UNITED STATES SECURITIES AND EXCHANGE COMMISSION
                     Washington, D.C. 20549
                          FORM 10-K405

(Mark One)

X     ANNUAL REPORT PURSUANT TO SECTION 13 OR 15 (d) OF
    THE SECURITIES
      EXCHANGE ACT OF 1934 [FEE REQUIRED]
For the fiscal year ended December 31, 1996
                               OR

      TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d)
    OF THE SECURITIES
      EXCHANGE ACT OF 1934 [NO FEE REQUIRED]

For the transition period from .................to..................
Commission file number 1-3198

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

          IDAHO                               82-0130980
     (State or other                       (I.R.S. Employer
     jurisdiction of                      Identification No.)
     incorporation or
      organization)
                                                   
  1221 W. Idaho Street,                       83702-5627
       Boise, Idaho
  (Address of principal                       (Zip Code)
    executive offices)

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

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

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

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

                         Preferred Stock
                        (Title of Class)

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

Yes  X    No


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

Aggregate market value of voting stock
held by nonaffiliates (January 31, 1997)     $1,195,163,000

Number of shares of common stock outstanding at February 28, 1997
37,612,351

Documents Incorporated by Reference:

Part III, Item 10   Portions of the definitive proxy statement of
                    the Registrant to be filed pursuant to
     Item 11   Regulation 14A for the 1996 Annual Meeting of
                    Shareowners to be held on May 7, 1997.
     Item 12
     Item 13


                             TABLE OF CONTENTS

PART I
                                                                    Page
  Item 1.   Business                                                  2
             The Company                                              2
             Power Supply                                             5
             Fuel                                                    10
             Water Rights                                            10
             Regulation                                              11
             Environmental Regulation                                12
             Rates                                                   13
             Construction Program                                    15
             Financing Program                                       16
  Item 2.   Properties                                               17
  Item 3.   Legal Proceedings                                        19
  Item 4.   Submission of Matters to a Vote of Security Holders      22
  
  Executive Officers of the Registrant                               22

Part II

  Item 5.   Market for the Registrant's Common Stock and 
             Related Stockholder Matters                             23
  Item 6.   Selected Financial Data                                  24
  Item 7.   Management's Discussion and Analysis of Financial
             Condition and Results of Operations                     26
  Item 8.   Financial Statements of Supplementary Data               40
  Item 9.   Changes in and Disagreements with Accountants and 
             Financial Disclosure                                    63
Part III

  Item 10.  Directors and Executive Officers of the Registrant*      63
  Item 11.  Executive Compensation*                                  63
  Item 12.  Security Ownership of Certain Beneficial Owners and
             Management*                                             63
  Item 13.  Certain Relationships and Related Transactions*          63

Part IV
  
  Item 14.  Exhibits, Fianancial Statement Schedule and Reports
             on Form 8-K                                            63

  Signatures                                                        70

*Incorporated by Reference.  

The exhibit index is located on Page 71.  This document contains 
145 pages.

PART I

ITEM 1. BUSINESS

THE COMPANY
This Form 10-K contains "forward-looking statements" intended to
qualify for safe harbor from liability established by the Private
Securities Litigation Reform Act of 1995.  Forward-looking
statements should be read with the cautionary statements and
important factors included in this Form 10-K at Part II, Item 7.
Management's Discussion and Analysis of financial condition and
Results of Operations - Forward-Looking Information.  Forward-
looking statements are all statements other than statements of
historical fact, including without limitation those that are
identified by the use of the words "anticipates," "estimates,"
"expects," "intends," "plans," "predicts," and similar
expressions.
     
     General -
Idaho Power Company (Company) is an electric public utility
incorporated under the laws of the state of Idaho in 1989 as
successor to a Maine corporation organized in 1915. The Company
is engaged in the generation, purchase, transmission,
distribution and sale of electric energy in an approximate 20,000-
square-mile area in southern Idaho, eastern Oregon and northern
Nevada, with an estimated population of 754,000 people. The
Company holds franchises in approximately 70 cities in Idaho and
10 cities in Oregon, and holds certificates from the respective
public utility regulatory authorities to serve all or a portion
of 28 counties in Idaho, 3 counties in Oregon and 1 county in
Nevada. The Company's results of operations, like those of
certain other utilities in the Northwest, can be significantly
affected by changing weather, precipitation and streamflow
conditions. With the implementation of a power cost adjustment
mechanism (PCA) in the Idaho jurisdiction, which includes a major
portion of the operating expenses with the largest variation
potential (net power supply costs), the Company's operating
results are more dependent upon general regulatory, economic,
temperature and competitive conditions and less on precipitation
and streamflow conditions.  Variations in energy usage by
ultimate customers occur from year to year, from season to season
and from month to month within a season, primarily as a result of
weather conditions.  As of December 31, 1996, the Company
supplied electric energy to 352,487 general business customers
and employed 1,645 people in its operations (1,565 full-time).

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

For the twelve months ended December 31, 1996, total system
electric revenues from residential customers accounted for 35
percent of the Company's total operating revenues. Commercial
customers with less than 1,000 kW demand including street
lighting customers accounted for 19 percent, industrial customers
with 1,000 kW demand and over accounted for 19 percent and
irrigation customers accounted for 11 percent. Public utilities
and interchange arrangements accounted for 12 percent and other
operating revenues accounted for 4 percent.
The Company's principal commercial and industrial revenues are
from sales of electric power to customers involved in elemental
phosphorus production; food processing, preparation and freezing
plants; phosphate fertilizer production; electronics and general
manufacturing facilities; lumber; beet sugar refining; and
electric loads associated with the year-round recreational
business, such as lodges, condominiums, ski lifts and other
related facilities, including those at the Sun Valley resort
area.

     Subsidiaries -
The Company has six wholly-owned subsidiary companies: Ida-West
Energy Company (Ida-West), Idaho Energy Resources Co. (IERCo),
Idaho Utility Products Company (IUPCo), IDACORP, Inc., Idaho
Power Resources Corporation (IPRC) and Stellar Dynamics, Inc.
(Stellar).

Ida-West was formed in 1989 to participate through partnership
interests in cogeneration and small power production (CSPP)
projects. Ida-West holds investments in thirteen operating
hydroelectric plants with a total generating capacity of
approximately 72 megawatts (MW).

In January 1996, Ida-West made an investment by acquiring all of
the outstanding bonds that were issued to finance three
hydroelectric plants known collectively as the Friant Power
Project.  This project is located at the U.S. Bureau of
Reclamation's Friant Dam on the headwaters of the San Joaquin
River in Madera and Fresno Counties, California.  It has an
aggregate generating capacity of 27.4 MW.  The project is owned
and operated by Friant Power Authority, a quasi-governmental
entity consisting of six irrigation districts, a water district,
and a municipal utility district.

In November 1996, Ida-West purchased an interest in five
hydroelectric projects located in Shasta County, California, with
a total generating capacity of 11.2 MW.  Ida-West acquired the
projects through a limited liability company in which it holds a
50 percent interest.

In addition, Ida-West has an interest in the Hermiston Power
Project, a 460 MW, gas-fired cogeneration project to be located
near Hermiston, Oregon.  Ida-West has been responsible for
managing all permitting and development activities relating to
the project since its inception in 1993, and has obtained all
permits necessary for construction and operation of the project.
The partnership is exploring various alternatives for marketing
the project's output.  Project financing for construction costs
would be non-recourse to Idaho Power.

The Company has purchased all of the power from five Idaho
hydroelectric entities of Ida-West, totaling approximately $9.0
million.

Ida-West continues to actively seek to develop new projects.  At
December 31,1996 the Company's total investment in Ida-West was
$21.8 million. (See Part II, Item 7. "Management's Discussion and
Analysis of Financial Condition" and "Results of Operations-
Subsidiaries".)

IERCo has been in operation since 1974. Its primary purpose is to
participate as a joint venturer in the Bridger Coal Company,
which operates the mine supplying coal to the Jim Bridger power
plant near Rock Springs, Wyoming (see "Fuel"). As of December 31,
1996, the Company's total investment in IERCo was $4.4 million.

IDACORP, Inc. was organized in 1986 to pursue a non-regulated
diversification program. At the end of 1996 IDACORP was
participating in five affordable housing programs which provide a
return primarily by reducing federal income taxes through tax
credits and tax depreciation benefits. As of December 31, 1996,
the total investment in IDACORP was $6.2 million.

IPRC, is a wholly-owned subsidiary, incorporated in March 1996 to
provide guidance, resources, and long-term strategic planning to
projects or business proposals that are not subject to regulation
by the FERC and the state regulatory commissions.  IPRC's goals
are to establish, acquire, and expand business operations in
sustainable infrastructure technology and services including
energy, water, waste disposal, telecommunications, and
information systems.  The Company has invested approximately $4.0
million in development and acquisition activities in IPRC.

IPRC has a Memorandum of Understanding signed by Idaho Power and
representatives from the government of Indonesia on March 6,
1996, clearing the way to conduct a detailed feasibility study on
using solar photovoltaic (PV) technology, micro hydroelectric
systems, and other renewable energy systems to provide
electricity to various locations throughout Indonesia's complex
of islands.  IPRC is currently reviewing results of the completed
business plan.  If the project is deemed workable and receives
the required approvals, IPRC would likely begin to develop
services in late 1997.

In October 1996, IPRC acquired a majority interest in Applied
Power Corporation (APC), a Lacey, Washington-based, company that
designs, supplies, and distributes photovoltaic (PV) systems.

Stellar was formed in 1995 to commercialize the Company's
extensive expertise in control technology for electric
substations and power plants. Today, the market focus lies in the
integration of complex control and automation systems for both
the electric utility sector and industrial applications. Stellar
also provides design and engineering for complete electric
substations. The geographic market for Stellar is mainly in the
western U.S. with some emphasis in the remaining U.S., Canada and
abroad.  As of December 31, 1996, total investment in Stellar was
$0.8 million.

IUPCO was formed in 1983 to develop and market products to the
utility industry.  The Company's total investment was $0.4
million in IUPCO at December 31, 1996.
     
     Research and Development and Renewable Energy Sources -
During 1996, the Company spent approximately $1.8 million on
research and development of which $1.5 million was through the
Company's membership in Electric Power Research Institute (EPRI).
EPRI's mission is to discover, develop and deliver advances in
science and technology. Some of the projects benefits to the
Company include: electrification technologies, power quality,
electric transportation systems, EMF assessment/risk management
and air quality issues. The Company also has an internal research
and development effort called the Emerging Technology (ET)
Program. The ET program was established to maintain an active and
coordinated response to new technology of interest to the
Company.

In 1992, the Company joined Southern California Edison, the U.S.
Department of Energy and others in retrofitting an existing 10-
megawatt central receiver solar thermal experimental power plant
now called Solar Two near Barstow, California. The Company will
have contributed $630,500 through 1997 and the EPRI will
contribute an additional $630,500 of matching funds, bringing the
Company's credited contribution to approximately $1.3 million.
Solar Two was first synchronized to Southern California Edison's
system in May 1996.  The main benefit the Company will receive by
participating in this project is valuable experience and
knowledge in solar plant design, construction and operation.

The Company offers Photovoltaics for basic electric service on
small loads at remote sites as an alternative to either line
extensions for grid service or the use of on-site, fossil-fuel
generators.  The customer pays a monthly fee to receive electric
service from a solar PV system designed, installed, owned, and
maintained by Idaho Power. The service, which the Company
launched in January 1993, is a pilot offering with a $5,000,000
program limit and a $50,000 limit for individual systems. To
date, Idaho Power has installed 32 solar photovoltaic (PV)
systems. All of these systems are operating as designed.

In 1996, the Company's newly-formed subsidiary, IPRC, acquired a
majority interest in APC, a company that would partner with
interested electric utilities to provide energy services to
remote locations within their service territories. This company
would work on behalf of the utilities to offer solar PV energy
systems at the lowest possible cost to the consumer. While the
domestic utility market is promising in itself, IPRC is also
pursuing international opportunities for its renewable energy
expertise (see "Subsidiaries").
     
     Energy Efficiency -
The Company continues to promote the efficient use of electrical
energy. The Company supported legislation in Idaho that
established energy-efficient building codes for new home
construction and continues to support the adoption of even more
stringent energy codes by local government jurisdictions. In
1996, the Company expended $4.4 million on its various energy-
efficiency programs.


POWER SUPPLY
The Company is a dual-peaking system, with the larger energy peak
generally occurring in the summer. This complements the winter
peaking utilities which predominate in the Pacific Northwest.
Even though its significant hydroelectric generation can operate
to meet demand peaks, seasonal energy requirements are important
to the Company because its seasonal energy capability is
determined in part by the availability of water. In 1994, below
normal precipitation created drought conditions reducing
reservoir storage. In 1995 and 1996, however, the Company's
service territory experienced above average water years. The
system peak demand for 1996 was 2,661 megawatts set on July 9,
1996. Peak demand for 1995 and 1994 were 2,393 and 2,392
megawatts respectively.

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

                             Total Energy Sources
                               (000's of MWH)
                         1996       %     1995     %     1994     %
Generation - net                                            
station output -
  Hydro                  10,713.5   58   9,277.2   58   6,213.2   40
  Coal-fired              4,783.0   26   4,591.9   29   7,221.8   46
Purchased and 
interchange               3,067.3   16   2,155.9   13   2,287.0   14          
   Total                 18,563.8  100  16,025.0  100  15,722.0  100

Historically, under normal water conditions, the Company's hydro
system supplies approximately 57 percent, thermal generation
accounts for 34 percent and purchased power and other
interchanges contribute the remaining 9 percent of total system
requirements.  Preliminary 1997 reports indicate the mountain
snowpack is well above normal for this time of year and the
carryover reservoir storage throughout the Snake River Basin is
close to average. The Company expects to meet projected energy
loads during the coming year by utilizing its hydro and coal-
fired facilities and strategic geographic location - which
provides opportunities to purchase, sell, exchange and transmit
energy.

Purchased power expenses fluctuated during the three-year period
reflecting necessity purchases from neighboring utilities due to
the 1994 drought. Purchased power expenses were lower in 1995,
reflecting better hydro conditions for the year.  In 1996,
purchased power expenses were higher as the Company took
advantage of low wholesale market prices due to the abundance of
hydro generation in the West, which allowed the Company to
remarket this energy to others.  Increased purchases from CSPP
projects also increased purchased power expenses in 1996.

The Company periodically updates its load and resource
projections and now expects total Company energy requirements
over the next 10 years to grow at an annual rate of 1.8 percent.

The Company's generating facilities are interconnected through
its integrated transmission system and are operated on a
coordinated basis to achieve maximum load-carrying capability and
reliability. The transmission system of the Company is directly
interconnected with the transmission systems of the Bonneville
Power Administration (BPA), The Washington Water Power Company,
PacifiCorp, The Montana Power Company and Sierra Pacific Power
Company (SPPCo). Such interconnections, coupled with transmission
line capacity made available under agreements with certain of the
above utilities, permit the advantageous interchange, purchase
and sale of power among most of the electric systems in the West.
The Company is a member of the Western Systems Coordinating
Council, the Western Systems Power Pool, the Northwest Power
Pool, the Western Regional Transmission Association and the
Northwest Regional Transmission Association.

     Competition -
Competition is increasing in the electric utility industry.  The
National Energy Policy Act of 1992, FERC rule-makings, state
initiatives, customer demands, and pending legislation at the
national and state level, all indicate increasing wholesale and
ultimately retail competition.  With its low energy production
costs, the Company believes it is well-positioned to enter a more
competitive environment and is taking action to preserve its low-
cost competitive advantage.

The legislatures and/or the regulatory commissions in several
states, and at a national level, have considered or are
considering "retail wheeling".  Retail wheeling means the
movement of electric energy produced by another entity over an
electric utility's transmission and distribution system, to a
retail customer in what was the utility's service territory. A
requirement to transmit directly to retail customers would permit
retail customers to purchase electric capacity and energy from
the electric utility in the service area they are located or from
any other electric utility or independent power supplier.  While
proposals have been advanced, the Idaho Legislature has not yet
addressed retail wheeling but the Idaho Public Utilities
Commission (IPUC) has conducted an issues dialogue process and
established workshops for discussing retail wheeling issues among
affected parties in 1996 (see "Regulation").

In response to increased competition in the industry, the
potential ability of retail customers to choose their electric
provider and the apparent deregulation of the electric power
industry, the Company has adjusted its resource acquisition
policy toward a greater emphasis on resource marketability. In
order to avoid burdening the Company and its customers with
unnecessary future power supply costs and higher rates, the
Company has adopted a policy of acquiring all new resources as
close as possible to the actual time of need and selecting the
lowest cost resources meeting all of the Company's requirements.
In practice, this policy will result in the purchase of power
from others through the marketplace whenever purchases are the
lowest cost resources, and new investment in resource ownership
by the Company only when a Company-owned resource would be cost
effective in the market.  With its predominantly hydro base and
low-cost thermal plants, the Company is one of the lowest cost
producers of electric energy among the nation's investor-owned
utilities.  Through its interconnections with BPA and other
utilities, the Company has access to all the major electric
systems in the West.


     Marketing Business Unit -
To accommodate its customers and allow itself to compete in the
rapidly evolving competitive market, the Company formed a
Marketing Business Unit in January 1997.  This new business unit
will be responsible for all purchases and sales of electric
energy, market research and the planning and implementation of
marketing strategies.

There are three core components to the new business unit:
Product development, which is responsible for creating and
commercializing all new energy products and services;  Supply and
logistics, which is responsible for energy supply aggregation,
delivery and risk management;  and Sales, which is responsible
for market aggregation and sales of energy products and service
offerings to its customers.

The new business unit will offer a comprehensive program of
energy supply and management services, and will expand its
current product line to include several new energy service
options.  Existing and planned product offerings include both
firm and interruptible short-term, month-to-month, and long-term
customized energy supply options and multiple pricing options
including fixed, floating, and indexed.  The business unit's
service options will include energy scheduling, energy reserve
products, risk management, load shaping and following service,
summary billing and energy analysis for multiple customer
facilities, and multi-fuel management service.  Fuel management
services will provide a means to partially or completely
outsource the administrative and operational duties associated
with managing all or part of our customers energy supply
requirements.
     
     Southwest Intertie Project (SWIP) -
The Company has been investigating the feasibility of
constructing and operating a new transmission line that could
serve as a major path for regional transfers of power between the
Northwest and desert Southwest.  SWIP is a proposed 500-mile, 500-
kV transmission line that would interconnect the Company's system
with utilities in California and the Southwest. In December 1994,
the US Bureau of Land Management (BLM) issued a favorable record
of decision on the Company's environmental impact statement and
granted the project a right-of-way across public lands in Idaho,
Nevada and Utah. The Company intends to retain up to a 20 percent
ownership in the 1,200 megawatt line.

The Company and interested parties have completed ownership
allocation and negotiations for the execution of the Memorandum
of Agreement (MOA).  When the MOA is executed, the Company will
require each party to pay its share of the approximately $8.5
million expended for environmental permitting, right-of-way
acquisition, and related development activities.  The SWIP owners
will then form an Executive Committee, with voting rights
proportional to each share of the project.  The Executive
Committee will oversee development activities for the SWIP and
related projects.

As of December 31, 1996, the Company's Southwest Intertie Project
(SWIP) is on hold.  At the current time, an order from the Public
Service Commission of Nevada is still pending, that would allow
Nevada Power to participate in the project.

The final development of SWIP may be impacted by regional efforts
to form an independent transmission and operator to eliminate
market control and provide improved transmission access for all
system users (see "Independent Grid Operator").
     
     
     
     Transmission Services -
The Company has long had an informal open-access transmission
policy and is experienced in providing reliable, high quality,
economical transmission service. The Company provides various
firm and non-firm wheeling services for several surrounding
utilities. In July 1996, the Company filed an open-access tariff
with the FERC, in compliance with Order 888.  The terms and
conditions of the tariff were approved for use beginning in 1997.

The Company's system lies between and is interconnected to the
winter-peaking northern and summer-peaking southern regions of
the western interconnected power system. This position is
advantageous both in providing transmission service and reaching
a broad power sales market. The Company is a member of both the
Western Regional Transmission Association and the Northwest
Regional Transmission Association. These associations will help
facilitate transmission access and planning throughout the power
system.
     
     Independent Grid Operator -
Recently a group of seven investor-owned Northwest electric
companies, including Idaho Power, BPA, and five public electric
entities signed a memorandum of understanding that will create an
independent transmission grid operator called "IndeGO".  IndeGO
will ensure non-discriminatory, open-access to electricity
transmission facilities in compliance with recent FERC rulings.
The memorandum of understanding is an agreement to investigate
the feasibility of developing a regional transmission grid which
would be operated by an entity independent of power market
interests.  It is believed that the formation of such an entity
will facilitate the operation of an evolving competitive electric
power market.  Operating as one regional system, the utilities
will be able to increase the efficiency of transmission
operations and provide improved access for all system users.

