserves Deducted From                                                
  Applicable Assets:
   Reserve for                                                         
     uncollectible
     accounts            $1,421      $1,174   $1,001(2)  $2,219      $1,377
  Other Reserves:                                                      
   Injuries and damages                                                
     reserve             $1,500      $2,820   $   -      $2,820      $1,500
   Miscellaneous                                                       
     operating reserves  $   -       $  870   $  332     $  454      $  748

NOTES:  (1)  Represents deductions from the reserves for purposes for 
             which the reserves were created.
        (2)  Represents collections of accounts previously written off.

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities
Exchange Act of 1934, the Registrant has duly caused this report to be
signed on its behalf by the undersigned, thereunto duly authorized.

                              IDAHO POWER COMPANY
                              (Registrant)


March 14, 1996                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 14, 1996
  Joseph W. Marshall        Chief Executive Officer and Director


By: /s/Larry R. Gunnoe      President and Chief Operating            "
  Larry R. Gunnoe           Officer and Director


By: /s/J. LaMont Keen       Vice President and Chief Financial       "
  J. LaMont Keen            Officer (Principal Financial Officer)


By: /s/Harold J. Hochhalter Controller and Chief Accounting Officer  "
  Harold J. Hochhalter      (Principal Accounting Officer)


By: /s/Robert D. Bolinder   By: /s/Evelyn Loveless                   "
  Robert D. Bolinder        Evelyn Loveless
  Director                  Director


By: /s/Roger L. Breezley    By: /s/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


12             Statement Re:  Computation of Ratio of Earnings       70
               to Fixed Charges

12(a)          Statement Re:  Computation of Supplemental            71
               Ratio of Earnings to Fixed Charges.

12(b)          Statement Re:  Computation of Ratio of Earnings       72
               to Combined Fixed Charges and Preferred
               Dividend Requirements.

12(c)          Statement Re:  Computation of Supplemental            73
               Ratio of Earnings to Combined Fixed Charges           
               and Preferred Dividend Requirements. 
               
23             Independent Auditor's Consent.                        74

27             Financial Data Schedule                               75