TABLE OF CONTENTS


PART I
                                                              PAGE

 ITEM 1. BUSINESS                                              2
         GENERAL                                               2
         POWER SUPPLY                                          5
         DIVERSIFIED BUSINESS OPERATIONS                       6
         ELECTRIC INDUSTRY RESTRUCTURING                       7
         FUEL                                                  7
         WATER RIGHTS                                          8
         REGULATION                                            9
         ENVIRONMENTAL REGULATION                              9
         RATES                                                11
         CONSTRUCTION PROGRAM                                 12
         FINANCING PROGRAM                                    13
 ITEM 2. PROPERTIES                                           14
 ITEM 3. LEGAL PROCEEDINGS                                    16
 ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS  18

 EXECUTIVE OFFICERS OF THE REGISTRANTS                        18

PART II

 ITEM 5. MARKET FOR THE REGISTRANT'S COMMON STOCK AND RELATED
         STOCKHOLDER MATTERS                                  20
 ITEM 6. SELECTED FINANCIAL DATA                              21
 ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
         CONDITION AND RESULTS OF OPERATIONS                  22
 ITEM 7A.QUANTITATIVE AND QUALITATIVE DISCLOSURE ABOUT
         MARKET RISK                                          36
 ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA          37
 ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON
         ACCOUNTING AND FINANCIAL DISCLOSURE                  72

PART III

 ITEM 10.DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANTS* 72
 ITEM 11.EXECUTIVE COMPENSATION*                              72
 ITEM 12.SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND
         MANAGEMENT*                                          72
 ITEM 13.CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS*      72

PART IV

 ITEM 14.EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS
         ON FORM 8-K                                          72

 SIGNATURES                                                  78-79

 *INCORPORATED BY REFERENCE.



         UNITED STATES SECURITIES AND EXCHANGE COMMISSION
                      Washington, D.C. 20549
                           FORM 10-K-405

(Mark One)

X     ANNUAL REPORT PURSUANT TO SECTION 13 OR 15 (d) OF THE
SECURITIES
    EXCHANGE ACT OF 1934
      For the fiscal year ended December 31, 1998

                                OR
   TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES
   EXCHANGE ACT OF 1934

       For the transition period from ................... to
 .................................................................

             Exact name of Registrants as specified in
Commissiontheir charters, address of principal executive    IRS
Employer Iden-
File Numberoffices and Registrants' telephone number tification
Number
1-14465                  IDACORP, Inc.               82-0505802
1-3198                Idaho Power Company            82-0130980
                      1221 W. Idaho Street
                      Boise, ID 83702-5627
                         (208) 388-2200

State or other jurisdiction of incorporation: Idaho

SECURITIES REGISTERED PURSUANT TO SECTION 12(b) OF THE ACT: Name
                                                 of exchange on
                                                 which registered
IDACORP, Inc.: Common Stock, without par value   New York and Pacific

SECURITIES REGISTERED PURSUANT TO SECTION 12(g) OF THE ACT:
Idaho Power Company: Preferred Stock

Indicate by check mark whether the registrants (1) have 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 registrants were required to file
such reports), and (2) have 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 registrants' 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 and non-voting common stock held
by nonaffiliates (March 1, 1999)

IDACORP, Inc.:           37,497,405
Idaho Power Company:     None

Number of shares of common stock outstanding at February 28, 1999:

IDACORP, Inc.:           37,612,351
Idaho Power Company:     37,612,351 shares all of which are held
                                    by IDACORP, Inc.

Documents Incorporated by Reference:
Part III, Item 10   Portions of the joint proxy statement of the
                    Registrants.
          Item 11   to be filed pursuant to Regulation 14A for the 1999
                    Annual Meeting of Shareholders to be
          Item 12   held on May 5, 1999.
          Item 13

PART I - IDACORP, Inc. and Idaho Power Company:



ITEM 1.  BUSINESS


SAFE HARBOR STATEMENT
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
IDACORP, Inc. (Company), a holding company, was incorporated under
the laws of the state of Idaho in 1998.  The Company's principal
subsidiary is Idaho Power Company (IPC), an electric public
utility company that represents over 90 percent of the Company's total
assets and is its principal operating subsidiary.  The Company's
other subsidiaries are Ida-West Energy Company (Ida-West) and
IDACORP Energy Solutions Inc. (IES).