IndeGo is envisioned as an independent transmission company not
controlled by any individual power market participant.  It is
anticipated that IndeGO will operate as a single control area,
with pricing based on a single zonal tariff applied equally to
all users including the participating companies.

IndeGO will not own transmission facilities initially, but will
be responsible for the operation of main transmission grid
facilities 230 kilovolts (kV) or more that are owned by the
participating utilities.  The area encompassed by the IndeGo has
over 20,000 miles of transmission lines accounting for about 97%
of the northwest grid.

The group plans to file the IndeGo proposal with FERC by July
1997, and anticipates operation would commence as early as 1999.
If the FERC's approval arrives by April 1998, an IndeGo Board and
Site Procurement could be expected by July 1998.
     
     Forecast Energy and Peak Demand -
The following tables show how the Company expects to meet its
forecast energy and peak demand requirements through 2001 from
system generation and contracted resources. Because of its
reliance upon hydroelectric generation, which varies according to
streamflows, the Company's generating system is more energy
constrained than capacity limited. Seasonal exchanges of winter-
for-summer power are included among the contracted resources to
maximize the firm load carrying capability. Exchanges are
currently made with The Montana Power Company under a 10-year
contract signed in 1987 and with Seattle City Light under an
extended contract that expires in 2003.

                                Summer Peak Capability (MW) (a)
                                1997  1998   1999   2000   2001
Generation capability          2,681  2,681  2,681  2,681  2,681
Less net peak load             2,438  2,493  2,541  2,590  2,635
Plus contract power(b)           313    313    313    313    313
Peak capability margin           556    501    453    404    359
Percent capability margin(c)    22.8%  20.1%  17.8%  15.6%  13.6%

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


                                     Annual Energy Capability     
                                        (000's of MWH) (a)
                              1997     1998     1999     2000     2001 
Generation Capability        15,097   15,220   15,279   15,313   15,471 
Contracts: Cogeneration      
 and small power production     832      832      832      832      832
Annual firm load            (15,572) (15,905) (15,965) (16,040) (16,271)
Energy capability margin        357      147      146      105       32 
Percent (b)                     2.3%     0.9%     0.9%     0.7%     0.2% 

(a)  Forecast based upon average of 68 historical water conditions.
(b)  Energy capability margin divided by the generating capability.

During the 1997-2001 period, the Company plans to provide all the
energy required to serve its firm load requirements during
periods of heavy demand, reduced hydrogeneration caused by below
normal streamflow conditions, or unscheduled outages of
generating units by utilizing its hydroelectric and coal-fired
generating units and through purchases of power from neighboring
utilities or marketing entities.
     
     CSPP Purchases -
As a result of the enactment of the PURPA and the adoption of
avoided cost standards by the IPUC, the Company has entered into
contracts for the purchase of energy from private developers.
Because the Company's service territory encompasses substantial
irrigation canal development, forest products production
facilities, mountain streams, and food processing facilities,
considerable amounts of energy are available from these sources.
Such energy comes from hydro power producers who own and operate
small plants and from cogenerators converting waste heat or steam
from industrial processes into electricity. The estimated
annualized cost for the 67 CSPP projects on-line as of December
31, 1996, is $55.9 million. During 1996, the Company purchased
776.4 million kilowatt-hours of power from these private
developers at a blended price of 5.6 cents per kilowatt-hour.

With the potential deregulation of the electric utility industry
and a more competitive power supply marketplace, the Company
believes that resource acquisition policies must avoid burdening
the Company and its customers with unnecessary future power
supply costs.  In 1993, the Company requested, and in 1995
received approval, to lower published CSPP rates for new
projects.  In addition, the IPUC determined that negotiated rates
for future CSPP projects larger than 1 megawatt (MW) should be
tied more closely to values determined in the Company's
integrated resource planning process.  In a subsequent order
issued on September 4, 1996, the IPUC further recognized the
coming changes by limiting the contract term which a new CSPP
project larger than 1 MW could request to a maximum of five years
(see "Rates").
     
     Firm Wholesale Power Sales -
The Company has firm wholesale power sales contracts with several
entities in the West.  These contracts are for various amounts of
energy, ranging from 6 to 75 average megawatts, and are of
various lengths presently scheduled to expire between 1997 and
2009.  The Company is actively marketing this power to other
entities as it becomes available.


FUEL
The Company, through Idaho Energy Resources Co., owns a one-third
interest in the Bridger Coal Company which owns the Jim Bridger
coal mine that supplies coal to the Jim Bridger generating plant
in Wyoming. The mine, located near the Jim Bridger plant,
operates under a long-term sales agreement and provides for
delivery of coal over a 51-year period that began in 1974. The
original contract of 41 years was extended for 10 years on
January 1, 1996. (See Item 2 "Properties".) The Jim Bridger Coal
Mine has sufficient reserves to provide coal deliveries pursuant
to the sales agreement.  The Company also has a coal supply
contract providing for annual deliveries of coal through 2005
from the Black Butte Coal Company's Leucite Hills mine adjacent
to the Jim Bridger project. This contract supplements the Bridger
Coal Company deliveries and provides another coal supply to
operate the Jim Bridger plant. The Jim Bridger plant's rail load-
in facility and unit coal train allows the plant to take
advantage of potentially lower-cost coal from outside mines for
tonnage requirements above established contract minimums.

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

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

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


WATER RIGHTS
The Company, except as otherwise stated herein, has valid water
rights acquired under applicable provisions of state law for all
waters used in its hydroelectric generating facilities.  In
addition, the Company holds water rights for domestic,
irrigation, commercial and other necessary purposes related to
other land and facility holdings within the state.  The exercise
and use of all of these water rights are subject to prior rights
and, with respect to certain hydroelectric facilities, the
Company's water rights for power generation are subordinated to
future upstream diversions of water for irrigation and other
recognized consumptive uses.
Over time, increased irrigation development and other consumptive
diversions have resulted in some reduction in the stream flows
available to fulfill the Company's water rights at certain
hydroelectric generating facilities.  In reaction to these
reductions, the Company initiated and continues to pursue a
course of action to determine and protect its water rights.  As
part of this process, the Company and the state of Idaho signed
the Swan Falls agreement on October 25, 1984 which provided a
level of protection for the Company's hydropower water rights at
specified plants by setting minimum stream flows and establishing
an administrative process governing the future development of
water rights that may affect the Company's hydroelectric
generation.  In 1987, Congress passed and the President signed
into law House Bill 519.  This legislation permitted
implementation of the Swan Falls agreement and further provided
that during the remaining term of certain of the Company's
project licenses that the relationship established by the
agreement would not be considered by the FERC as being
inconsistent with the terms of the Company's project licenses or
imprudent for the purposes of determining rates under Section 205
of the Federal Power Act.  The FERC entered an order implementing
the legislation on March 25, 1988.

In addition to providing for the protection of the Company's
hydropower water rights, the Swan Falls agreement contemplated
the initiation of a general adjudication of all water uses within
the Snake River basin.  In 1987, the director of the Idaho
Department of Water Resources filed a petition in state district
court asking that the court adjudicate all claims to water
rights, whether based on state or federal law, within the Snake
River basin.  A commencement order initiating the Snake River
Basin Adjudication was signed by the court on November 19, 1987.
This legal proceeding was authorized by state statute based upon
a determination by the Idaho Legislature that the effective
management of the waters of the Snake River basin required a
comprehensive determination of the nature, extent and priority of
all water uses within the basin.  The adjudication is expected to
continue past the turn of the century.  The Company has filed
claims to its water rights within the basin and is actively
participating in the adjudication to ensure that its water rights
and the operation of its hydroelectric facilities are not
adversely impacted.  The Company does not anticipate any
modification of its water rights as a result of the adjudication
process.


REGULATION
The Company is under the regulatory jurisdiction (as to rates,
service, accounting and other general matters of utility
operation) of the FERC, the IPUC, the Oregon Public Utilities
Commission (OPUC) and the Public Service Commission of Nevada.
The Company is also under the regulatory jurisdiction of the
IPUC, OPUC and the Public Service Commission of Wyoming as to the
issuance of securities. The Company is subject to the provisions
of the Federal Power Act as a "licensee" and "public utility" as
therein defined. The Company's retail rates are established under
the jurisdiction of the state regulatory agencies and its
wholesale and transmission rates are regulated by the FERC (See
"Rates"). Pursuant to the requirements of Section 210 of the
PURPA, the state regulatory agencies have each issued orders and
rules regulating the Company's purchase of power from CSPP
facilities.

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

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


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

Based upon the requirements of present environmental laws and
regulations, the Company estimates its capital expenditures
(excluding allowance for funds used during construction) for
environmental matters for 1997 and during the period 1998-2001
will total approximately $0.7 million and $29.1 million,
respectively. Mitigation of environmental concerns due to
relicensing of hydro facilities will be a major portion of these
expenditures. The Company also anticipates spending approximately
$21 million a year in operating expenses for environmental
facilities during the 1997-2001 period. However, to the extent
regulations under federal and state environmental protection
laws, as well as the laws themselves, are changed, costs for
compliance with such laws and regulations in connection with the
Company's existing facilities and facilities under construction
are subject to change in an amount not determinable.
     
     Air -
The Company has analyzed the Clean Air Act's legislation and its
effects upon the Company and its rate payers. The Company's coal-
fired plants in Nevada and Oregon already meet the federal
emission rate standards for sulfur dioxide (SO2) and the
Company's coal-fired plant in Wyoming meets that state's even
more stringent SO2 regulations. The Company anticipates no
material adverse effect upon its operations. The Company has
entered into a joint arrangement with PacifiCorp and Black Hills
Corporation under which certain of these companies generating
units have been accepted by the Environmental Protection Agency
as "Substitution" units for the Baldwin #2 unit owned by Illinois
Power Company. In exchange for Illinois Power naming units at the
Jim Bridger Station as "Substitution" units for Baldwin #2, the
Company sold Illinois Power a portion of the Phase I SO2
Allowances it received by having its share of the Jim Bridger
units accepted as Phase I "Substitution" units.
     
     Water -
The Company has received National Pollutant Discharge Elimination
System Permits, as required under the Federal Water Pollution
Control Act Amendments of 1972, for the discharge of effluents
from its hydroelectric generating plants.

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

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

The Company has installed aeration equipment, water quality
monitors and data processing equipment as part of the Cascade
hydroelectric project to provide accurate water quality data and
increase dissolved oxygen levels as necessary to maintain water
quality standards on the Payette River.  The Company has also
installed and operates water quality monitors at the Milner and
Twin Falls hydroelectric projects, in order to meet compliance
standards for water quality.

The Company owns and finances the operation of anadromous fish
hatcheries and related facilities to mitigate the effects of its
hydroelectric dams on fish populations. In connection with its
fish facilities, the Company sponsors ongoing programs for the
control of fish disease and improvement of fish production. The
Company's anadromous fish facilities at Hells Canyon, Oxbow,
Rapid River, Pahsimeroi and Niagara Springs continue to be
operated under agreements with the Idaho Department of Fish and
Game. In 1996, the investment in these facilities was $12.2
million and the operation of these facilities pursuant to the
FERC License 1971 cost approximately $2.2 million annually.
     
     Endangered Species -
The Company continues to review and analyze the various effects
upon its operations of the listing as threatened or endangered of
several species of salmon and Snake River mollusks. The Company
is cooperating with various governmental agencies to resolve
these issues. (See Part II, Item 7. "Management's Discussion and
Analysis of Financial Condition and Results of Operation -
Environmental Issues".)
     
     Hazardous/Toxic Wastes and Substances -
Under the Toxic Substances Control Act (TSCA), the Environmental
Protection Agency (EPA) has adopted regulations governing the
use, storage, inspection and disposal of electrical equipment
that contain polychlorinated biphenyls (PCBs). The regulations
permit the continued use and servicing of certain electrical
equipment (including transformers and capacitors) that contain
PCBs. The Company continues to meet all federal requirements of
TSCA for the continued use of equipment containing PCBs. The
Company has a program to make the 200-plus substations on its
system non-PCB. While the Company's use of equipment containing
PCBs falls well within the federal standards, the Company has
voluntarily decided to virtually eliminate these compounds from
the substation sites. This program will save costs associated
with the long-term monitoring and testing of substation equipment
and grounds for PCB contamination as well as being good for the
environment today. Total Company costs for the disposal of PCBs
from the Company's system were $1.3 million, $0.4 million and
$0.9 million for 1994, 1995 and 1996 respectively.


RATES
     
     Idaho Jurisdiction
Since 1993, the IPUC has permitted Idaho Power to use a PCA
mechanism in its Idaho jurisdiction.  The PCA enables the Company
to collect or to refund a portion of the difference between net
power supply costs actually incurred and those allowed in the
Company's base rates.  The current balance is adjusted monthly as
actual conditions are compared to the PCA forecasted net power
supply costs.  For the period May 1996 through May 1997, the IPUC
approved tariffs, reducing Idaho jurisdictional PCA rates by
$25.7 million (5.9 percent), including the true-up for the PCA
period May 1995 through May 1996.  The reduction reflects
anticipated lower power supply costs in the coming year due to
above-average hydroelectric generating conditions.  The 1996 PCA
forecast reflects power supply costs below those established for
PCA expenses in the Company's last general rate proceeding.  At
December 31, 1996, the Company had recorded as a deferred asset
and reduction in operating expenses $11.4 million of power supply
costs above those projected in the 1996 forecast.

On January 31, 1995, the Company received IPUC Order No. 25880,
which authorized $17.2 million in general rate relief,
representing a 4.2 percent overall increase in Idaho retail
rates. The relief was based on an 11.0 percent allowed return on
equity and an overall rate of return of 9.2 percent. The increase
in Idaho retail rates went into effect on February 1, 1995.  It
also allows Idaho Power to realign its overall rate structure to
a price, more closely associated with the cost of serving the
different customer classes.

On May 24, 1995, Idaho Power filed another application with the
IPUC to increase rates in its Idaho jurisdiction. In August 1995,
the IPUC issued an order authorizing the Company to increase its
Idaho retail rates on an annual basis by $3.8 million (0.9
percent). This increase was uniform to all customer classes, as
well as to special contract customers. The Company originally
applied for a $6.3 million (l.5 percent) increase to recover
capital costs and related expenses associated with the
construction of a new 43.5 megawatt (MW) power plant at its Twin
Falls hydro facility, along with additional plant investments at
the Swan Falls hydro facility since the filing of its last
general rate case. The major issue in this case was whether the
reduced power supply costs resulting from the inclusion of the
Twin Falls hydro expansion would be recognized explicitly through
a reduction in base energy rates or implicitly through the PCA.
The Company reached a compromise with the IPUC staff on the
overall revenue requirement and agreed to recognize benefits up
front in base rates, instead of flowing the benefits through the
PCA. As a result, the Company's original $6.3 million request was
reduced by $1.9 million.  The effect on projected Company
earnings is only 10 percent of this amount ($190,000), since all
but 10 percent of the power supply cost reduction would have been
passed through to Idaho customers in the next PCA adjustment. The
IPUC action enabled the Company to begin recovering the capital
costs of a plant addition within weeks of the plant becoming
operational.

In December 1993, the Company filed with the IPUC for permission
to approve lower published prices for new CSPP contracts.  In
response to the Company's filing, the IPUC issued an order on
January 31, 1995, approving lower published CSPP rates for new
projects.  In addition, the IPUC determined that negotiated rates
for future CSPP projects larger than 1 MW should be tied more
closely to values determined in the Company's integrated resource
planning process.  In a subsequent order issued on September 4,
1996, the IPUC further recognized the coming changes by limiting
the contract term which a new CSPP project larger than 1 MW could
request to a maximum of five years.

On August 3, 1995, Idaho Power filed a proposal with the IPUC to
support the Company's organizational redesign.  In response to
the Company's proposal, the IPUC approved a Settlement that
authorizes the Company to defer and amortize costs related to
reorganization in return for a general rate freeze through the
end of 1999.  In addition, the Settlement allows for the
accelerated amortization of regulatory liabilities associated
with accumulated deferred investment tax credits (ADITCs) to
provide a minimum 11.50 percent return on actual year-end common
equity for the Idaho jurisdiction.  The new rate freeze and the
accelerated amortization of regulatory liabilities associated
with ADITCs gives the Company time to pursue and to implement its
efficiency and growth initiatives with the assurance of at least
a reasonable level of financial performance apart from the need
to change customer prices.

The terms and conditions of the Settlement will remain in effect
through 1999.  Under the Settlement, when the Company's actual
earnings in a given year exceed an 11.75 percent return on year-
end common equity, the Company will refund 50 percent of the
excess to its Idaho retail customers.  In 1996 the Company set
aside approximately $4.9 million for refund to its Idaho
customers.
Other important points in the Settlement are:  (1) the Company
may accelerate a maximum of $30 million of regulatory liabilities
associated with ADITCs over the five-year period; (2) the Company
will not be allowed to increase its Idaho general rates prior to
January 1, 2000, except under special conditions as defined in
the Settlement; and (3) Idaho Power agrees that its quality of
service will not decline as a result of corporate reorganization.

The Company has received approval from the Idaho State Tax
Commission and the Internal Revenue Service on the accounting
treatment for the tax credits.  No accelerated ADITC was
recognized in 1995 or 1996.
     
     Oregon Jurisdiction -
In response to the Company's April 1995 application, the OPUC
granted $1.5 million in drought-related rate relief. The OPUC
order allows recovery of the $1.5 million through the continued
application of an existing increase authorized in July 1993 (for
1992 drought relief). The rate increase will remain in effect for
approximately 34 months beginning in July 1995. The Company had
deferred, with interest, increased power supply costs between May
1994 and December 31, 1994.

In May 1995, Idaho Power filed an application with the OPUC
seeking general rate relief of approximately $3.4 million, or a
16.65 percent increase. The Company later negotiated a Settlement
Stipulation with the OPUC staff, the Company's Oregon industrial
customers, and the Citizens Utility Board of Oregon. The
Settlement grants Idaho Power a $1.3 million general rate
increase for its Oregon retail customers. The OPUC Settlement
became effective December 5, 1995.
     
     Other Jurisdictions -
In 1996, the Company did not file any applications for rate
relief before the FERC or in its Nevada retail jurisdiction.  In
July 1996, the Company filed an open-access tariff with the FERC,
in compliance with Order 888.  The terms and conditions of the
tariff were approved for use beginning in 1997 (see "Transmission
Services").


CONSTRUCTION PROGRAM
The Company's construction program for the 1997-2001 period
(excluding allowances for funds used during construction) is
presently estimated to require cash funds of approximately $421.7
million as follows:
                                   1997    1998-2001 (a)
                                   (Millions of Dollars)
Generating Facilities:                   
  Hydro                            $3.9      $32.0
  Thermal                           8.2       38.2 
Total generating facilities        12.1       70.2 
Transmission lines and           
substations                        12.0       55.4
Distribution lines and            
substations                        37.8      160.0
General                            22.4       51.8 
  Total cash construction          84.3      337.4 
AFUDC                               1.1        4.1 
  Total construction             
including AFUDC (b)               $85.4     $341.5

(a) Escalation rates were not applied to construction
expenditures because the level of expenditures has
been capped.

(b) Does not include Ida-West equity investment in
construction as Ida-West develops its construction as
a participant in joint ventures which are not a part
of the consolidated entity.

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


FINANCING PROGRAM
The Company's five-year estimate of capital requirements and
sources of capital is $412.7 million outlined as follows:

                                         1997   1998-2001
                                      (Millions of Dollars)
Capital Requirements:                           
  Net cash construction expenditures    $84.3      $337.4 
  Conservation expenditures               1.3        -  
  Other cash expenditures                (0.3)      (10.0)
   Total                                $85.3      $327.4 
Sources of Capital:                             
  Internal generation                   $72.4      $359.6 
  Short-term bank loans - Net            13.3        29.3 
  First mortgage bonds                    -         (60.7)
  Debt repayment                         (0.1)       (0.3)
  Common stock                            -          -  
  Cash investments (increase)            (0.3)       (0.5)
  Total (a)                             $85.3      $327.4 

(a)  Does not include subsidiary financings.

These estimates are subject to constant revision in light of
changing economic, regulatory and environmental factors and
patterns of conservation.  Any additional securities to be sold
will depend upon market conditions and other factors, but it is
the Company's objective to maintain capitalization ratios of
approximately 45 percent common equity, 5 to 10 percent preferred
stock and the balance long-term debt. The Company will continue
to take advantage of any refinancing opportunities as they become
available.

Under the terms of the Indenture relating to the Company's First
Mortgage Bonds, net earnings must be at least two times the
annual interest on all bonds and other equal or senior debt. For
the twelve months ended December 31, 1996, net earnings were 6.52
times. Additional preferred stock may be issued when earnings for
twelve consecutive months within the preceding fifteen months are
at least equal to l.5 times (until December 31, 2000, at which
time the issuance ratio will increase to 1.75 times) the
aggregate annual interest requirements on all debt securities and
dividend requirements on preferred stock. At December 31, 1996,
the actual preferred dividend earnings coverage was 3.11 times.
If the dividends on the shares of Auction Preferred Stock were to
reach the maximum allowed, the preferred dividend earnings
coverage would be 2.84 times. The Indenture and the Company's
Restated Articles of Incorporation are exhibits to the Form 10-K
and reference is made to them for a full and complete statement
of their provisions.

ITEM 2. PROPERTIES
The Company's system includes 17 hydroelectric generating plants
located in southern Idaho and eastern Oregon (detailed below) and
an interest in three coal-fired steam electric generating plants.
The system also includes approximately 4,642 miles of high
voltage transmission lines; 21 step-up transmission substations
located at power plants; 17 transmission substations; 7
transmission switching stations; and 194 energized distribution
substations (excludes mobile substations and dispatch centers).

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

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

At December 31, 1996, the composite average ages of the principal
parts of the Company's system, based on dollar investment, were:
production plant, 17.1 years; transmission system and
substations, 18.2 years; and distribution lines and substations,
13.9 years. The Company considers its properties to be well
maintained and in good operating condition.

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

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

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

Ida-West holds investments in thirteen operating hydroelectric
plants with a total generating capacity of 72 MW.

ITEM 3. LEGAL PROCEEDINGS
On  December  6,  1991,  a complaint entitled  Nez  Perce  Tribe,
Plaintiff, vs. Idaho Power Company, Defendant, Civil No. CIV  91-
0517-S-EJL,  was filed against the Company in the  United  States
District Court for the District of Idaho.

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

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

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

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

On  November  8, 1994, the Tribe filed its Notice of Appeal  with
the Ninth Circuit Court of Appeals.

The  Company and the Tribe have reached agreement on a settlement
of  this  case (Settlement Agreement).  The Settlement  Agreement
has been approved by the Nez Perce Tribal Executive Committee and
the  Company's  Board  of  Directors.  Under  the  terms  of  the
Settlement  Agreement, the Company will pay the Nez  Perce  Tribe
$11.5 million in the following manner:

          -     $5 million at which time the Tribe would move for
          the  dismissal of, with   prejudice, their legal action
          against the Company.

          -     $1,625,000  each  year for the  next  four  years
          beginning in 1998.


All  payments under the Settlement Agreement will be made in 1996
dollars,  which  allows for adjusted future  inflation  within  a
minimum range of 3 percent and a maximum of 7 percent.  The first
payment  of $5.0 million plus inflation adjustment will  be  paid
sometime in 1997.

On July 12, 1996 the IPUC issued Order No 26513, and on August 5,
1996,  the  OPUC issued Order No. 96-207 approving capitalization
of  their  respective jurisdictional share of the $11.5  million.
The parties requested Bureau of Indian Affairs (BIA) approval  of
the  Settlement Agreement.  However, on November  21,  1996,  the
Portland Area Director of the BIA issued a decision stating  that
the  Settlement Agreement did not have to be approved by the BIA.
On  December 19, 1996, the Company filed an administrative appeal
of the BIA's decision and have since requested and been granted a
stay  of  said  appeal  pending pursuit of an  alternate  federal
approval.   As  a result of the BIA decision, the Tribe  and  the
Company  explored alternatives to BIA approval  that  would  help
assure  the  ultimate enforceability of the Settlement Agreement.
The parties agreed to request that the Federal District Court for
the  District  of  Idaho approve the Settlement  Agreement.   The
Tribe  and  the  Company, by motion, stipulated  that  the  Ninth
Circuit  Court of Appeals remand the case to the Federal District
Court for the District of Idaho, which motion was granted by  the
Ninth  Circuit  on February 6, 1997.  The parties will  now  seek
Federal District Court approval of the Settlement Agreement.

This  matter  has  been previously reported in  Form  10-K  dated
March  16, 1992, March 12, 1993, March 10, 1994, March  9,  1995,
March 14, 1996 and other reports filed with the Commission.

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

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

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


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

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

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

On  August 12, 1996, the Idaho Supreme Court determined that  the
District  Court's decision that Cogeneration, Inc., had  breached
the FESA was premature.

On  February  10,  1997,  Cogeneration,  Inc.  filed  an  amended
Complaint restating its previous claims, requesting a jury  trial
rather  than  the  court  trial it had previously  requested  and
raising several new allegations and claims.

While  the  outcome of litigation is never certain,  Idaho  Power
believes  that  Cogeneration, Inc.'s  counterclaims  are  without
merit.

This matter has been previously reported in Form 10-K dated March
14, 1996 and other reports filed with the Commission.

ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS

     None


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

Name, Age and Position       Business Experience During Past Five (5) Years
                             
J. W. Marshall, 58           Appointed August 18, 1989.
Chairman of the Board and
Chief Executive Officer

L. R. Gunnoe, 61             Appointed July 12, 1990.
President and Chief
Operating Officer

J. LaMont Keen, 44           Appointed March 14, 1996.  Mr. Keen
Vice President, Chief        was Vice President and Chief
Financial Officer            Financial Officer prior to March 14,
and Treasurer                1996.

Douglas H. Jackson, 60       Appointed July 12, 1990.
Vice President - Retail
Services

C. N. Olson, 47              Appointed July 11, 1991.
Vice President -Corporate
Services

J. B. Packwood, 53           Appointed July 11, 1996.  Mr.
Executive Vice President     Packwood was Vice President-Power
                             Supply prior to July 11, 1996.

Richard Riazzi, 42           Appointed January 9, 1997.  Mr.
Vice President -             Riazzi was Vice President, Corporate
Marketing and Sales          Marketing (1995-1996) and was Vice
                             President of the Energy Group (1991-
                             1995) for Equitable Resources, Inc.
                             
Robert W. Stahman, 52        Appointed July 13, 1989.
Vice President, General
Counsel and Secretary

PART II

ITEM 5.  MARKET  FOR  THE REGISTRANT'S COMMON STOCK  AND  RELATED
         STOCKHOLDER MATTERS
The  Company has paid cash dividends on its common stock in  each
year since 1918.  For the year ended December 31, 1994, 1995  and
1996,  cash dividends per share of common stock were  $1.86.   At
the  July  1996 meeting, the Board of Directors voted to maintain
the  annual  common  dividend at $1.86  per  share.   It  is  the
intention  of the Board of Directors to continue to pay dividends
quarterly  on the common stock, but such dividends in the  future
will  depend  on earnings, cash requirements of the Company,  and
other factors.

The  Company's common stock is listed on the New York and Pacific
Stock Exchanges. The following table indicates the reported  high
and  low sales price of the Company's common stock for the  years
1995  and  1996,  as  reported  by The  Wall  Street  Journal  as
composite tape transactions. The Company's year-end common  stock
price  was  $31  1/8 per share and the number of stockholders  of
record at December 31, 1996, was 29,333.

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

                                     1996 Quarters
Common Stock, $2.50 par       1st      2nd         3rd       4th
value:
   High                       $31 1/4  $31 1/8     $34 1/4   $32
   Low                         27 1/4   27 5/8      29 3/4    29 7/8
   Dividends paid per share    
    (cents)                    46.5     46.5        46.5      46.5

ITEM 6. SELECTED FINANCIAL DATA

SUMMARY OF OPERATIONS          1996             1995            1994     
(Thousands of Dollars)

Revenues:                                                               
  General business         $  484,145       $   461,594      $   457,354 
  Sales to other utilities     70,222            57,418           59,923
  Other revenues               24,078            26,609           26,381 
     Total revenues           578,445           545,621          543,658   
Expenses:                                                                   
  Purchased power              69,038            54,586           60,216 
  Fuel expense                 63,334            54,691           94,888  
  Other operation and                     
    maintenance               168,539           169,959          154,742 
  Depreciation                 69,705            67,415           60,202 
  Taxes other than                                               
    income taxes               20,658            22,979           23,945   
      Total expenses          391,274           369,630          393,993 
                                              
Income from operations        187,171           175,991          149,665  
Other income and         
 deductions - Net             (12,534)          (14,356)         (12,160)  
Interest charges - Net         56,995            55,014           52,652  
Income taxes                   52,092            48,412           34,243  
Cumulative effect of      
  accruing unbilled
  revenues                       -                 -                -     
Net Income                     90,618            86,921           74,930   
  Dividends on preferred   
   stocks                       7,463             7,991            7,398  
Earnings on common stock       83,155            78,930           67,532 
  Dividends on common      
   stock                       69,924            69,941           69,594    
Net change to retained            
earnings                   $   13,231       $     8,989      $    (2,062) 
                                                                        
CAPITALIZATION (000 ommitted)           %                 %                 %
First mortgage bonds       $  527,000}      $   470,000}      $  490,000}      
Other long-term debt          211,550}  48      202,618}  45     203,206}   46 
Preferred stock               106,975    7      132,181    9     132,456     9 
Common stock (incl.        
prem. & exp.)                 452,486}          452,948}         452,962}      
Retained earnings             242,088}  45      229,827}  46     220,838}   45 
  Total capitalization     $1,540,099  100  $ 1,487,574  100  $ 1,499,462  100
Short-term borrowings   
  outstanding              $   54,016       $    53,020       $    55,000     
                                                                             
FINANCIAL STATISTICS                                                       
Income from operations                                                    
 as a percent of         
 total revenues                  32.4%             32.3%            27.5% 
Times interest charges                                                        
earned:
  Before tax                     3.49              3.40             3.01     
  After tax                      2.58              2.54             2.38   
Market-to-book ratio              169%              165%             131%  
Payout ratio                       84%               89%             103%     
Return on year-end              11.97%            11.56%           10.02%    
common equity
Common stock data:                                                      
  Earnings per average   
   share outstanding       $     2.21        $     2.10        $    1.80  
  Dividends declared per   $     1.86       $      1.86       $     1.86  
   share                    
  Book value per share     $    18.47       $     18.15       $    17.91   
  Average shares       
   outstanding (000 
     ommitted)                 37,612            37,612           37,499  
  Common shareowners           29,333            30,795           26,209     

*Includes cumulative 
  effect of accounting 
  change
                                                                   
CUSTOMER DATA                                                         
General business data:                                              
  Energy sales - kwh     
   (000,000 omitted)           13,035            11,983           12,194    
  Number of customers         352,487           340,708          330,308   
 
Residential customer                                                    
data:
  Number of customers         292,145           282,797          274,187 
  Average kwh use per  
   customer                    13,828            13,475           14,159 
Average rate per kwh (cents)     5.07              5.16             4.83    
                                                                   
OTHER STATISTICS                                                      
Total assets (000    
 omitted)                  $2,295,337       $ 2,241,753       $2,191,816   
Gross plant additions     
 (000 omitted)             $   94,120       $    87,297       $  107,667 
Number of employees     
(full-time)                     1,565             1,522            1,609    



                           1993            1992            1991          
Revenues:
  General Business         $  428,658      $  431,818      $  409,454
  Sales to other utilities     86,525          42,000          52,563
  Other revenues               25,219          24,274          21,176 
        Total Revenues        540,402         498,092         483,193 
Expenses:    
  Purchased power              45,361          58,496          51,210
  Fuel expense                 87,855          96,710          75,161
  Other operation and
   maintenance                164,388         137,547         151,593
  Depreciation                 58,724          59,823          57,597
  Taxes other than
    income taxes               22,129          20,562          21,168
      Total expenses          378,457         373,138         356,729

Income from operations        161,945         124,954         126,464
Other income and
 deductions - Net             (12,984)        (11,133)         (9,453)
Interest charges - Net         53,991          52,935          56,901 
Income taxes                   36,474          23,162          21,144
Cumulative effect of 
  accruing unbilled
  revenues                        -               -               -   
Net Income:                    84,464          59,990          57,872
  Dividends of preferred
   stocks                       6,009           5,516           4,904
Earnings on common stock       78,455          54,474          52,968
  Dividends on common stock    67,959          65,043          63,197
Net change to retained 
  earnings                 $   10,496         (10,569)        (10,229)

CAPITALIZATION 
  (000 omitted)                         %               %               %
First mortgage bonds       $  490,000}     $  485,000}     $  435,000}  48  
Other long-term debt          203,780}  47    216,948}  49    194,981}      
Preferred stock               132,751    9    107,874    7    108,191    8
Common stock (incl.
  prem. & exp.)               439,467}        412,998}        356,824}    
Retained earnings             222,900}  44    212,404}  44    222,973}  44
     Total capitalization  $1,488,898  100  $1,435,224  100 $1,317,969 100
Short-term borrowings
  outstanding              $    4,000       $    6,000      $   48,500   

FINANCIAL STATISTICS
Income from operations
  as a percent of total
  revenues                       30.0%           25.1%           26.2%
Times interest charged earned:                                            
  Before tax                     3.14            2.50            2.34
  After tax                      2.50            2.08            1.98
Market-to-book ratio              170%            159%            168%
Payout ratio                       87%            120%            119%
Return on year-end common
  equity                        11.84%           8.71%           9.14%

Commmon stock data:
  Earnings per average
    share outstanding     $      2.14     $      1.55      $     1.56
  Dividends declared
    per share             $      1.86     $      1.86      $     1.86
  Book value per share    $     17.86     $     17.28      $    17.07
  Average shares 
    outstanding (000
    ommitted)                  36,675          35,116          33,977
  Common Shareowners           26,870          27,834          28,069
*includes cumulative effect of accounting change

CUSTOMER DATA
General business data:
  Energy sales - kwh
    (000,000 ommitted)         11,406          11,606          11,266
  Number of customers         317,772         307,567         297,808
Residential customer data:                                     
  Number of customers         263,682         255,022         246,689
  Average kwh use per 
    customer                   14,587          13,856          14,845
  Average rate per kwh
    (cents)                      4.82            4.80            4.72
                                     
OTHER STATISTICS                                     
Total assets (000 
  omitted)                 $2,097,417       $1,862,307      $1,773,674
Gross plant additions
  (000 omitted)            $  116,972       $  118,920      $  135,904
Number of employees
  (full-time)                   1,654            1,638           1,626


                           1990             1989             1988     
Revenues: 
  General business         $  401,350       $  397,974       $  362,050
  Sales to other utilities     44,368           70,749           32,175
  Other revenues               19,217           27,438           18,096
       Total revenues         464,935          496,161          412,321
Expenses:    
  Purchased power              43,923           43,845           43,723
  Fuel expense                 77,606           77,127           74,528
  Other operation and 
   maintenance                134,126          132,114          116,230
  Depreciation                 55,114           53,092           51,691
  Taxes other than income
   taxes                       20,752           20,213           19,301
       Total expenses         331,521          326,391          305,473
Income from operations        133,414          169,770          106,848
Other income and deductions
  - Net                       (11,666)         (10,005)          (6,552)
Interest charges - Net         52,605           52,997           50,762
Income taxes                   23,234           42,041           13,558
Cumulative effect of 
  accruing unbilled revenu       -                -                -  
Net Income                     69,241           84,737           49,080
  Dividends on preferred
    stocks                      4,279            4,285            4,293
Earnings on common stock       64,962           80,452           44,787
  Dividends on common stock    63,197           62,177           61,159
Net change to retained
  earnings                      1,765           18,275          (16,372)
            
CAPITALIZATION 
  (000 omitted)                        %               %                %
First mortgage bonds       $  367,500}      $  377,000}      $  392,000}     
Other long-term debt          194,159}  46     165,551}  47     164,426}  47
Preferred stock                58,761    5      58,923    5      59,126    5
Common stock (incl.
  prem. & exp.)               358,078}         357,986}         357,866}   
Retained earnings             233,241}  49     231,476}  48     213,201}  48
    Total capitalization   $1,211,739  100  $1,190,936  100  $1,186,619  100
Short-term borrowings
  outstanding              $   48,280       $   31,000       $   37,000    

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

CUSTOMER DATA                                      
General business data:
  Energy sales - kwh 
    (000,000 omitted)          11,086           11,069           10,563
  Number of customers         291,800          284,363          279,529
Residential customer data:                                       
  Number of customers         241,790          236,008          232,650
  Average kwh use per 
    customer                   14,281           14,923           14,364
  Average rate per kwh
    (cents)                      4.73             4.69             4.47
                                           
OTHER STATISTICS                                          
Total assets (000 omitted) $1,680,110       $1,625,120       $1,608,935
Gross plant additions 
  (000 omitted)            $   80,117       $   62,094       $   64,358
Number of employees
  (full-time)                   1,574            1,528            1,500


                           1987            1986     
Revenues:                                       
  General business         $  343,899      $  336,480
  Sales to other utilities     35,447          54,987           
  Other revenues               15,251          17,394
       Total revenues         394,597         408,861 
Expenses:    
  Purchased power              30,234          31,849  
  Fuel expense                 65,934          31,260
  Other operations and
    maintenace                114,235         114,407
  Depreciation                 50,929          49,308
  Taxes other than 
    income taxes               19,072          18,539
       Total expenses         280,404         245,363

Income from operations        114,193         163,498
Other income and 
  deductions - Net            (13,115)        (17,064)
Interest charges - Net         51,843          51,206
Income taxes                   27,246          50,923
Cumulative effect of 
  accruing unbilled
  revenues                    (11,302)            -
Net Income                     59,521          78,433
  Dividends on preferred
    stock                       4,298          10,553                 
Earnings on common stock       55,223          67,880                       
  Dividends on common stock    61,159          59,755                       
Net change to retained
  earnings                     (5,936)          8,125
            
CAPITALIZATION
  (000 Omitted)                         %                 %
First mortgage bonds       $  407,000}      $  432,000}
Other long-term debt          160,003}  47     153,887}  47   
Preferred stock                59,238    5      59,403    5
Common stock (incl.
  prem. & exp.)               357,797}         357,708}
Retained earnings             229,573}  48     235,509}  48
     Total capitalization  $1,213,611  100  $1,238,507  100
Short-term borrowings
  outstanding              $    4,000       $    5,000

FINANCIAL STATISTICS
Income from operations
  as a percent of total
  revenues                       28.9%            40.0%
Times interest charges earned:                                  
  Before tax                     2.76*            3.40
  After tax                      2.10*            2.46
Market-to-book ratio              127%             150%   
Payout ratio                      111%              88%   
Return on year-end common
  equity                         9.40%           11.44%   
Common stock data:
  Earnings per average
    share outstanding      $     1.63*      $     2.00          
  Dividends declared per
    share                  $     1.80       $     1.76     
  Book value per share     $    17.29       $    17.46     
  Average shares outstanding
    (000 omitted)              33,977           33,961
  Common shareowners           33,733           34,456
*Includes cumulative effect of accounting change
                 
CUSTOMER DATA
General business data:
  Energy sales - kwh
    (000,000 omitted)          10,175            9,938
  Number of customers         276,249          274,129
Residential customer data:                       
  Number of customers         230,486          228,921
  Average kwh use per 
    customer                   13,785           14,541
  Average rate per kwh
    (cents)                      4.34             4.21
                    
OTHER STATISTICS                     
Total assets (000 omitted) $1,602,311       $1,621,887
Gross plant additions
  (000 omitted)            $   38,929       $   50,257   
Number of employees 
  (full-time)                   1,521            1,524


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

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

FORWARD-LOOKING INFORMATION -
Certain matters discussed in this report are "forward-looking
statements" intended to qualify for the safe harbor from
liability established by the Private Securities Litigation Reform
Act of 1995.  Such statements address future plans, objectives,
expectations, and events or conditions concerning various matters
such as capital expenditures, earnings, litigation, rate and
other regulatory matters, liquidity and capital resources, and
accounting matters.  Actual results in each case could differ
materially from those currently anticipated in such statements,
by reason of factors such as electric utility restructuring,
including ongoing state and federal activities; future economic
conditions; legislation; regulation; competition; and other
circumstances affecting anticipated rates, revenues and costs.

EARNINGS PER SHARE AND BOOK VALUE -
Earnings per share of common stock in 1996 totaled $2.21, up from
the $2.10 earned in 1995 and the $1.80 earned in 1994.  The 1996
earnings equate to a 12.0 percent earned return on year-end
common equity, as compared to the 11.6 percent earned in 1995 and
the 10.0 percent earned in 1994.  At December 31, 1996, the book
value per share of common stock was $18.47.

A number of factors have affected earnings per share over the
last three years:  improved hydro conditions, a strong service
territory economy, continued customer growth, and resolution of
rate cases in 1995.  In 1996, under terms and conditions of the
regulatory settlement with the Idaho Public Utilities Commission
(IPUC), the Company set aside approximately $4.9 million for
refund to its Idaho customers.  This provision for refund reduced
reported earnings per share by approximately eight cents (See
"Regulatory Settlement").


RESULTS OF OPERATIONS -

     Customer Growth and Energy Demand -
New customer growth continued at a brisk pace with the Company
adding 11,779 new general business customers during 1996.  This
increase marks 1996 as the Company's second best year in terms of
customer growth.  This, added to 1994's record-setting 12,536 new
customers, and 1995's 10,400, combined for a three-year total of
34,715 (10.9 percent) new general business customers.  During
1996, Idaho Power added 9,348 residential customers, 2,090
commercial customers, and 339 irrigation customers.

Higher summer temperatures led to increases in energy demand
during 1996.  In contrast, 1995 had milder winter and summer
weather conditions which reduced loads for heating and cooling,
while the wet, cool spring reduced irrigation loads.

     Economy -
Idaho's economy continued to outperform the nation in terms of
non-agricultural employment growth.  Idaho's overall non-
agricultural employment growth advanced at a 4.1 percent annual
rate through the first eight months of 1996.  This compares to
1995's 3.2 percent growth rate.  Employment in the manufacturing,
construction, service and trade industries posted gains of 1.8
percent, 12.5 percent, 7.6 percent and 3.7 percent, respectively,
for the first eight months of 1996.  The state's economic
performance has fluctuated during the periods presented, but
Idaho's economy continues to create jobs and attract new
companies to the state.

     Revenues -
For the three-year period 1994-1996, the Company received an
average 85 percent of its operating revenues from electric sales
in Idaho, 5 percent in Oregon, less than 1 percent in Nevada, and
9 percent from the wholesale market.  For the same three-year
period, the average percentages of total operating revenues by
customer category were as follows:

-  35 percent from residential customers;
-  30 percent from a combination of irrigation customers, street
   lighting customers, and commercial customers with less than
   1,000 kW demand;
-  19 percent from industrial customers with demand of 1,000 kW or greater;
-  11 percent from off-system sales to other utilities and interchange 
   arrangements; and
-  5 percent from miscellaneous revenue

The Company's energy sales to general business customers,
increased 6.9 percent in 1994 and 8.8 percent in 1996, but
decreased 1.7 percent in 1995.  In 1995, residential usage was
down l.5 percent, due to the mild weather, despite an increase in
customers during the year.  Also contributing to the 1995 decline
was wet spring weather that reduced irrigation kilowatt sales in
that year by 25.2 percent.

The year 1996 saw energy sales increase in all customer classes.
Residential and commercial sales increased 6.0 percent and 9.3
percent, respectively, due to increased customers, a strong
economy, and weather factors providing more heating-and cooling-
degree days during the year.  Irrigation sales increased 21.0
percent with a return to more normal weather patterns during the
summer months.  Industrial sales also grew by 7.0 percent in
1996.

General business revenues represent approximately 84 percent of
the Company's total operating revenues.  General business
revenues were $457.4 million in 1994, $461.6 million in 1995, and
$484.1 million in 1996.  The 1995 increase reflects rate
increases during the year and increased sales to some industrial
customers.  The 1996 increase comes primarily from residential,
$8.0 million (4.2 percent), commercial $5.0 million (4.9
percent), and irrigation, $6.7 million (12.1 percent).  The
average residential customer used 14,159 kwh in 1994, 13,475 kwh
in 1995, and 13,828 kwh in 1996.  These averages reflect changes
due to varied weather patterns.
     
     Off-System Sales -
Off-system sales are composed of firm sales (long-term contracts)
and opportunity sales made on a when-available basis. The volume
and price of these latter sales depend on the Company's firm energy
demand, hydroelectric generating conditions in its service
territory, and market conditions throughout the West. Revenues
from off-system sales declined $26.6 million in 1994.  Off-system
revenues declined an additional $2.5 million in 1995, but rose by
$12.8 million in 1996.

In 1995 and 1996, improved hydroelectric generating conditions
created an increase in off-system sales, while drought conditions
reduced sales in 1994.  In 1995, improved hydroelectric
conditions created an increase in off-system sales.  However,
reduced demand on the off-system market cut the prices of such
sales.
     
     Expenses -
Total operating expenses rose $15.5 million in 1994, decreased by
$24.4 million in 1995, and increased $21.6 million in 1996.  The
increase in expense for 1994 reflects drought conditions, which
increased the Company's reliance on thermal generation and
purchased power.  The decrease in 1995 resulted from improved
hydroelectric operating conditions, which lowered purchased power
and fuel expense.

In 1996, purchased power expense was up $14.5 million.  This
increase reflects economy purchases made to take advantage of low
wholesale market prices during the year and increased purchases
from cogeneration and small power production (CSPP) projects
which also experienced strong hydroelectric generating
conditions.  The low market prices were a result of the abundance
of hydro generation in the West, which allowed the Company to
remarket this energy to others.  In 1995, with the return to more
normal hydro conditions, purchased power expense was lower when
compared to 1994, a year in which drought conditions were
experienced.

Fuel expense  also increased in 1996 by $8.6 million.  The
largest increase came in the fourth quarter, mainly due to the
operation of the Valmy coal-fired plant.  A reduction in spot
market coal prices allowed the Company to generate additional
energy and to be competitive in the off-system market.  In 1995,
the Company experienced good seasonal hydroelectric conditions,
thereby reducing its reliance on thermal generation.

The Power Cost Adjustment (PCA) component of expenses was up
$19.3 million when comparing 1995 to 1994.  However, for 1996,
the PCA was down $14.1 million, compared to 1995.  The PCA
mechanism reduces expenses when power supply costs are above
forecast, and increases expenses when power supply costs are
below forecast  (see "PCA discussion").

All other operation and maintenance expenses fluctuated during
the three-year period, with a cumulative increase of $9.5
million.  These variations are due, in part, to increases in
payroll and benefits, changes in operation and maintenance due to
water conditions, as well as reconstruction of Company facilities
damaged or destroyed by natural causes.

Depreciation expense was up for the three-year period by $10.9
million (18.7 percent), due to a greater plant investment base,
while taxes other than income taxes decreased $1.5 million (6.6
percent).

     Interest Charges -
Interest charges on long-term debt fluctuated during the three-
year period, with a cumulative decrease of $1.5 million.  This
decrease reflects the maturity, early redemption, and issuance of
several series of first mortgage bonds at reduced or lower
interest rates.  Additionally, the Company took advantage of
lower interest rates to refinance several existing higher-cost
Pollution Control Revenue Bond issues with new lower-cost
Pollution Control Revenue Bond issues.  Refinancing in 1996
reduced interest requirements by $2.2 million over 1995.  These
amounts will fluctuate as two series of these bonds are variable
rate, while the third is fixed.  Also, this refinancing
lengthened the maturity of these bonds from those originally
issued.

During 1996, the Company redeemed the 8.375% Series of Serial
Preferred Stock and retired at maturity the 5.25% Series of First
Mortgage Bonds.  This was accomplished by issuing two series of
medium term notes.  This financing reduced the Company's overall
cost of capital (see Note 5 of "Notes to Consolidated Financial
Statements").

Interest on short-term debt rose during the three-year period due
to fluctuating interest rates, as well as to a higher level of
short-term borrowings.  At December 31, 1996, the Company's short-
term borrowings totaled $54.0 million (see Note 7 of "Notes to
Consolidated Financial Statements").
     
     Precipitation and Streamflows -
Idaho Power analyzes precipitation and streamflow conditions
based on the effect on Brownlee Reservoir, the primary water
source for the three Hells Canyon hydroelectric power plants.  In
normal years, these three projects combine to produce about half
of the Company's generated electricity.  In 1994, drought
conditions reduced the amount of water flowing into the Company's
reservoir system.  However, in 1995 and 1996, Idaho Power's
service territory experienced above average water years.  Between
April and July 1996, the Company recorded 8.3 million acre feet
(MAF) of water flowing into Brownlee Reservoir.  This compares
with 1994's 2.8 MAF, 1995's 6.6 MAF, and the 66-year median of
4.8 MAF.  The early indications for 1997 are promising.  As of
February 1, 1997, reservoir storage above Brownlee Reservoir was
79 percent of capacity compared to 81 percent of 1995.  The
average snow-water equivalent for the Snake River above Brownlee
Reservoir was 171 percent of the 30-year average at this time of
year.
     
     Energy Requirements -
With precipitation and streamflow conditions above normal in
1996, hydroelectric generation accounted for 58 percent of the
Company's total energy requirements.  This figure is an
improvement over 1994's 40 percent, and is unchanged from 1995.
During 1996, thermal generation accounted for 26 percent of total
energy requirements, while purchased power and other interchanges
supplied 16 percent. Under historically normal conditions, the
Company's hydro system supplies approximately 57 percent of its
total energy requirements, with thermal generation accounting for
34 percent and purchased power and other interchanges
contributing the remaining 9 percent.

The Company expects to meet 1997's projected energy loads by
using its hydro and coal-fired facilities and its strategic
geographic location, which presents excellent opportunities to
purchase, sell, exchange, and transmit Northwest energy.
     
     Regulatory Issues -
     
          Power Cost Adjustment -
Since 1993, the IPUC has permitted Idaho Power to use a PCA
mechanism in its Idaho jurisdiction.  The PCA enables the Company
to collect or to refund a portion of the difference between net
power supply costs actually incurred and those allowed in the
Company's base rates.  The current balance is adjusted monthly as
actual conditions are compared to the PCA  forecasted net power
supply costs.  For the period May 1996 through May 1997, the IPUC
approved tariffs, reducing Idaho jurisdictional PCA rates by
$25.7 million (5.9 percent), including the true-up for the PCA
period May 1995 through May 1996.  The reduction reflects
anticipated lower power supply costs in the coming year due to
above-average hydroelectric generating conditions.  The 1996 PCA
forecast reflects power supply costs below those established for
PCA expenses in the Company's last general rate proceeding.  At
December 31, 1996, the Company had recorded as a deferred asset
and reduction in operating expenses $11.4 million of power supply
costs above those projected in the 1996 forecast.
     
          General Revenue Requirement Case -
On January 31, 1995, the Company received IPUC Order No. 25880,
which authorized $17.2 million in general rate relief,
representing a 4.2 percent overall increase in Idaho retail
rates.  The relief was based on an 11.0 percent allowed return on
equity and an overall rate of return of 9.2 percent.  The
increase in Idaho retail rates went into effect on February 1,
1995.
     
          Twin Falls Rate Case -
In August 1995, the IPUC issued an order authorizing the Company
to increase its Idaho retail rates on an annual basis by $3.8
million (0.9 percent).  This increase was uniform to all customer
classes, as well as to special contract customers.
     
          Regulatory Settlement -
On August 3, 1995, Idaho Power filed a proposal with the IPUC to
support the Company's organizational redesign.  In response to
the Company's proposal, the IPUC approved a Settlement that
authorizes the Company to defer and amortize costs related to
reorganization in return for a general rate freeze through the
end of 1999.  In addition, the Settlement allows for the
accelerated amortization of regulatory liabilities associated
with accumulated deferred investment tax credits (ADITCs) to
provide a minimum 11.50 percent return on actual year-end common
equity for the Idaho jurisdiction.  The new rate freeze and the
accelerated amortization of regulatory liabilities associated
with ADITCs gives the Company time to pursue and to implement its
efficiency and growth initiatives with the assurance of at least
a reasonable level of financial performance apart from the need
to change customer prices.

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

Other important points in the Settlement are:  (1) the Company
may accelerate a maximum of $30 million of regulatory liabilities
associated with ADITCs over the five-year period; (2) the Company
will not be allowed to increase its Idaho general rates prior to
January 1, 2000, except under special conditions as defined in
the Settlement Agreement; and (3) Idaho Power agrees that its
quality of service will not decline as a result of corporate
reorganization.

The Company has received approval from the Idaho State Tax
Commission and the Internal Revenue Service on the accounting
treatment for the tax credits.  No accelerated ADITC was
recognized in 1995 or 1996.
     
          Cogeneration and Small Power Production Contracts -
In light of the potential deregulation of the electric utility
industry and a more competitive power supply marketplace, Idaho
Power believes that resource acquisition policies must avoid
burdening the Company and its customers with unnecessary future
power supply costs.  In December 1993, the Company filed with the
IPUC for permission to approve lower published prices for new
CSPP contracts.  In response to the Company's filing, the IPUC
issued an order on January 31, 1995, approving lower published
CSPP rates for new projects.  In addition, the IPUC determined
that negotiated rates for future CSPP projects larger than 1
megawatt (MW) should be tied more closely to values determined in
the Company's integrated resource planning (IRP) process.  In a
subsequent order issued on September 4, 1996, the IPUC further
recognized the coming changes by limiting the contract term which
a new CSPP project larger than 1 MW could request to a maximum of
five years.
     
          Oregon General Rate Relief -
In May 1995, Idaho Power filed an application with the Oregon
Public Utilities Commission (OPUC), seeking general rate relief
of approximately $3.4 million, or a 16.65 percent increase.  The
Company later negotiated a Settlement Stipulation with the OPUC
staff, the Company's Oregon industrial customers, and the
Citizens Utility Board of Oregon.  The Settlement grants Idaho
Power a $1.3 million general rate increase for its Oregon retail
customers.  The OPUC approved the Settlement Stipulation on
November 28, 1995.
     
          Oregon Drought-Related Rate Relief -
In response to the Company's April 1995 application, the OPUC
granted $1.5 million in drought-related rate relief.  The OPUC
order allows recovery of the $1.5 million through the continued
application of an existing increase authorized in July 1993 (for
1992 drought relief). The rate increase will remain in effect for
approximately 34 months beginning in July 1995.  The Company had
deferred, with interest, increased power supply costs between May
1994 and December 31, 1994.
     
     Subsidiaries -
     
          Ida-West Energy Company -
This wholly owned subsidiary of the Company holds investments in
13 operating hydroelectric plants with a total generating
capacity of 72 megawatts (MW).

In January 1996, Ida-West made an investment by acquiring all of
the outstanding bonds that were issued to finance three
hydroelectric plants known collectively as the Friant Power
Project.  This project is located at the U.S. Bureau of
Reclamation's Friant Dam on the headwaters of the San Joaquin
River in Madera and Fresno Counties, California.  It has an
aggregate generating capacity of 27.4 MW.  The project is owned
and operated by Friant Power Authority, a quasi-governmental
entity consisting of six irrigation districts, a water district,
and a municipal utility district.

In November 1996, Ida-West purchased an interest in five
hydroelectric projects located in Shasta County, California, with
a total generating capacity of 11.2 MW.  Ida-West acquired the
projects through a limited liability company in which it holds a
50 percent interest.

In addition, Ida-West has an interest in the Hermiston Power
Project, a 460 MW, gas-fired cogeneration project to be located
near Hermiston, Oregon.  Ida-West has been responsible for
managing all permitting and development activities relating to
the project since its inception in 1993, and has obtained all
permits necessary for construction and operation of the project.
The partnership is exploring various alternatives for marketing
the project's output.  Project financing for construction costs
would be non-recourse to Idaho Power.

To date, the Company has invested $20 million in Ida-West.  Ida-
West continues an active search for new projects.
     
          IDACORP, Inc. -
Through this wholly-owned subsidiary, the Company is
participating in five affordable housing programs.  These
investments provide a return to IDACORP by reducing the Company's
federal income taxes and by assuring a return on investment
through tax credits and tax depreciation benefits.  To date, the
Company has invested $4.0 million in IDACORP.
     
          Idaho Power Resources Corporation -
IPRC, is a wholly-owned subsidiary, incorporated in March 1996 to
provide guidance, resources, and long-term strategic planning to
projects or business proposals that are not subject to regulation
by the FERC and the state regulatory commissions.  IPRC's goals
are to establish, acquire, and expand business operations in
sustainable infrastructure technology and services including
energy, water, waste disposal, telecommunications, and
information systems.  The Company has invested approximately $4.0
million in development and acquisition activities in IPRC.

IPRC has a Memorandum of Understanding signed by Idaho Power and
representatives from the government of Indonesia on March 6, 1996
that cleared the way to conduct a detailed feasibility study on
using solar photovoltaic (PV) technology, micro hydroelectric
systems, and other renewable energy systems to provide
electricity to various locations throughout Indonesia's complex
of islands.  IPRC is currently reviewing results of the completed
business plan.  If the project is deemed workable and receives
the required approvals, IPRC would likely begin to develop
services in 1997.

In October 1996, IPRC acquired a majority interest in Applied
Power Corporation (APC), a Lacey, Washington-based, company that
designs, supplies, and distributes photovoltaic (PV) systems.
     
          Stellar Dynamics -
Stellar Dynamics core business is to provide products and
services to control, protect, and monitor utility and industry
processes and equipment.  Stellar offers design and integration
of high-quality modular process control systems backed with field
support, training, documentation, and customer service.  The
Company has invested $1.5 million in Stellar.  As Stellar's
capital requirements increase, the Company has approved
additional equity investments up to a total of $3.0 million.

LIQUIDITY AND CAPITAL RESOURCES -

     Cash Flow -
The Company's net cash generation from operations totaled $468.0
million for the three-year period 1994-1996.  After deducting
common and preferred dividends of $232.8 million, net cash
generation from operations provided approximately $235.2 million
for the Company's construction program and other capital
requirements.

Internal cash generation after dividends provided 41 percent of
the Company's total capital requirements in 1994, 101 percent in
1995, and 99 percent in 1996.  The Company forecasts that
internal cash generation after dividends will provide
approximately 85 percent of total capital requirements in 1997
and over 94 percent during the four-year period 1998-2001.  Idaho
Power expects to continue financing its construction program and
other capital requirements with both internally generated funds
and, to the extent necessary, externally financed capital.
During the forecast period, the Company also has first mortgage
bond maturities of $30.0 million in 1998, $80.0 million in 2000,
and $30.0 million in 2001.  At January 1, 1997, the Company had
regulatory authority to incur up to $200.0 million of short-term
indebtedness.  On December 19, 1996, the Company replaced its
committed lines of credit arrangements with a $120.0 million
multi-year revolving credit facility under which the Company will
pay a facility fee on the commitment, quarterly in arrears, based
on the Company's first mortgage bond rating (see Note 7 of "Notes
to Consolidated Financial Statements").
     
     Construction Program -
The Company's consolidated cash construction expenditures totaled
$110.5 million in 1994, $84.0 million in 1995, and $93.6 in 1996.
Approximately 25 percent of these expenditures were for
generation facilities, 15 percent for transmission facilities, 43
percent for distribution facilities, and 17 percent for general
plant and equipment.
     
          Twin Falls Project -
In July 1995, the Company completed testing of the new expansion
turbine at its Twin Falls Hydroelectric Project and declared the
unit available for commercial operation.  This project added 43.5
MW of capacity to the Company's generation system and a second
powerhouse to the Twin Falls site.
     
          Southwest Intertie Project -
The Company's Southwest Intertie Project (SWIP) is on hold.  At
the current time, an order from the Public Service Commission of
Nevada is still pending, that would allow Nevada Power to
participate in the project.

The Company's SWIP proposal calls for a 500-mile, 500-kilovolt
(kV) transmission line that would serve as a major north-south
transmission artery, connecting the Company's system with those
of utilities in California and the Southwest.  The U.S. Bureau of
Land Management has issued a favorable record of decision on the
Company's environmental impact statement and granted the project
a right-of-way across public lands in Idaho, Nevada, and Utah.

The Company and interested parties have completed ownership
allocation and negotiations for the execution of the Memorandum
of Agreement (MOA).  When the MOA is executed, the Company will
require each party to pay its share of the approximately $8.5
million expended for environmental permitting, right-of-way
acquisition, and related development activities.  The SWIP owners
will then form an Executive Committee, with voting rights
proportional to each share of the project.  The Executive
Committee will oversee development activities for the SWIP and
related projects.

     Financing Program -
     
          Capital Structure -
The Company's capital structure (as illustrated in Selected
Financial Data) fluctuated during the three-year period, with
common equity ending at 45 percent, preferred stock  7 percent,
and long-term debt 48 percent at December 31, 1996.  The
Company's objective is to maintain capitalization ratios of
approximately 45 percent common equity, 5-10 percent preferred
stock, and the balance in long-term debt.  The Company's pre-tax
interest coverage ratios were 3.01 times in 1994, and 3.40 times
in 1995, and 3.49 times in 1996.  The Company has on file a shelf
registration statement for the issuance of first mortgage bonds
and/or preferred stock, with an aggregate principal amount not to
exceed $200 million. On July 29, 1996, the Company issued
$30,000,000 principal amount of Secured Medium Term Notes, Series
B, 6.93% Series Due 2001.  The net proceeds were used for
repayment of commercial paper issued in connection with the
Company's ongoing construction program.  On October 2, 1996,
$27,000,000 principal amount of Secured Medium Term Notes, Series
B, 6.85% Due 2002 were issued with net proceeds from this sale
used to redeem the Company's 250,000 shares 8.375% Series, Serial
Preferred Stock, Without Par Value.

On August 29, 1996, tax exempt Pollution Control Revenue
Refunding Bonds were issued in principal amount of $68,100,000
Series 1996A, $24,200,000 Series 1996B and $24,000,000 Series
1996C.  The proceeds were used to retire the $24,200,000
Pollution Control Revenue Bonds Due 2003, $24,000,000 -Pollution
Control Revenue Bonds Due 2007 and the $68,100,000 Pollution
Control Revenue Bonds Due 2013-2014.
     
          Common Stock -
During the period of January through May 1994, the Company issued
original issue shares of common stock for its Dividend
Reinvestment and Stock Purchase Plan, and for its Employee
Savings Plan. During 1994, common shares totaling 527,296, were
issued under these plans.  The Company used the net proceeds from
these issues for its ongoing construction program.  During 1995
and 1996, no original issue shares were issued pursuant to these
plans.
     
     Environmental Issues -
     
          Salmon Recovery Plan -
Work continues on the development of a comprehensive and
scientifically credible plan to ensure the long-term survival of
anadromous fish runs on the Columbia and Lower Snake rivers.

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

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

The Northwest Power Planning Council (NWPPC) issued its recovery
plan for Snake River anadromous fish, the Strategy for Salmon, on
December 15, 1994.  The NWPPC plan calls on the U. S. Bureau of
Reclamation (BOR) to acquire 500,000 acre-feet of water within
the Snake River Basin by 1996, and an additional 500,000 acre-
feet by 1998.  The water is to be acquired from willing sellers.
Thus far, the BOR has indicated it does not intend to comply with
the request to acquire 1,000,000 acre-feet of additional water.
However, if the BOR does comply and successfully implements the
request, its movement of additional water could have a material
impact on the Company's power supply costs.  The strategy for
Salmon also calls for the Company to contribute 427,000 acre-feet
of water from Brownlee Reservoir as required in the NMFS Proposed
Recovery Plan.  The Company has negotiated a five-year contract
with BPA to replace lost energy and capacity resulting from
recovery plans that impact the Company's power supply cost.
     
          Nez Perce Lawsuit -
In 1996, Idaho Power's Board of Directors and the Nez Perce Tribe
approved an Agreement between the Company and the Tribe which
would resolve a civil lawsuit filed against Idaho Power in
December of 1991, in the United States District Court for the
District of Idaho, regarding alleged damages to the Tribe's
treaty-reserved fishing rights.

The suit arose from the construction, maintenance, and operation
of Idaho Power's three-dam Hells Canyon Complex and the project's
alleged impact both on fish and the Tribe's treaty-reserved
fishing rights.  The Agreement required the approval of the
United States government (through the Bureau of Indian Affairs
(BIA)) acting in its capacity as trustee for the Tribe. Under the
terms of the Agreement, Idaho Power will pay the Nez Perce Tribe
$11.5 million in the following manner:

    -  $5 million at which time the Nez Perce would move for the
       dismissal of, with prejudice, their legal action against the
       Company.
    -  $1,625,000 each year for the next four years.

All payments under the Agreement will be made in 1996 dollars,
which allows for adjusted future inflation within a minimum range
of 3 percent and a maximum of 7 percent.  The first payment of $5
million plus inflation adjustment will be paid before the end of
1997.

On July 12, 1996 the IPUC issued Order No. 26513, and on August
5, 1996, the OPUC issued Order No. 96-207 approving
capitalization of their respective jurisdictional share of the
$11.5 million.  The Company has recorded the $11.5 million as a
regulatory asset due from ratepayers and a liability to the
Tribe.  The Tribe requested BIA approval.  However, on November
21, 1996, the Portland Area Director of the BIA issued a decision
stating that the Agreement did not have to be approved by the BIA
and declined to review the Agreement.  On December 19, 1996, the
Company filed an administrative appeal of the BIA's decision.  As
a result of the BIA decision, the Tribe and the Company are
exploring alternatives to BIA approval that would help assure the
ultimate enforceability of the Agreement.

In connection with settling the litigation, Idaho Power and the
Tribe also reached a provisional settlement regarding the license
renewal of the Hells Canyon Complex.  In return for the Tribe's
support of the Company's application to relicense the project,
the Company will place $5 million, the majority of which the
Tribe has agreed to dedicate to implementable fisheries
restoration efforts, in an escrow account on August 3, 2003, the
date by which the Company must file its relicense application.
The Tribe will be entitled to earnings from investments on this
account until the Company accepts or rejects a new federal
license for the project.  If the Company accepts the new federal
license, the Tribe will take ownership of the money in the
account.  If the Company rejects the license, the money will be
returned to the Company.  This settlement is provisional because
the Tribe retains the right to opt out of this relicensing
settlement at any time prior to the Company's acceptance of a new
federal license.
     
          Threatened and Endangered Snails -
In mid-December 1992, the U.S. Fish and Wildlife Service (USFWS)
listed five species of Snake River snails as Threatened and
Endangered Species.  Since that time, the Company has included
this possibility in all of its discussions regarding relicensing
and new hydro development.

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

In 1995, as a part of its federal hydro relicensing process,
Idaho Power obtained a permit from the USFWS to study five
species of endangered Snake River snails.  The Company's
biologists will conduct this study over the next three years,
focusing on potential snail habitat in the Middle Snake River.
The Company's objective is to gain scientific insight into how or
if these snails are affected by a variety of factors, including
hydropower production, water quality, and irrigation run-off.
The study will review how these and other factors influence the
status of the various colonies and their respective habitats.
     
          Mountaineer Cleanup -
In May 1993, the Company was notified that Bridger Coal Company
(BCC) was a potential contributor to a Superfund site involving
waste motor oil delivered to Mountaineer Refinery in Wyoming.
Idaho Energy Resources Company (IERCo), a wholly-owned subsidiary
of Idaho Power, owns one-third of BCC.  In November 1993, BCC
agreed to be included on the list of parties potentially
responsible for this site.  The estimated cleanup costs totaled
approximately $4.0 million. BCC's portion of the cleanup costs,
based on the amount of oil delivered to the site, was estimated
to be approximately 4.63 percent ($185,200).  This estimate is
likely to be high since the cleanup is substantially complete,
with the exception of ground water monitoring.  To date, BCC has
expended $84,700 in cleanup costs and continues to carry $42,750
as an unfunded liability as of December 31, 1996. IERCo is
responsible for one-third of BCC's share of the cleanup costs.
     
          Clean Air -
Idaho Power has analyzed the Clean Air Act's effects on the
Company and its rate payers.  The Company's coal-fired plants in
Oregon and Nevada already meet the federal emission rate
standards for sulfur dioxide (SO2) and Idaho Power's coal-fired
plant in Wyoming meets that state's even more stringent SO2
regulations.  Therefore, the Company foresees no adverse effects
on its operations with regard to SO2 emissions.

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

          Electric and Magnetic Fields -
While scientific research has not established any conclusive link
between electric and magnetic fields (EMFs) and human health, the
possibility of a link has caused public concern in the United
States and abroad.  Electric and magnetic fields exist wherever
there is electric current, whether the source is a high-voltage
transmission line or the simplest of electrical household
appliances.  Concerns over possible health effects have prompted
regulatory efforts in several states to limit human exposure to
EMFs. Depending on what researchers ultimately discover and any
necessary regulations, it is possible that this issue could
affect a number of industries, including electric utilities.
However, it is difficult at this time to estimate what effects,
if any, the EMF issue could have on the Company and its
operations.

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

The Company believes the first meaningful step to a competitive
retail energy market is the functional unbundling of costs into
the various delivery and energy components.  The Company believes
that the unbundling of costs will create a real means for our
customers to compare energy prices and that cost unbundling will
facilitate the establishment of more accurate price signals for
service components. The Company is prepared to bring forward cost
unbundling filings in its regulatory jurisdictions in the first
half of 1997.  The Company expects that state regulators may
require formal hearings on the cost unbundling issue.

The Company further believes that the future of the electric
utility industry will be characterized by the right of customers
to choose their own electric service provider.  To remain
successful, Idaho Power must continue to provide value to its
shareholders in the face of this new competitive environment.
The Company's vision involves three strategies for creating this
value:  selective and efficient use of capital; an enhanced
customer orientation; and innovative, efficient operations.
Because future prices for power will be determined more by market
forces and less by regulatory administration, the Company must be
very selective and efficient in the use and allocation of
capital. Idaho Power will invest in improving and expanding its
core business, in developing new opportunities beyond its current
service territory, and in continuing to develop non-regulated
opportunities consistent with the Company's core competencies.
Based on this vision and the Company's efforts to increase
shareholder and customer value, Idaho Power is transforming its
operations to improve both efficiency and customer service.
Teams of employees are redesigning work processes.  In some
cases, these improved processes are successfully in place.
During 1995, Idaho Power announced plans for voluntary and
involuntary separation packages in the event of workforce
reductions resulting from its reorganization efforts.  The
packages included compensation based on years of service and
address medical benefits and transition services.

     FERC Decisions -
On April 24, 1996, the FERC issued its Order Nos. 888 and 889
dealing with Open-Access Non-Discriminatory Transmission Services
by Public and Transmitting Utilities, and standards of conduct
regarding these issues.  These orders require public utilities
owning transmission lines to file open-access tariffs available
to buyers and sellers of wholesale electricity; to require
utilities to use the tariffs for their own wholesale sales; and
to allow utilities to recover stranded costs, subject to certain
conditions.  Public utilities owning transmission lines were
required to file compliance tariffs by July 9, 1996.

Idaho Power has long had an informal open-access transmission
policy, and is experienced in providing reliable, high-quality,
economical transmission service.  The Company provides various
firm and non-firm wheeling services for several surrounding
utilities.  In November of 1995, the Company filed open-access
tariffs with the FERC for Point-to-Point and Network transmission
service.  The substance of these tariffs was to offer the same
quality and character of transmission services that the Company
uses in its own operations to anyone seeking them.  The Company
requested and received permission to implement these tariffs
beginning February 1, 1996.  On July 8, 1996, the Company filed a
new open-access transmission tariff to replace the 1995 tariffs.
This provides full compliance with Final Order No. 888.  This new
filing did not include a rate change.  On November 13, 1996, FERC
issued an unconditional acceptance of the terms and conditions of
this tariff.  The rate was not subject to review.
     
     Independent Grid Operator -
A group of seven investor-owned Northwest electric companies,
including Idaho Power, BPA, and three public electric entities
have signed a memorandum of understanding that will create an
independent transmission grid operator called "IndeGO".  It will
ensure non-discriminatory, open-access to electricity
transmission facilities in compliance with recent FERC rulings.
This memorandum of understanding is an agreement to investigate
the feasibility of developing a regional transmission grid which
would be operated by an entity independent of power market
interests.  It is believed that the formation of such an entity
will facilitate the operation of an evolving competitive electric
power market.  Operating as one regional system, the utilities
will be able to increase the efficiency of transmission
operations and provide improved access for all system users.

IndeGo is envisioned as an independent transmission company not
controlled by any individual power market participant(s).  It is
anticipated that IndeGO will operate as a single control area,
with pricing based on a single zonal tariff applied equally to
all users including the participating companies.

IndeGO will not own transmission facilities at the onset, but
will be responsible for the operation of main transmission grid
facilities 230 kilovolts (kV) or more that are owned by the
participating utilities.  The area encompassed by the IndeGo has
over 20,000 miles of transmission lines accounting for about 97%
of the northwest grid.

The group plans to file the IndeGo proposal with FERC by July
1997, and anticipates operation would commence as early as 1999.
If the FERC's approval arrives by April of 1998, an IndeGo Board
and Site Procurement could be expected by July of 1998.
     
     Marketing Business Unit -
To accommodate its customers and allow itself to compete in the
rapidly evolving competitive market, the Company has formed a
Marketing Business Unit, effective January 1997.  This new
business unit will be responsible for all purchases and sales of
electric energy, market research and the planning and
implementation of marketing strategies.

To assist the Marketing Business Unit in bringing value to the
Company, the Board of Directors gave approval for executive
management to form a Risk Management Committee, comprised of
executives and senior managers, to oversee a new risk management
program.  The program is intended to minimize fluctuations in
earnings and cash flow while controlling the volatility of the
Company's energy prices to its customers.  The objectives of the
program include setting and achieving commodity price targets,
locking in commodity prices related to specific contracts for the
sale of electricity, and managing commodity price risk for
customers.
     
     IPUC Workshops Regarding Industry Changes -
In August 1996, the IPUC completed its investigation into changes
in the electric utility industry and issued Order No. 26555.  The
IPUC commended the working group for its effort and for the
development of a position paper (an attachment to the order) on
the changes affecting the electric utility industry.  The
position paper was the product of a series of workshops
concerning the electric utility industry restructuring and its
impact on the state of Idaho.  Participants included
commissioners and commission staff, electric utility customers
and customer group representatives, publicly-and investor-owned
utilities, and public interest groups.  The position paper set
forth regulatory and legal issues that might arise during a
transition to a more competitive environment.  The IPUC addressed
the issues individually in Order No. 26555.  In its order, the
IPUC described a cautious forward approach, noting that customers
of Idaho regulated utilities pay some of the lowest rates in the
nation and that low cost hydroelectricity is an existing benefit
of Idaho retail customers.  The IPUC stated its expectation that
many of the specific restructuring issues would be resolved in a
case-by-case manner.

     Relicensing of Hydroelectric Projects -
Idaho Power is actively pursuing the relicensing of its
hydroelectric projects, a process that will continue for the next
10 to 15 years.  The Company submitted its first applications for
license renewal to the FERC in December 1995.  These first
applications seek renewal of the Company's licenses for its
Bliss, Upper Salmon Falls, and Lower Salmon Falls Hydroelectric
Projects.  Although various federal requirements and issues must
be resolved through the license renewing process, the Company
anticipates that its efforts will be successful.  At this point,
however, the Company cannot predict what type of environmental or
operational requirements it may face, nor can it estimate the
eventual cost of license renewal.


ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA


INDEX TO FINANCIAL STATEMENT
AND FINANCIAL STATEMENT SCHEDULE


                                                            PAGE

Management's Responsibility for Financial Statements         41

Consolidated Financial Statements:

     Consolidated Balance Sheets as of December 31, 1996,
       1995 and 1994                                           42-43

     Consolidated Statements of Income for the Years
       Ended December 31, 1996, 1995 and 1994                    44

     Consolidated Statements of Retained Earnings for the Years
       Ended December 31, 1996, 1995 and 1994                    45

     Consolidated Statements of Capitalization as of

       December 31, 1996, 1995 and 1994                          46

     Consolidated Statements of Cash Flows for the Years
       Ended December 31, 1996, 1995 and 1994                    47

     Notes to Consolidated Financial Statements                48-60

Independent Auditors' Report                                     61

Supplemental Financial Information (Unaudited)                   62

Supplemental Schedule for the Years Ended December 31, 
     1996, 1995 and 1994:

     Schedule II-  Consolidated Valuation and
                   Qualifying Accounts                           69



MANAGEMENT'S RESPONSIBILITY FOR FINANCIAL STATEMENTS

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

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

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

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



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


IDAHO POWER COMPANY
CONSOLIDATED BALANCE SHEETS
ASSETS

                                                    December 31,        
                                            1996        1995       1994  
                                               (Thousands of Dollars)   
                                                               
ELECTRIC PLANT:                                                  
   In service (at original cost)         $2,537,565  $2,481,830  $2,383,898 
   Accumulated provision for depreciation  (886,885)   (830,615)   (775,033)
     In service - Net                     1,650,680   1,651,215   1,608,865 
   Construction work in progress             42,178      20,564      46,628 
   Held for future use                        1,773       1,106       1,150 
   
      Electric plant - Net                1,694,631   1,672,885   1,656,643 
                                                               
INVESTMENTS AND OTHER PROPERTY               36,502      16,826      18,034 
                                                               
CURRENT ASSETS:                                                
   Cash and cash equivalents                  7,928       8,468       7,748 
   Receivables:                                                
    Customer                                 34,962      33,357      31,889
     Allowance for uncollectible accounts    (1,394)     (1,397)     (1,377)
     Notes                                    5,104       5,134       4,962 
     Employee notes receivable                4,486       4,648       5,444 
     Other                                    8,489      10,771       4,316 
   Accrued unbilled revenues                 27,709      25,025      29,115 
   Materials and supplies (at average cost)  24,639      25,937      24,141 
   Fuel stock (at average cost)              11,631      13,063      11,310 
   Prepayments                               16,165      20,778      21,398 
   Regulatory assets associated                
    with income taxes                         4,397       5,777       5,674
                                                               
      Total current assets                  144,116     151,561     144,620
                                                               
DEFERRED DEBITS:                                               
   American Falls and Milner water rights    32,260      32,440      32,605 
   Company-owned life insurance              57,291      56,066      49,510 
   Regulatory assets associated              
    with income taxes                       196,696     200,379     179,311
   Regulatory assets - other                 89,507      68,348      67,713 
   Other                                     44,334      43,248      43,380 
                                                               
      Total deferred debits                 420,088     400,481     372,519 
                                                               
      TOTAL                              $2,295,337  $2,241,753  $2,191,816

The accompanying notes are an integral part of these statements.



IDAHO POWER COMPANY
CONSOLIDATED BALANCE SHEETS
CAPITALIZATION AND LIABILITIES

                                                   December 31,       
                                          1996        1995        1994 
                                            (Thousands of Dollars)
CAPITALIZATION:                                                    
   Common stock equity:                                         
     Common stock - $2.50 par value                                     
      (shares authorized 50,000,000   
       shares outstanding-37,612,351) $   94,031  $   94,031  $   94,031
     Premium on capital stock            362,297     363,044     363,063 
     Capital stock expense                (3,842)     (4,127)     (4,132)
     Retained earnings                   242,088     229,827     220,838 
                                                                
      Total common stock equity          694,574     682,775     673,800 
   Preferred stock                       106,975     132,181     132,456 
   Long-term debt                        738,550     672,618     693,206 
                                                                
      Total capitalization             1,540,099   1,487,574   1,499,462 
                                                                
CURRENT LIABILITIES:                                            
   Long-term debt due within one year         71      20,517         517 
   Notes payable                          54,016      53,020      55,000 
   Accounts payable                       36,370      40,483      32,063 
   Taxes accrued                          17,304      15,409      16,394 
   Interest accrued                       15,886      14,785      14,755 
   Deferred income taxes                   4,397       5,777       5,674 
   Other                                  12,439      12,867      12,574 
                                                                
      Total current liabilities          140,483     162,858     136,977 
                                          
DEFERRED CREDITS:                                               
 Regulatory liabilities associated                               
  with deferred investment tax credits    71,283      70,507      71,593
Deferred income taxes                    411,890     408,394     375,252
   Regulatory liabilities             
    associated with income taxes          35,028      34,554      35,090
   Regulatory liabilities - other            616         789         626 
   Other                                  95,938      77,077      72,816 
                                                                
      Total deferred credits             614,755     591,321     555,377
                                                                
COMMITMENTS AND CONTINGENT                                      
  LIABILITIES (Note 8)                                
                                                                
      TOTAL                           $2,295,337  $2,241,753  $2,191,816

The accompanying notes are an integral part of these statements.




IDAHO POWER COMPANY
CONSOLIDATED STATEMENTS OF INCOME

                                           Year Ended December 31,   
                                     1996           1995           1994 
                                            (Thousands of Dollars)   
                                                                
REVENUES                           $578,445       $545,621       $543,658 

EXPENSES:                                                       
   Operation:                                                   
     Purchased power                 69,038         54,586         60,216 
     Fuel expense                    63,334         54,691         94,888 
     Power cost adjustment           (6,859)         7,292        (12,076)
     Other                          132,667        126,714        123,328 
     Maintenance                     42,731         35,953         43,490 
     Depreciation                    69,705         67,415         60,202 
     Taxes other than income taxes   20,658         22,979         23,945 
     Total expenses                 391,274        369,630        393,993 

INCOME FROM OPERATIONS              187,171        175,991        149,665 

OTHER INCOME:                                                   
   Allowance for equity funds used      
    during construction                  46            (16)         1,680
   Other - Net                       12,488         14,372         10,480
      Total other income             12,534         14,356         12,160 
                                                                
INTEREST CHARGES:                                               
   Interest on long-term debt        52,165         51,147         51,172 
   Other interest                     5,183          5,309          3,261 
      Total interest charges         57,348         56,456         54,433 
   Allowance for borrowed funds                                 
    used during construction           (353)        (1,442)        (1,781)
      Net interest charges           56,995         55,014         52,652 
                                                                
INCOME BEFORE INCOME TAXES          142,710        135,333        109,173 
                                                                
INCOME TAXES                         52,092         48,412         34,243 
                                                                
NET INCOME                           90,618         86,921         74,930 
   Dividends on preferred stock       7,463          7,991          7,398 
                                                                
EARNINGS ON COMMON STOCK            $83,155        $78,930        $67,532 
                                                                
AVERAGE COMMON SHARES                                           
   OUTSTANDING (000)                 37,612         37,612         37,499

EARNINGS PER SHARE OF                                             
   COMMON STOCK                     $  2.21        $  2.10        $  1.80

The accompanying notes are an integral part of these statements.



IDAHO POWER COMPANY
CONSOLIDATED STATEMENTS OF RETAINED EARNINGS

                                    Year Ended December 31,   
                                   1996       1995       1994 
                                     (Thousands of Dollars)   
                                                                
RETAINED EARNINGS                                                
  Beginning of year              $229,827   $220,838   $222,900
                                                                
NET INCOME                         90,618     86,921     74,930
                                                                
   Total                          320,445    307,759    297,830 
                                                                
DIVIDENDS:                                                      
   Preferred stock                  7,463      7,991      7,398 
   Common stock (per share:
    1996 - 1994 - $1.86            69,924     69,941     69,594 

      Total dividends              77,387     77,932     76,992 
                                                                
PREFERRED STOCK REDEMPTION           970         -          -   
                                                                
RETAINED EARNINGS                                               
   End of year                   $242,088   $229,827   $220,838

The accompanying notes are an integral part of these statements.


IDAHO POWER COMPANY
CONSOLIDATED STATEMENTS OF CAPITALIZATION
                                                  December 31,
                                      1996    %      1995    %      1994    %
                                             (Thousands of Dollars)
COMMON STOCK EQUITY:                                                   
   Common stock                   $   94,031     $   94,031     $   94,031     
   Premium on capital stock          362,297        363,044        363,063     
   Capital stock expense              (3,842)        (4,127)        (4,132)   
   Retained earnings                 242,088        229,827        220,838     
      Total common stock equity      694,574  45    682,775   46   673,800  45
                                                                  
PREFERRED STOCK:                                                   
   4% preferred stock                 16,975         17,181         17,456     
   7.68% Series, serial               
    preferred stock                   15,000         15,000         15,000   
   8.375% Series, serial                
    preferred stock                     -            25,000         25,000     
   7.07% Series, serial       
    preferred stock                   25,000         25,000         25,000     
   Auction rate preferred stock       50,000         50,000         50,000     
      Total preferred stock          106,975   7    132,181    9   132,456   9
                                                 
   First mortgage bonds:                                          
     5 1/4 % Series due 1996            -             20,000         20,000
     5.33  % Series due 1998          30,000          30,000         30,000     
     8.65  % Series due 2000          80,000          80,000         80,000     
     6.93  % Series due 2001          30,000            -              -     
     6.85  % Series due 2002          27,000            -              -   
     6.40  % Series due 2003          80,000          80,000         80,000     
     8     % Series due 2004          50,000          50,000         50,000    
     9.50  % Series due 2021          75,000          75,000         75,000     
     7.50  % Series due 2023          80,000          80,000         80,000     
     8 3/4 % Series due 2027          50,000          50,000         50,000     
     9.52  % Series due 2031          25,000          25,000         25,000    
       Total first mortgage bonds    527,000         490,000        490,000     
   Amount due within one year           -            (20,000)          -       
      Net first mortgage bonds       527,000         470,000        490,000     
   Pollution control revenue bonds:
     5.90  % Series due 2003            -             24,200         24,650     
     6.0   % Series due 2007            -             24,000         24,000     
     7 1/4 % Series due 2008           4,360           4,360          4,360     
     7 5/8 % Series 1083-1984 
       due 2013-2014                    -             68,100         68,100     
     8.30  % Series 1984 due 2014     49,800          49,800         49,800    
     6.05  % Series 1996A due 2026    68,100            -              -     
     Variable rate Series      
       1996B due 2026                 24,200            -              -     
     Variable rate Series     
       1996C due 2026                 24,000            -              -     
      Total pollution control 
       revenue bonds                 170,460         170,460        170,910     
   Amount due within one year           -               (450)          (450)   
      Net pollution control    
       revenue bonds                 170,460         170,010        170,460     
   REA notes                           1,632           1,700          1,768     
   Amount due within one year            (71)            (67)           (67)   
   Net REA notes                       1,561           1,633          1,701     
   Subsidiary debt                     9,000            -               -    
   American Falls bond guarantee      20,560          20,740         20,905     
   Milner Dam note guarantee          11,700          11,700         11,700     
   Unamortized premium/discount-Net   (1,731)         (1,465)        (1,560)   
      Total long-term debt           738,550  48     672,618  45    693,206 46
                                                                   
TOTAL CAPITALIZATION              $1,540,099 100  $1,487,574 100 $1,499,462 100

The accompanying notes are an integral part of these statements.
                                


IDAHO POWER COMPANY
CONSOLIDATED STATEMENTS OF CASH FLOWS

                                       Year Ended December 31,  
                                    1996        1995         1994 
                                       (Thousands of Dollars) 
OPERATING ACTIVITIES:                                         
   Cash received from operations:                             
     Retail revenues               $490,504    $468,821     $457,202 
     Wholesale revenues              66,551      59,260       62,110 
     Other revenues                  24,469      22,825       23,711 
   Fuel paid                        (59,798)    (61,741)     (94,530)
   Purchased power paid             (70,302)    (52,526)     (62,592)
   Other operation & maintenance   (177,055)   (154,209)    (171,774)
   Interest paid (include long and  
    short-term debt only)           (53,273)    (54,303)     (52,376)
   Income taxes paid                (45,050)    (40,402)     (16,518)
   Taxes other than income taxes   
    paid                            (23,455)    (22,939)     (21,698)
   Other operating cash receipts   
    and payments-Net                 21,824       3,634        2,122 
       Net cash provided by         174,415     168,420      125,657
                                                              
FINANCING ACTIVITIES:                                         
   First mortgage bonds issued       57,000        -            -  
   PC bond fund requisitions/other 
    long-term debt                  128,534        -            -  
   Common stock issued                 -           -          13,402 
   Short-term borrowings-Net          1,000      (2,000)      51,000 
   Long-term debt retirement       (140,069)       (519)        (466)
   Preferred stock retirement       (26,530)       (151)        (166)
   Dividends on preferred stock      (7,850)     (7,888)      (7,565)
   Dividends on common stock        (69,923)    (69,967)     (69,594)
   Other sources/uses                (4,144)       (781)        -  
       Net cash - financing        
        activities                  (61,982)    (81,306)     (13,389)
                                                              
INVESTING ACTIVITIES:                                         
   Additions to utility plant       (93,645)    (83,965)    (110,523)
   Conservation                      (3,839)     (5,688)      (6,830)
   Increase in investments          (20,153)       -            -  
   Other                              4,664       3,259        4,605 
       Net cash - investing        
        activities                 (112,973)    (86,394)    (112,748)
   Change in cash and cash         
    equivalents                        (540)        720         (480)
   Cash and cash equivalents       
    beginning of year                 8,468       7,748        8,228 
       Cash and cash equivalents
        end of year                   7,928       8,468        7,748
                                                              
RECONCILIATION OF NET INCOME TO NET                           
CASH PROVIDED BY OPERATING
ACTIVITIES:
   Net income                     $ 90,618     $ 86,921     $ 74,930 
   Adjustments to reconcile net                               
    income to net cash:
     Depreciation                   69,705       67,415       60,202 
     Deferred income taxes           7,201       11,698       14,265 
     Investment tax credit - Net       776       (1,086)      (1,064)
     Allowance for funds used      
      during construction             (399)      (1,425)      (3,461)
     Postretirement benefits funding      
      (excl pensions)                1,340       (2,857)      (5,182)
     Changes in operating assets                              
       and liabilities:
      Accounts receivable            3,079        5,285         (635)
      Fuel inventory                 3,535       (7,050)         358 
      Accounts payable              (1,264)       2,061       (2,376)
      Taxes payable                 (3,696)      (2,519)       7,296 
      Interest payable               3,870        2,100        1,656 
     Other - Net                      (350)       7,877      (20,332)
      Net cash provided by          
       operating activities       $174,415     $168,420     $125,657 

The accompanying notes are an integral part of these statements.



IDAHO POWER COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

1.  SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
PRINCIPLES OF CONSOLIDATION - The consolidated financial
statements include the accounts of the Company and its six wholly-
owned subsidiaries, Idaho Energy Resources Co. (IERCo), Ida-West
Energy Company (Ida-West), IDACORP, Inc., Idaho Utility Products
Company (IUPCo), Stellar Dynamics, Inc. (Stellar), and Idaho
Power Resources Corporation (IPRC).  All significant intercompany
transactions and balances have been eliminated in consolidation.
Investments in business entities in which the Company and its
subsidiaries do not have control, but has the ability to exercise
significant influence over operating and financial policies, are
accounted for using the equity method.

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

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

ALLOWANCE FOR FUNDS USED DURING CONSTRUCTION (AFDC) - The
allowance, a non-cash item, represents the composite interest
costs of debt, shown as a reduction to interest charges, and a
return on equity funds, shown as an addition to other income,
used to finance construction. While cash is not realized
currently from such allowance, it is realized under the rate
making process over the service life of the related property
through increased revenues resulting from higher rate base and
higher depreciation expense. Based on the uniform formula adopted
by the FERC, the Company's weighted average monthly AFDC rates
for 1996, 1995 and 1994 were 6.1 percent, 6.1 percent and 8.2
percent, respectively.

REVENUES - In order to match revenues with associated expenses,
the Company accrues unbilled revenues for electric services
delivered to customers but not yet billed at month-end.

In 1996, under terms and conditions of the Regulatory Settlement
with the Idaho Public Utilities Commission (IPUC) , the Company
set aside approximately $4.9 million of revenues for the benefit
of its Idaho customers.  Under the Settlement, when the Company's
actual earnings in a given year exceeds an 11.75 percent return
on year-end common equity, the Company will refund 50 percent of
the excess.

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

DEPRECIATION - All electric plant is depreciated using the
straight-line method. Annual depreciation provisions as a percent
of average depreciable electric plant in service approximated
2.89 percent in 1996, 2.90 percent in 1995 and 2.93 percent in
1994 and are considered adequate to amortize the original cost
over the estimated service lives of the properties.

INCOME TAXES - The Company follows the liability method of
computing deferred taxes on all temporary differences between
book and tax basis of assets and liabilities and adjusts deferred
tax assets and liabilities for enacted changes in tax laws or
rates. Consistent with orders and directives of the IPUC the
regulatory authority having principal jurisdiction, deferred
income taxes (commonly referred to as normalized accounting) are
provided for the difference between income tax depreciation and
straight-line depreciation on coal-fired generation facilities
and properties acquired after 1980. On other facilities, deferred
income taxes are provided for the difference between accelerated
income tax depreciation and straight-line depreciation using tax
guideline lives on assets acquired prior to 1981. Deferred income
taxes are not provided for those income tax timing differences
where the prescribed regulatory accounting methods do not provide
for current recovery in rates. Regulated enterprises are required
to recognize such adjustments as regulatory assets or liabilities
if it is probable that such amounts will be recovered from or
returned to customers in future rates (see Note 2).

The state of Idaho allows a three percent investment tax credit
(ITC) upon certain qualifying plant additions. ITC earned on
regulated assets are deferred and amortized to income over the
estimated service lives of the related properties. Credits earned
on non-regulated assets or investments are recognized in the year
earned.

In 1995, the Company received an accounting order from the IPUC
approving acceleration of amortization of up to $30.0 million of
regulatory liabilities associated with deferred ITC to non-
operating income.  The Internal Revenue Service and the Idaho
State Tax Commission have both approved the application.
Acceleration of ITC amortization is to be utilized until the
actual return on year-end common equity is 11.5 percent. No
accelerated ITC was recognized in 1995 or 1996.

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

MANAGEMENT ESTIMATES - The preparation of financial statements,
in conformity with generally accepted accounting principles,
requires management to make estimates and assumptions that affect
the reported amounts of assets and liabilities and the disclosure
of contingent assets and liabilities at the date of the financial
statements and the reported amounts of revenues and expenses
during the reporting period.  Actual results could differ from
those estimates.

REGULATION OF UTILITY OPERATIONS - Electric utilities have
historically been recognized as natural monopolies and have
operated in a highly regulated environment in which they have an
obligation to provide electric service to their customers in
return for an exclusive franchise within their service territory
with an opportunity to earn a regulated rate of return.  This
regulatory environment is changing.  The generation sector has
experienced competition from non-utility power producers, and the
FERC is requiring utilities, including the Company, to provide
wholesale open-access transmission service to others and may
order electric utilities to enlarge their transmission systems to
facilitate transmission services.

Some state regulatory authorities are in the process of changing
utility regulations in response to federal and state statutory
changes and evolving competitive markets.  The Company believes
that these statutory and conforming regulations may result in
increased wholesale competition.  However, due to the company's
low cost structure, increased wholesale competition is not
expected to adversely affect it in the near term and may
favorably impact it in the long term.  The Company is unable to
predict what financial impact or effect the adoption of any such
legislation would have on its operations.

The Company follows Statement of Financial Accounting Standards
(SFAS) No. 71, "Accounting for the Effects of Certain Types of
Regulation", and its financial statements reflect the effects of
the different rate making principles followed by the various
jurisdictions regulating the Company. Pursuant to SFAS No. 71 the
Company capitalizes, as deferred regulatory assets, incurred
costs which are expected to be recovered in future utility rates.
The Company also records as deferred regulatory liabilities the
current recovery in utility rates of costs which are expected to
be paid in the future.

The following is a breakdown of regulatory assets and liabilities
for the years 1996, 1995 and 1994:

                               1996             1995             1994
                          Assets   Liab.   Assets   Liab.   Assets   Liab.
                                        (Millions of Dollars)
Income taxes              $201.1   $35.0   $206.2   $ 34.6  $185.0   $35.1
Conservation                40.3             36.3             29.7        
Employee benefits            7.4              8.3              9.5        
PCA deferral and 
amortizatioin                9.6              2.1              9.1        
Other                       32.2     0.6     21.6      0.7    19.4     0.6
Accumulated deferred                
  Investment tax credits            71.3              70.5            71.6 
Total                     $290.6  $106.9   $274.5   $105.8  $252.7  $107.3

At December 31, 1996, the Company had $22.6 million of regulatory
assets that were not earning a return on investment excluding the
$201.1 million that relates to income taxes.

In the event that recovery of cost through rates becomes unlikely
or uncertain, SFAS No. 71 would no longer apply. If the Company
were to discontinue application of SFAS No. 71 for some or all of
its operations, then these items may represent stranded
investments. Certain regulators are currently reviewing ways to
allow the electric utilities to recover these investments in the
event the customers are allowed to choose their energy supplier.
However, if the Company is not allowed recovery of these
investments, it would be required to write off the applicable
portion of regulatory assets and the financial effects could be
significant.

DERIVATIVES - The Company has a policy which allows for the use
of financial instruments such as commodity futures, options and
swaps as a means of hedging against the risks associated with
price fluctuations in the electricity market.  At December 31,
1996, the Company's hedging transactions did not have a material
effect on its financial statements.

OTHER ACCOUNTING POLICIES - Debt discount, expense and premium
are being amortized over the terms of the respective debt issues.

RECLASSIFICATIONS - Certain items previously reported for years
prior to 1996 have been reclassified to conform with the current
year' s presentation. Net income was not affected by these
reclassifications.

2.  INCOME TAXES:
A reconciliation between the statutory    
federal income tax                      1996       1995       1994
rate and the effective rate is as         
follows:                                  (Thousands of Dollars)
   Computed income taxes based on                             
statutory federal income tax rate       $ 49,949   $ 47,367   $ 38,210
   Change in taxes resulting from:                            
     AFDC                                   (140)      (504)    (1,211)
     Investment tax credits               (2,835)    (2,837)    (3,351)
     Repair allowance                     (2,800)    (3,150)    (1,575)
     Elimination of amounts provided 
      in prior years                         (16)    (1,963)    (2,607)
     Current state income taxes            2,823      3,275      1,496 
     Depreciation                          5,945      5,493      2,812 
     Affordable housing tax credits       (1,777)       -          -   
     Other                                   943        731        469 
   Total provision for federal and          
     state income taxes                 $ 52,092   $ 48,412   $ 34,243
   Effective tax rate                       36.5%      35.8%      31.4%
The provision for income taxes                                
consists of the following:
   Income taxes currently payable:                            
     Federal                            $40,379    $33,456    $19,617 
     State                                3,746      4,503      1,425
      Total                              44,125     37,959     21,042 
   Income taxes deferred - Net of                             
     amortization:
     Federal                              6,877     10,904     12,595
     State                                  314        635      1,670 
      Total                               7,191     11,539     14,265
   Investment and other tax credits:                          
     Deferred                             3,611      1,751      1,643 
     Restored                            (2,835)    (2,837)    (2,707)
      Total                                 776     (1,086)    (1,064)
   Total provision for income taxes    $ 52,092   $ 48,412   $ 34,243
The tax effects of significant items                          
  comprising the Company's net deferred 
  tax liability are as follows:
   Deferred tax assets:                                     
     Regulatory liability              $ 35,028   $ 34,554   $ 35,090
     Advances for construction           17,736     14,823     10,542
     Other                               13,550     10,498      6,387 
      Total                              66,314     59,875     52,019 
   Deferred tax liabilities:                                  
     Property, plant and equipment      245,652    237,655    225,444
     Regulatory asset                   201,093    206,156    184,985 
     Investment tax credit               71,283     70,507     71,593 
     Conservation programs               13,720     11,746      4,704 
     Other                               22,136     18,489     17,812 
      Total                             553,884    544,553    504,538 
   Net deferred tax liabilities        $487,570   $484,678   $452,519

The Company has settled Federal and Idaho tax liabilities on all
open years through the 1992 tax year except for amounts related
to a partnership which, in management's opinion, have been
adequately accrued.

3.  COMMON STOCK:
Changes in shares of the common stock of the Company for 1996,
1995 and 1994 were as follows:
                                                               
                                     Common Stock              
                                                             Premium on
                                                  $2.50      Capital
                                   Shares        Par Value   Stock
                                                 (Thousands of Dollars)
                                                                
Balance at December 31, 1993       37,085,055    $92,713     $350,882
  Gain on reacquired 4%       
   preferred stock                     -            -             126    
  Stock purchase plans                527,296      1,318       12,055 
Balance at December 31, 1994       37,612,351     94,031      363,063 
  Gain on reacquired 4%           
   preferred stock                     -            -             117
  Restricted stock plans               -            -            (136)  
Balance at December 31, 1995       37,612,351     94,031      363,044
  Gain on reacquired 4%         
   preferred stock                     -            -              83      
  Restricted stock plans               -            -            (102)
  Preferred stock redemption           -            -            (728)
Balance at December 31, 1996       37,612,351    $94,031     $362,297 

During the period of January 1994 through May 1994, the Company
issued 527,296 original issue shares of common stock for its
Dividend Reinvestment and Stock Purchase Plan and the Employee
Savings Plan.

As of December 31, 1996, the Company had 2,791,321 of its
authorized but unissued shares of common stock reserved for
future issuance under its Dividend Reinvestment and Stock
Purchase Plan and Employee Savings Plan.

The Company has a Shareowner Rights Plan (Plan) designed to
ensure that all shareholders receive fair and equal treatment in
the event of any proposal to acquire control of the Company.
Under the Plan, the Company declared a distribution of one
Preferred Stock Right (Right) for each of the Company's
outstanding Common shares held on January 29, 1990 or issued
thereafter. The Rights are currently not exercisable and will be
exercisable only if a person or group (Acquiring Person) either
acquires ownership of 20 percent or more of the Company's Voting
Stock or commences a tender offer that would result in ownership
of 20 percent or more. The Company may redeem the Rights at a
price of $0.01 per Right anytime prior to acquisition by an
Acquiring Person of a 20 percent position.

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

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

4.  PREFERRED STOCK:
The number of shares of preferred stock outstanding at December
31, 1996, 1995 and 1994 were as follows:
                                   Shares Outstanding at       Call Price
                                     December 31,
                                  1996      1995      1994      Per Share
Preferred stock:                                             
 Cumulative, $100 par value:                                 
                                                             
  4% preferred stock                                         
   (authorized 215,000 shares)    169,753   171,813   174,556   $104.00
                                                             
  Serial preferred stock, 7.68% 
    Series (authorized
    150,000 shares)               150,000   150,000   150,000   $102.97
                                                             
 Serial preferred stock, 
   cumulative, without
   par value; total of
   3,000,000 shares authorized:
                                                             
  8.375% Series, $100 stated value                  
   (authorized 250,000 shares)       -      250,000   250,000

  7.07% Series, $100 stated                                  
   value, authorized 250,000  
    shares)(a)                    250,000   250,000   250,000   $103.535 to 
                                                                  $100.354
                                                             
  Auction rate preferred                                     
   stock, $100,000 stated  
   value, (authorized 500
   shares)(b)                         500       500       500   $100,000.00
                                                             
   Total                          570,253   822,313   825,056          

(a)   The preferred stock is not redeemable prior to July 1, 2003.
(b)   Dividend rate at December 31, 1996 was 4.05% and ranged
      between 4.00% and 4.31% during the year.

During 1996, 1995 and 1994 the Company reacquired and retired
2,060; 2,743; and 2,950 shares of 4% preferred stock resulting in
a net addition to premium on capital stock of $82,900, $117,346,
and $126,066 respectively. As of December 31, 1996 the overall
effective cost of all outstanding preferred stock was 5.54
percent.

On November 7, 1996, the Company redeemed the $25,000,000
principal amount of 8.375% Series, serial preferred stock with
par value, ($100 stated value) from proceeds of the issuance of
$27,000,000 principal amount of secured medium term notes, Series
B, 6.85%, Due 2002.  The total cost was $26,395,000 which
includes a premium of $1,395,000.  The redemption premium plus
the initial issuance expense of $303,547, was charged $728,541 to
premium on capital stock and $970,006 to retained earnings.


5.  LONG-TERM DEBT:
The amount of first mortgage bonds issuable by the Company is
limited to a maximum of $900,000,000 and by property, earnings
and other provisions of the mortgage and supplemental indentures
thereto. Substantially all of the electric utility plant is
subject to the lien of the indenture.

Pollution Control Revenue Bonds, Series 1984, due December 1,
2014, are secured by First Mortgage Bonds, Pollution Control
Series A, which were issued by the Company and are held by a
Trustee for the benefit of the bondholders.

First mortgage bonds maturing during the five-year period ending
2001 are $30,000,000 in 1998, $80,000,000 in 2000 and $30,000,000
in 2001.  On July 29, 1996, the Company issued $30,000,000
principal amount of Secured Medium Term Notes, Series B, 6.93%
Series Due 2001.  The net proceeds were used for repayment of
commercial paper issued in connection with the Company's ongoing
construction program.  On October 2, 1996, $27,000,000 principal
amount of Secured Medium Term Notes, Series B, 6.85% Due 2002
were issued with net proceeds from this sale used to redeem the
Company's 250,000 shares of 8.375% Series, Serial Preferred
Stock, Without Par Value.

On August 29, 1996, tax exempt Pollution Control Revenue
Refunding Bonds were issued in principal amount of $68,100,000
Series 1996A, $24,200,000 Series 1996B and $24,000,000 Series
1996C.  The proceeds were used to retire the $24,200,000
Pollution Control Revenue Bonds due 2003, $24,000,000 Pollution
Control Revenue Bonds due 2007 and the $68,100,000 Pollution
Control Revenue Bonds due 2013-2014.  At December 31, 1996, 1995
and 1994, the overall effective cost of all outstanding first
mortgage bonds and pollution control revenue bonds was 7.73
percent, 8.02 percent and 8.02 percent, respectively.


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

Cash and cash equivalents, customer and other receivables, notes
payable, accounts payable, interest accrued, and taxes accrued
are reported at their carrying value as these are a reasonable
estimate of their fair value. The total estimated fair value of
long-term debt was approximately  $773,760,000 for 1996,
$731,168,000 for 1995 and $682,647,000 for 1994. The estimated
fair values for long-term debt are based upon quoted market
prices of the same or similar issues.


7.  NOTES PAYABLE:
At January 1, 1997, the Company had regulatory authority to incur
up to $200,000,000 of short-term indebtedness.  On December 19,
1996, the Company replaced its committed lines of credit
arrangements with a $120,000,000 multi-year revolving credit
facility, which will expire on December 19, 2001.  Under this
facility the Company will pay a facility fee on the commitment,
quarterly in arrears, based on the Company's First Mortgage Bond
rating.  Commercial paper may be issued in an amount not to
exceed 25 percent of revenues for the latest twelve-month period
subject to the $200,000,000 maximum described above and are
supported by bank lines of credit of an equal amount.

Balances and interest rates of short-term borrowings were as
follows:

                                        Year Ended December
                                               31,
                                      1996      1995      1994
                                      (Thousands of Dollars)
                                                               
Balance at end of year                $54,016      $53,020      $55,000 
Effective annual interest rate      
 at end of year                           5.7%         6.0%         6.1%



8.  COMMITMENTS AND CONTINGENT LIABILITIES:
Commitments under contracts and purchase orders relating to the
Company's program for construction and operation of facilities
amounted to approximately $2.2 million at December 31, 1996. The
commitments are generally revocable by the Company subject to
reimbursement of manufacturers' expenditures incurred and/or
other termination charges.

The Company is currently purchasing energy from 67 on-line
cogeneration and small power production facilities with contracts
ranging from 1 to 32 years. Under these contracts the Company is
required to purchase all of the output from these facilities.
During the fiscal year ended December 31, 1996, the Company
purchased 776,368 (MWH) at a cost of $43.7 million.

The Company is party to various legal claims, actions, and
complaints, certain of which involve material amounts. Although
the Company is unable to predict with certainty whether or not it
will ultimately be successful in these legal proceedings, or, if
not, what the impact might be, based upon the advice of legal
counsel, management presently believes that disposition of these
matters will not have a material adverse effect on the Company's
financial position, results of operation or cash flow.


9.  BENEFIT PLANS:
Incentive Plans - The Company implemented two annual incentive
plans effective January 1, 1995. The Executive Annual Incentive
Plan and the Employee Incentive Plan tie a portion of each
employee's compensation to achieving annual operational and
financial goals. The plans share common goals designed to promote
safety, control capital expenditures, control operation and
maintenance expenses and increase annual earnings per share.  For
the years 1996 and 1995 total incentive for the plans was
$2,467,334 and $2,898,785, respectively.

Restricted Stock Plan - The 1994 Restricted Stock Plan ("Plan")
approved by shareholders at the May 1994 Annual Meeting was
implemented January 1, 1995 as an equity-based long-term
incentive plan. The performance-based grant approach and
administrative guidelines for the Plan were developed by the
Compensation Committee of the Board of Directors ("Committee")
during 1994. At December 31, 1996, there were 370,000 shares of
common stock reserved for the Plan.  Grants are offered to all
officers.   The Committee has selected a three-year restricted
period for each grant.  A new grant can be offered in each
succeeding year with a single financial performance goal of
Cumulative Earnings Per Share ("CEPS"). Final award amounts will
depend on the attainment by the Company of the CEPS performance
goal established by the Committee and may be prorated in the
event of death, disability or retirement of an officer based on
the number of whole months of service the officer completes
during the Restricted Period. Upon the officer's termination of employment
during the Restricted Period for any other reason, all such
shares will be forfeited by the officer to the Trustee.
Effective January 1, 1997, certain senior managers of the Company
have become participants in the Plan.

Restricted stock awards are compensatory awards and the Company
accrues compensation expenses (which are charged to operations)
based upon the market value of the granted shares.

For the years 1996 and 1995, total compensation for the plan was
$184,153 and $91,200, respectively.

The following table shows the cumulative amount of grants offered
by the Company for the years 1996 and 1995:

Balance of shares outstanding at January 1, 1995         - 
   Granted in 1995                                   9,480 
   Forfeited in 1995                                  (360)
Balance at December 31, 1995                         9,120 
   Granted in 1996                                   9,740 
   Forfeited in 1996                                  (720)
Balance at December 31, 1996                        18,140 

At December 31, 1996, no shares were vested under the plan.

Pension Plan - The Company maintains a trusteed noncontributory
defined benefit pension plan for all employees who work 1,000
hours or more during a calendar year. The benefits under the plan
are based on years of service and the employee's final average
earnings. The Company's policy is to fund with an independent
corporate trustee at least the minimum required under the
Employee Retirement Income Security Act of 1974 but not more than
the maximum amount deductible for income tax purposes. The
Company was not required to contribute to the plan in 1996, but
funded $5.9 million in 1995 and $5.5 million in 1994. The plan's
assets held by the trustee consist primarily of listed stocks
(both U.S. and foreign), fixed income securities and investment
grade real estate.

Deferred Compensation Plan - The Company has a nonqualified,
deferred compensation plan for certain senior management
employees and directors (Security Plan) that provides for
supplemental retirement and death benefit payments to the
participant and his or her family. The plan is being financed by
life insurance policies, of which the Company is the beneficiary,
with premiums being paid by the Company. These policies have
accumulated cash values in excess of the projected benefit
obligation and do not qualify as plan assets in the actuarial
computation of the funded status. Based upon SFAS No. 87,
"Employers' Accounting for Pensions", the Company has recorded a
net liability of $21.8 million as of December 31, 1996.

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

Plan Costs for the Year            1996     1995    1994 
Pension plan:                       (Thousands of Dollars)
 Service cost                     $ 6,273    $ 5,167    $ 6,049 
 Interest cost                     13,647     12,998     12,263 
 Actual return on plan assets     (30,214)   (45,990)       312 
 Deferred gain (loss) on plan      12,230     31,489    (15,584)
  Net cost                        $ 1,936    $ 3,664    $ 3,040 
 Approximate percentage                                    
  included in operating expenses       67%        65%        67%
Net deferred compensation plan                               
 costs charged to other income 
 (including life insurance and
 SFAS No. 87 liability 
 accrual)(a)                      $   794    $    37    $   508

(a)   These charges to the Income Statement have been reduced by
      gains from the Company-owned life insurance of $1,697; $2,320
      and $2,724, for 1996, 1995 and 1994, respectively.

Funded status and significant assumptions as of December 31:

                             Pension Plan         Deferred Compensation Plan
                     1996      1995      1994      1996      1995      1994 
                                     (Thousands of Dollars)           
Actuarial present                                                       
value of benefit
obligations:
 Vested benefit     
  obligation         $155,343  $145,334  $128,162  $21,840   $21,530   $19,148
 Accumulated benefit       
  obligation          158,349   150,688   132,766   21,840    21,530    19,148
                                                                         
 Projected benefit   
  obligation         $202,049  $193,133  $167,103  $22,370   $22,111   $19,681
Plan assets at fair                    
 value                230,479   204,760   165,839      -         -         -
Plan assets in                                                           
 excess of (or less            
 than) projected
 benefit obligation    28,430    11,627   (1,264)  (22,370)  (22,111)   (19,681)
                                                                         
Unrecognized net                                                         
 (gain) loss from past
 experience different
 from that assumed    (20,995)   (8,341)   6,040     4,376     4,389      2,173
                                                                         
Unrecognized prior          
 service cost           5,517     5,941    6,365    (2,762)   (3,097)    (3,516)
                                                                         
Unrecognized net                                                         
 (asset) obligation                                              
 existing at date of 
 initial adoption 
 (19.5 years straight-
 line amortization)    (2,230)   (2,493)  (2,756)    5,214     5,827      6,440
Minimum liability    
 adjustment               -         -        -      (6,298)   (6,538)    (4,564)
Net asset (liability) 
 included in the 
 balance sheet       $ 10,722  $  6,734  $ 8,385  $(21,840) $(21,530)  $(19,148)
                                                                         
Discount rate to
 compute projected        
 benefit obligation      7.35%     7.25%     8.0%     7.35%     7.25%       8.0%
Rate for future                                                          
 compensation  
 increases                4.5       4.5      4.5       4.5       4.5        4.5
Expected long-term                                                     
 rate of return on     
 plan assets              9.0       9.0      9.0        -         -          -

Supplemental Employee Retirement Plan (SERP) - The Company has a
nonqualified SERP that provides benefits in excess of Internal
Revenue Service limits (Section 401 (a) (17) of the Internal
Revenue Code) for highly paid individuals. The projected benefit
obligation of this plan was $1,752,000, $1,581,000, and $857,000 at 
December 31, 1996, 1995 and 1994, respectively, with accrued pension 
costs of $918,000, $682,000, and $396,000. The Company's net periodic 
pension cost of this plan was $306,000, $184,000, and $125,000 for the 
same periods.  During 1996, the SERP was merged with the Security Plan.

Savings Plan - The Company has an Employee Savings Plan whereby,
for each $1 of employee contribution up to 6 percent of their
base salary the Company will match 100 percent of the first 2
percent employee contribution and 50 percent of the next 4
percent employee contribution, all such amounts to be invested by
a trustee in any or all of seven investment options. The
Company's contribution amounted to $2,285,904 in 1996, $2,426,840
in 1995, and $2,410,200 in 1994.

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

The following tables set forth the amounts recognized in the
Company's financial statements for year-end 1996, 1995 and 1994
and the funded status of the plan in accordance with SFAS No.
106, "Employers' Accounting for Postretirement Benefits other
than Pensions", as of December 31:

                                         1996        1995         1994 
Postretirement Benefit Cost:                 (Thousands of Dollars)
 Service Cost                          $    794     $    763     $    855  
 Interest Cost                            3,172        3,571        3,334 
 Actual return on plan assets            (1,410)      (1,116)      (1,114)
 Amortization of transition             
  obligation (20-year amortization)       2,040        2,040        2,040
 Net amortization and deferral              (57)          -            -   
 Regulatory assets                           -           506       (1,907)
 Voluntary severance program                 -            64           -   
  Net cost                             $  4,539     $  5,828     $  3,208 
Funded Status:                                                        
 Accumulated postretirement benefit    
obligation (APBO)                      $(44,439)    $(48,928)    $(45,001)
 Plan assets at fair value               17,341       15,920       12,116
 APBO in excess of plan assets          (27,098)     (33,008)     (32,885)
 Unrecognized gain/losses                (5,478)         378          773 
 Unrecognized transition obligation      32,640       34,680       36,720
 Prepaid postretirement benefit cost  $      64     $  2,050     $  4,608 
Discount rate                              7.50%        7.50%        8.25%
Medical and dental inflation rate          6.75         6.75         7.25   
Long-term plan assets expected return      9.0          9.0          9.0

A one percent change in the medical inflation rate would change
the APBO by 7.2 percent and the post retirement expense for 1996
by 8.6 percent.

The Company has a retiree medical benefits funding program which
consists of life insurance policies on active employees of which
the Company is the beneficiary, and a qualified Voluntary
Employees Beneficiary Association (VEBA) Trust. The net charge to
other income for the life insurance policies was $1,390,800 in
1996, $1,754,300 in 1995 and $776,400 in 1994. The funding to the
VEBA was $0 in 1996, $916,200 in 1995, and $743,600 in 1994 and
recorded as a prepayment. The VEBA trust represents plan assets
which are invested in variable life insurance policies, Trust
Owned Life Insurance (TOLI), on active employees. Inside buildup
in the TOLI policies is tax deferred and tax free if the policy
proceeds are paid to the Trust as death benefits. The investment
return assumption reflects an expectation that investment income
in the VEBA will be substantially tax free.

Post-employment Retirement Benefits - The Company provides
certain benefits to former or inactive employees, their
beneficiaries, and covered dependents after employment but before
retirement. The Company accrues for such post employment
benefits. These benefits include salary continuation and related
health care and life insurance for both long and short-term
disability plans, workmen's compensation and health care for
surviving spouse and dependent plan. The Company recognizes a
deferred asset which represents future revenue expected to be
realized at the time the post employment benefits are included in
the Company's rates. The Company has recorded a liability of $4.1
million and a regulatory asset of $3.0 million which represents
the costs associated with post employment benefits at December
31, 1996. The Company received an IPUC order authorizing the
amortization of the regulatory asset over a 10-year period.


10.  ELECTRIC PLANT IN SERVICE AND JOINTLY-OWNED PROJECTS:
The following table sets out the major classifications of the
Company's electric plant in service and accumulated provision for
depreciation for the years 1996, 1995, and 1994.

                                       1996       1995     1994  
                                       (Thousands of Dollars)   
Electric Plant in Service:                                       
   Production                         $1,323,090   $1,350,239   $1,303,572 
   Transmission                          371,123      330,812      308,055 
   Distribution                          688,232      648,549      625,149
   General and Other                     155,120      152,230      147,122 
     Total in service                  2,537,565    2,481,830    2,383,898 
     Less accumulated provision         
      for depreciation                   886,885      830,615      775,033 
     In service - Net                 $1,650,680   $1,651,215   $1,608,865 

The Company is involved in the ownership and operation of three
jointly-owned generating facilities. The Consolidated Statements
of Income include the Company's proportionate share of direct
operation and maintenance expenses applicable to the projects.

Each facility and extent of Company participation as of December
31, 1996 are as follows:

                                          Company Ownership
                                                Accumulated
                                    Electric    Provision        
Name of Plant       Location        In Service  for Depreciation   %    MW
                                       (Thousands of Dollars)
Jim Bridger      Rock Springs, WY   
 Units 1-4                          $382,135    $169,126          33    693
Boardman         Boardman, OR         60,780      28,028          10     53
Valmy Units 1    Winnemucca, NV  
 and 2                               299,156     112,523          50    261

The Company's wholly-owned subsidiary, IERCo, is a joint venturer
in Bridger Coal Company, which operates the mine supplying coal
for the Jim Bridger steam generation plant. Coal purchased by the
Company from the joint venture amounted to $34,974,000 in 1996,
$44,278,000 in 1995, and $46,097,000 in 1994.

The Company has contracts to purchase the energy from five PURPA
Qualified Facilities which are 50 percent owned by Ida-West.
Power purchased from these facilities amounted to $8,953,000 in
1996, $8,696,000 in 1995, and $7,139,000 in 1994.


INDEPENDENT AUDITORS' REPORT


Board of Directors and Shareowners of Idaho Power Company:

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

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

In our opinion, such consolidated financial statements present
fairly, in all material respects, the financial position of Idaho
Power Company and subsidiaries at December 31, 1996, 1995, and
1994, and the results of their operations and their cash flows
for the years then ended in conformity with generally accepted
accounting principles. Also, in our opinion, such financial
statement schedule, when considered in relation to the basic
consolidated financial statements taken as a whole, presents
fairly in all material respects the information set forth
therein.




DELOITTE & TOUCHE LLP

Portland, Oregon
January 31, 1997



IDAHO POWER COMPANY
SUPPLEMENTAL FINANCIAL INFORMATION, UNAUDITED


QUARTERLY FINANCIAL DATA:
The following unaudited information is presented for each quarter
of 1996, 1995 and 1994 (in thousands of dollars, except for per
share amounts). In the opinion of the Company, all adjustments
necessary for a fair statement of such amounts for such periods
have been included. The results of operations for the interim
periods are not necessarily indicative of the results to be
expected for the full year. Accordingly, earnings information for
any three-month period should not be considered as a basis for
estimating operating results for a full fiscal year. Amounts are
based upon quarterly statements and the sum of the quarters may
not equal the annual amount reported.

                                       Quarter Ended
                           March 31  June 30  September December
                                                 30        31
                                                                      
1996                                                                  
 Revenues                     $146,629   $140,384   $149,652   $141,781 
 Income from operations         58,489     46,741     41,780     40,161 
 Income taxes                   17,466     12,828     11,597     10,201 
 Net income                     30,211     23,033     19,151     18,225 
 Dividends on preferred stock    1,952      1,927      1,954      1,632 
 Earnings on common stock       28,259     21,106     17,197     16,593 
 Earnings per share of 
  common stock                    0.75       0.56       0.45       0.44 
                                                                          
1995                                                                  
 Revenues                      131,336    130,254    148,726    135,306 
 Income from operations         46,552     38,681     45,637     45,122 
 Income taxes                   14,234     10,951     12,442     10,786
 Net income                     20,727     17,588     23,771     24,833
 Dividends on preferred stock    2,026      2,006      1,976      1,982 
 Earnings on common stock       18,701     15,582     21,795     22,851 
 Earnings per share of     
  common stock                    0.50       0.41       0.58       0.61 
                                                                          
1994                                                                      
 Revenues                      128,810    128,541    151,031    135,277 
 Income from operations         37,408     33,984     33,609     44,663 
 Income taxes                    9,406      6,554      8,150     10,133 
 Net income                     18,260     17,030     16,289     23,351 
 Dividends on preferred stock    1,789      1,819      1,862      1,928 
 Earnings on common stock       16,471     15,211     14,427     21,423 
 Earnings per share of      
  common stock                    0.44       0.41       0.38       0.57 


ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON
      ACCOUNTING AND FINANCIAL DISCLOSURE

     None


PART III

Part III has been omitted because the registrant will file a
definitive proxy statement pursuant to Regulation 14A, which
involves the election of Directors, with the Commission within
120 days after the close of the fiscal year portions of which are
hereby incorporated by reference (except for information with
respect to executive officers which is set forth in Part I
hereof).


PART IV

ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULE AND REPORTS ON
       FORM 8-K
(a)   Please refer to Item 8, "Financial Statements and
      Supplementary Data" for a complete listing of all consolidated
      financial statements and financial statement schedule.

(b)   Reports on SEC Form 8-K. No reports on Form 8-K were
      filed during the three months ended December 31, 1996.

(c)   Exhibits.

*Previously Filed and Incorporated Herein by Reference

Exhibit   File Number   As Exhibit

*3(a)      33-00440     4(a)(xiii)  Restated Articles of Incorporation
                                    of the Company as filed with the
                                    Secretary of State of Idaho on
                                    June 30, 1989.
                               
*3(a)(i)   33-65720     4(a)(i)     Statement of Resolution
                                    Establishing Terms of 8.375% Serial
                                    Preferred Stock, Without Par Value
                                    (cumulative stated value of $100
                                    per share), as filed with the
                                    Secretary of State of Idaho on
                                    September 23, 1991.
                               
*3(a)(ii)  33-65720     4(a)(ii)    Statement of Resolution
                                    Establishing Terms of Flexible
                                    Auction Series A, Serial Preferred
                                    Stock, Without Par Value
                                    (cumulative stated value of
                                    $100,000 per share), as filed with
                                    the Secretary of State of Idaho on
                                    November 5, 1991.
                               
*3(a)(iii) 33-65720     4(a)(iii)   Statement of Resolution
                                    Establishing Terms of 7.07% Serial
                                    Preferred Stock, Without Par Value
                                    (cumulative stated value of $100
                                    per share), as filed with the
                                    Secretary of State of Idaho on June
                                    30, 1993.
                               
                               
Exhibit   File Number   As Exhibit      

*3(b)     33-41166      4(b)        Waiver resolution to Restated
                                    Articles of Incorporation adopted
                                    by Shareholders on May 1, 1991.
                               
*3(c)     33-00440      4(a)(xiv)   By-laws of the Company amended on
                                    June 30, 1989, and presently in
                                    effect.
                               
*4(a)(i)  2-3413        B-2         Mortgage and Deed of Trust, dated as
                                    of  October  1,  1937,  between  the
                                    Company  and  Bankers Trust  Company
                                    and R. G. Page, as Trustees.
                               
*4(a)(ii)                           Supplemental Indentures to  Mortgage
                                    and Deed of Trust:
                                           
                                  Number          Dated
          1-MD          B-2-a     First           July 1, 1939
          2-5395        7-a-3     Second          November 15, 1943
          2-7237        7-a-4     Third           February 1, 1947
          2-7502        7-a-5     Fourth          May 1, 1948
          2-8398        7-a-6     Fifth           November 1, 1949
          2-8973        7-a-7     Sixth           October 1, 1951
          2-12941       2-C-8     Seventh         January 1, 1957
          2-13688       4-J       Eighth          July 15, 1957
          2-13689       4-K       Ninth           November 15, 1957
          2-14245       4-L       Tenth           April 1, 1958
          2-14366       2-L       Eleventh        October 15, 1958
          2-14935       4-N       Twelfth         May 15, 1959
          2-18976       4-O       Thirteenth      November 15, 1960
          2-18977       4-Q       Fourteenth      November 1, 1961
          2-22988       4-B-16    Fifteenth       September 15, 1964
          2-24578       4-B-17    Sixteenth       April 1, 1966
          2-25479       4-B-18    Seventeenth     October 1, 1966
          2-45260       2(c)      Eighteenth      September 1, 1972
          2-49854       2(c)      Nineteenth      January 15, 1974
          2-51722       2(c)(i)   Twentieth       August 1, 1974
          2-51722       2(c)(ii)  Twenty-first    October 15, 1974
          2-57374       2(c)      Twenty-second   November 15, 1976
          2-62035       2(c)      Twenty-third    August 15, 1978
          33-34222      4(d)(iii) Twenty-fourth   September 1, 1979
          33-34222      4(d)(iv)  Twenty-fifth    November 1, 1981
          33-34222      4(d)(v)   Twenty-sixth    May 1, 1982
          33-34222      4(d)(vi)  Twenty-seventh  May 1, 1986
          33-00440      4(c)(iv)  Twenty-eighth   June 30, 1989
          33-34222      4(d)(vii) Twenty-ninth    January 1, 1990
          33-65720      4(d)(iii) Thirtieth       January 1, 1991
          33-65720      4(d)(iv)  Thirty-first    August 15, 1991
          33-65720      4(d)(v)   Thirty-second   March 15, 1992
          33-65720      4(d)(vi)  Thirty-third    April 16, 1993
          1-3198        4         Thirty-fourth   December 1, 1993
          Form 8-K          
          Dated
          12/17/93

Exhibit     File Number   As Exhibit
*4(b)                                Instruments relating to American    
                                     Falls bond guarantee. (see Exhibits
                                     10(f) and 10(f)(i)).
                                                                   
*4(c)       33-65720      4(f)       Agreement to furnish certain debt   
                                     instruments.
                                                                   
*4(d)       33-00440      2(a)(iii)   Agreement and Plan of Merger dated  
                                      March 10, 1989, between Idaho Power
                                      Company, a Maine Corporation, and
                                      Idaho Power Migrating Corporation.
                                                                   
*4(e)       33-65720      4(e)        Rights Agreement dated January 11,  
                                      1990, between the Company and First
                                      Chicago Trust Company of New York,
                                      as Rights Agent (The Bank of New
                                      York, successor Rights Agent).
                                                                   
*10(a)      2-51762       5(a)        Agreement, dated April 20, 1973,    
                                      between the Company and FMC
                                      Corporation.
                                                                   
*10(a)(i)   2-57374       5(b)        Letter Agreement, dated October 22, 
                                      1975, relating to agreement filed
                                      as Exhibit 10(a).
                                                                   
*10(a)(ii)  2-62034       5(b)(i)     Letter Agreement, dated             
                                      December 22, 1976, relating to
                                      agreement filed as Exhibit 10(a).
                                                                   
*10(a)(iii) 33-65720      10(a)       Letter Agreement, dated             
                                      December 11, 1981, relating to
                                      agreement filed as Exhibit 10(a).
                               
*10(b)      2-49584       5(b)        Agreements, dated September 22,     
                                      1969, between the Company and
                                      Pacific Power & Light Company
                                      relating to the operation,
                                      construction and ownership of the
                                      Jim Bridger Project.
                               
*10(b)(i)   2-51762       5(c)        Amendment, dated February 1, 1974,  
                                      relating to operation agreement
                                      filed as Exhibit 10(b).
                               
*10(c)      2-49584       5(c)        Agreement, dated as of October 11,  
                                      1973, between the Company and
                                      Pacific Power & Light Company.
                                                                   
*10(d)      2-49584       5(d)        Agreement, dated as of October 24,  
                                      1973, between the Company and Utah
                                      Power & Light Company.
                                                                    
*10(d)(i)   2-62034       5(f)(i)     Amendment, dated January 25, 1978,   
                                      relating to agreement filed as
                                      Exhibit 10(d).
                               
*10(e)      33-65720      10(b)       Coal Purchase Contract, dated as of  
                                      June 19, 1986, among the Company,
                                      Sierra Pacific Power Company and
                                      Black Butte Coal Company.
                                                                    
*10(f)      2-57374       5(k)        Contract, dated March 31, 1976,      
                                      between the United States of America
                                      and American Falls Reservoir
                                      District, and related Exhibits.

Exhibit     File Number   As Exhibit     

*10(f)(i)   33-65720      10(c)       Guaranty  Agreement, dated March 1,  
                                      1990, between the Company and West
                                      One Bank, as Trustee, relating to
                                      $21,425,000 American Falls
                                      Replacement Dam Bonds of the
                                      American Falls Reservoir District,
                                      Idaho.
                                                                    
*10(g)      2-57374       5(m)        Agreement, effective April 15, 1975, 
                                      between the Company and The
                                      Washington Water Power Company.
                                                                    
*10(h)      2-62034       5(p)        Bridger Coal Company Agreement,      
                                      dated February 1, 1974, between
                                      Pacific Minerals, Inc., and Idaho
                                      Energy Resources Co.
                                                                    
*10(i)      2-62034       5(q)        Coal Sales Agreement, dated February 1,
                                      1974, between Bridger Coal
                                      Company and Pacific Power & Light
                                      Company and the Company.
                                                                    
*10(i)(i)   33-65720      10(d)       Second Restated and Amended Coal     
                                      Sales Agreement, dated March 7,
                                      1988, among Bridger Coal Company and
                                      PacifiCorp (dba Pacific Power &
                                      Light Company) and the Company.
                                                                    
*10(i)(ii)  1-3198        10(i)(ii)   Third Restated and Amended Coal      
            Form 10-Q                 Sales Agreement, dated January 1,
            for 3/31/96               1996, among Bridger Coal Company and
                                      PacifiCorp (dba Pacific Power &
                                      Light Company) and the Company.
                                                                    
*10(j)      2-62034       5(r)        Guaranty Agreement, dated as of      
                                      August 30, 1974, with Pacific Power
                                      & Light Company.
                                                                    
*10(k)      2-56513       5(i)        Letter Agreement, dated January 23,  
                                      1976, between the Company and
                                      Portland General Electric Company.
                               
*10(k)(i)   2-62034       5(s)        Agreement for Construction,          
                                      Ownership and Operation of the
                                      Number One Boardman Station on Carty
                                      Reservoir, dated as of October 15,
                                      1976, between Portland General
                                      Electric Company and the Company.
                                                                    
*10(k)(ii)  2-62034       5(t)        Amendment, dated September 30, 1977, 
                                      relating to agreement filed as
                                      Exhibit 10(k).
                               
*10(k)(iii) 2-62034       5(u)        Amendment, dated October 31, 1977,   
                                      relating to agreement filed as
                                      Exhibit 10(k).
                                                                    
*10(k)(iv)  2-62034       5(v)        Amendment, dated January 23, 1978,   
                                      relating to agreement filed as
                                      Exhibit 10(k).
                                                                    
*10(k)(v)   2-62034       5(w)        Amendment, dated February 15, 1978,  
                                      relating to agreement filed as
                                      Exhibit 10(k).
                                                                    
*10(k)(vi)  2-68574       5(x)        Amendment, dated September 1, 1979,  
                                      relating to agreement filed as
                                      Exhibit 10(k).

Exhibit     File Number   As Exhibit

*10(l)       2-68574     5(z)        Participation Agreement, dated       
                                     September 1, 1979, relating to the
                                     sale and leaseback of coal handling
                                     facilities at the Number One
                                     Boardman Station on Carty Reservoir.
                               
*10(m)       2-64910     5(y)        Agreements for the Operation,        
                                     Construction and Ownership of the
                                     North Valmy Power Plant Project,
                                     dated December 12, 1978, between
                                     Sierra Pacific Power Company and the
                                     Company.
                                                                    
*10(n)(i)1   1-3198      10(n)(i)     The Revised Security Plans for       
             Form 10-K                Senior Management Employees and for
             for 1994                 Directors-a non-qualified, deferred
                                      compensation plan effective November
                                      30, 1994.
                                                                    
*10(n)(ii)1  1-3198      10(n)(ii)    The Executive Annual Incentive Plan  
             Form 10-K                for senior management employees
             for 1994                 effective January 1, 1995.
                                                                    
*10(n)(iii)1 1-3198      10(n)(iii)   The 1994 Restricted Stock Plan for   
             Form 10-K                officers and key executives
             for 1994                 effective July 1, 1994.
                                                                    
                               
10(n)(iv)1                            The Revised Security Plans for       
                                      Senior Management Employees and for
                                      Directors-a non-qualified, deferred
                                      compensation plan effective August
                                      1, 1996.
                                                                    
*10(o)       33-65720    10(f)        Residential Purchase and Sale        
                                      Agreement, dated August 22, 1981,
                                      among the United Stated of American
                                      Department of Energy acting by and
                                      through the Bonneville Power
                                      Administration, and the Company.
                                                                    
*10(p)       33-65720    10(g)        Power Sales Contact, dated           
                                      August 25, 1981, including
                                      amendments, among the United States
                                      of America Department of Energy
                                      acting by and through the Bonneville
                                      Power Administration, and the
                                      Company.
                                                                    
*10(q)       33-65720    10(h)        Framework Agreement, dated October   
                                      1, 1984, between the State of Idaho
                                      and the Company relating to the
                                      Company's Swan Falls and Snake River
                                      water rights.
                               
*10(q)(i)    33-65720    10(h)(i)     Agreement, dated October 25, 1984,   
                                      between the State of Idaho and the
                                      Company relating to the agreement
                                      filed as Exhibit 10(q).
                                                                    
*10(q)(ii)   33-65720    10(h)(ii)    Contract to Implement, dated October 
                                      25, 1984, between the State of Idaho
                                      and the Company relating to the
                                      agreement filed as Exhibit 10(q).

*10(r)       33-65720    10(i)        Agreement for Supply of Power and    
                                      Energy, dated February 10, 1988,
                                      between the Utah Associated
                                      Municipal Power Systems and the
                                      Company.
                                                                              
                                                                              
1 Compensatory Plan


Exhibit     File Number   As Exhibit     

*10(s)      33-65720      10(j)       Agreement Respecting Transmission    
                                      Facilities and Services, dated
                                      March 21, 1988 among PC/UP&L Merging
                                      Corp. and the Company including a
                                      Settlement Agreement between
                                      PacifiCorp and the Company.
                                                                    
*10(s)(i)   33-65720      10(j)(i)    Restated Transmission Services       
                                      Agreement, dated February 6, 1992,
                                      between Idaho Power Company and
                                      PacifiCorp.
                                                                    
*10(t)      33-65720      10(k)       Agreement for Supply of Power and    
                                      Energy, dated February 23, 1989,
                                      between Sierra Pacific Power Company
                                      and the Company.
                                                                    
*10(u)      33-65720      10(l)       Transmission Services Agreement,     
                                      dated May 18, 1989, between the
                                      Company and the Bonneville Power
                                      Administration.
                                                                    
*10(v)      33-65720      10(m)       Agreement Regarding the Ownership,   
                                      Construction, Operation and
                                      Maintenance of the Milner
                                      Hydroelectric Project (FERC No.
                                      2899), dated January 22, 1990,
                                      between the Company and the Twin
                                      Falls Canal Company and the
                                      Northside Canal Company Limited.
                                                                    
*10(v)(i)   33-65720      10(m)(i)    Guaranty Agreement, dated February   
                                      10, 1992, between the Company and
                                      New York Life Insurance Company, as
                                      Note Purchaser, relating to
                                      $11,700,000 Guaranteed Notes due
                                      2017 of Milner Dam Inc.
                                                                    
*10(w)      33-65720      10(n)       Agreement for the Purchase and Sale  
                                      of Power and Energy, dated October
                                      16, 1990, between the Company and
                                      The Montana Power Company.
                                                                    
*10(x)      1-3198        10(x)       Agreement for design of substation   
            Form 10-Q                 dated October 4, 1995, between the
            for 9/30/95               Company and Micron Technology, Inc.
                                                                    
12                                    Statement Re:  Computation of Ratio  
                                      of Earnings to Fixed Charges.
                                                                    
12(a)                                 Statement Re:  Computation of        
                                      Supplemental Ratio of Earnings to
                                      Fixed Charges.
                                                                    
12(b)                                 Statement Re:  Computation of Ratio  
                                      of Earnings to Combined Fixed
                                      Charges and Preferred Dividend
                                      Requirements.
                                                                     
12(c)                                 Statement Re:  Computation of        
                                      Supplemental Ratio of Earnings to
                                      Combined Fixed Charges and Preferred
                                      Dividend Requirements.
                                                                    
21                                    Subsidiaries of Registrant..         
                                                                    
23                                    Independent Auditor's Consent        
                                                                    
27                                    Financial Data Schedule              


IDAHO POWER COMPANY
SCHEDULE II - CONSOLIDATED VALUATION AND QUALIFYING ACCOUNTS
Years Ended December 31, 1996, 1995 and 1994

       Column A          Column B         Column C        Column D   Column E
                                          Additions    
                                                 Charged
                         Balance at   Charged  (Credited)            Balance at
                         Beginning       to     to Other   Deduction  End of
     Classification      of Period    Income    Accounts      (1)     Period
                                 (Thousands of Dollars)
1996:                                                          
 Reserves Deducted                                             
  From Applicable Assets:                                           
   Reserve for 
    uncollectible 
    accounts             $1,397       $  -     $3,003(2)  $3,006     $1,394 
  Other Reserves:                                              
   Injuries and                                                
    damages
    reserve              $1,500       $  -     $  -       $  -       $1,500 
   Miscellaneous                                               
    operating
    reserves             $1,143       $  829   $4,874     $  198     $6,648
                                                               
1995:                                                          
 Reserves Deducted                                             
  From Applicable Assets:                                           
   Reserve for                                                 
    uncollectible
    accounts             $1,377      $  217     $2,927(2) $3,124     $1,397 
  Other Reserves:                                              
   Injuries and                                                
    damages
    reserves             $1,500      $1,364     $  -      $1,364     $1,500
   Miscellaneous                                               
    operating
    reserve              $  940      $  460     $ (176)   $   81     $1,143 
                                                               
1994:                                                          
 Reserves Deducted                                             
  From Applicable Assets:                                           
  Reserve for                                                 
   uncollectible
   accounts              $1,377      $1,360     $1,018(2) $2,378     $1,377 
  Other Reserves:                                              
   Injuries and                                                
    damages
    reserve              $1,500      $1,804     $  -       $1,804    $1,500
   Miscellaneous                                               
    operating
    reserves             $  748      $  429     $(156)     $   81    $  940 
                                                               

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


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

                                     IDAHO POWER COMPANY
                                     (Registrant)

March 13, 1997                 By:   /s/Joseph W. Marshall
                                     Joseph W. Marshall
                                     Chairman of the Board and
                                     Chief Executive Officer and
Director

Pursuant to the requirements of the Securities Exchange Act of
1934, this report is signed below by the following persons on
behalf of the Registrant and in the capacities and on the dates
indicated.
                                
By:/s/Joseph W. Marshall        Chairman of the Board and    March 13, 1997
   Joseph W. Marshall           Chief Executive Officer
                                and Director
                                                              
By:/s/Larry R. Gunnoe           President and Chief                 "
                                Operating
   Larry R. Gunnoe              Officer and Director       
                                                              
By:/s/J. LaMont Keen            Vice President, Chief Financial     "
   J. LaMont Keen               Officer and Treasurer       
                                (Principal Financial and
                                Accounting Officer)
                                                              
By:/s/Robert D. Bolinder        By:/s/Evelyn Loveless               "
   Robert D. Bolinder           Evelyn Loveless                
   Director                     Director                       
                                                               
By:/s/Roger L. Breezley         By:/s/Jon H. Miller                 "
   Roger L. Breezley            Jon H. Miller                  
   Director                     Director                       
                                                               
By:/s/John B. Carley            By:/s/Peter S. O'Neill              "
   John B. Carley               Peter S. O'Neill               
   Director                     Director                       
                                                               
By:/s/Peter T. Johnson          By:/s/Gene C. Rose                 "
   Peter T. Johnson             Gene C. Rose                   
   Director                     Director                       
                                                               
By:/s/Jack K. Lemley            By:/s/Phil Soulen                 "
   Jack K. Lemley               Phil Soulen                    
   Director                     Director                       



EXHIBIT INDEX

Exhibit                                                   Page
Number                                                    Number

10(n)(iv)      The Revised Security Plans                   
               for Senior Management                        
               Employees and for Directors-a               72
               non-qualified, deferred
               compensation plan effective
               August 1, 1996
                                                            
12             Statement Re: Computation of                 
               Ratio of Earnings to Fixed                  139
               Charges
                                                            
12(a)          Statement Re: Computation of                 
               Supplemental Ratio of                       140
               Earnings to Fixed Charges
                                                            
12(b)          Statement Re: Computation of                 
               Ratio of Earnings to Combined                
               Fixed Charges and Preferred                 141
               Dividend Requirements
                                                            
12(c)          Statement Re: Computation of                 
               Supplemental Ratio of                        
               Earnings to Combined Fixed                  142
               Charges and Preferred
               Dividend Requirements.
                                                            
21             Subsidiaries of Registrant                  143
                                                            
23             Independent Auditors'                       144
               Consent.
                                                            
27             Financial Data Schedule                     145