     Subsidiaries of IDACORP -
IPC 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.  IPC 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
780,000.  IPC holds franchises in approximately 70 cities in Idaho
and ten cities in Oregon, and holds certificates from the
respective public utility regulatory authorities to serve all or a
portion of 28 counties in Idaho, three counties in Oregon and one
county in Nevada.  As of December 31, 1998, IPC supplied electric
energy to 373,730 general business customers and employed 1,669
people in its operations.

IPC's results of operations, like those of certain other utilities
in the Northwest, can be significantly affected by changing
weather, precipitation and streamflow conditions.  In 1993 a power
cost adjustment (PCA) mechanism was implemented in IPC's Idaho
jurisdiction.  With the implementation of the PCA, which includes
a major portion of the operating expenses with the largest variation
potential (net power supply costs), IPC'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.

IPC operates 17 hydro power plants and shares ownership in three
coal-fired generating plants (see Item 2 - "Properties").  IPC
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.  IPC has participated in the development
of thermal generation in Wyoming, Oregon and Nevada using low-
sulfur coal from Wyoming and Utah.

For the year ended December 31, 1998, total revenues from
residential customers accounted for 41percent of total general
business revenues.  Commercial customers with less than 1,000
kilowatt (kW) demand accounted for 23 percent, industrial
customers with 1,000 kW demand and over accounted for 24 percent,
irrigation customers accounted for 11 percent and other revenues
accounted for 1 percent.

IPC's principal commercial and industrial customers are involved
in:  elemental phosphorus production; food processing; phosphate
fertilizer production; electronics and general manufacturing;
lumber; beet sugar refining; and the recreation industry, such as
lodges, condominiums, ski lifts and related facilities.

The off-system revenue percentage increased in 1998 due primarily
to increases in electricity trading activity.  Firm energy demand,
hydroelectric generating conditions and market conditions
throughout the west also affect the volume and price of off-system
sales.

IPC intends to be a competitive energy provider, including both
electricity and natural gas and operates gas trading offices in
Houston, Texas to serve the southern and eastern United States and
Boise, Idaho, to serve the northwest and Canadian markets.  IPC
has also significantly increased its participation in the wholesale
electricity markets.

Ida-West was formed in 1989 to participate through partnership
interests in cogeneration and small power production (CSPP)
projects.  Ida-West holds investments in 13 operating
hydroelectric plants with a total generating capacity of approximately 72
megawatts (MW).

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

Ida-West has a partnership interest in the Hermiston Power
Project, a 536 MW, gas-fired 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.  Construction of
this project could begin in 1999.

IPC has purchased all of the power from the five Idaho
hydroelectric entities that are fifty percent owned by Ida-West,
totaling approximately $8.7 million in 1998.  At December 31,
1998, total investment in Ida-West was $26.9 million.

IES was created in December 1997 to address and pursue
opportunities to provide expanded products and services to present
and future customers.  To date there has been limited activity in
this entity.

     Subsidiaries of IPC -

Idaho Energy Resources Company (IERCo), has been in operation
since 1974.  Its primary purpose is to participate as a joint venturer
in the Bridger Coal Company, which operates the mine supplying coal
to the Jim Bridger power plant near Rock Springs, Wyoming (see
"Fuel").  As of December 31, 1998, total investment in IERCo was
$10.7 million.

IDACORP Financial Services, Inc.  (IFS), was organized in 1986 to
pursue a non-regulated diversification program.  At the end of
1998 IFS was participating in 12 affordable housing programs which
provide a return primarily by reducing federal income taxes
through tax credits and tax depreciation benefits.  As of December 31,
1998, total investment in IFS was $15.0 million.

Stellar Dynamics, Inc (Stellar) was formed in 1995 to
commercialize expertise in control technology for electric substations
and power plants.  Currently, Stellar's market focus is in complex
control and automation systems for the electric utility sector and
industrial applications.  Stellar also provides design and
engineering for complete electric substations.  Stellar markets
its products nationally and internationally.  As of December 31, 1998,
total investment in Stellar was $1.1 million.

Applied Power Corporation (APC) is a Lacey, Washington based
company that designs, supplies and distributes photovoltaic (PV)
systems.  APC provides reliable, cost-effective solar electric
products and systems for industry, contractors, utilities,
government and an international network of solar dealers and
distributors. As of December 31, 1998, total investment in APC was
$4.7 million.

Pathnet/Idaho Equipment, LLC (Pathnet) was formed in 1998 to
develop and distribute microwave communication services and
products.  As of December 31, 1998, total investment in Pathnet
was $1.5 million.

     Research and Development, Renewable Energy Sources and Fuel
     Cells -
During 1998, the Company spent approximately $1.2 million on
research and development of which $0.9 million was through
membership in Electric Power Research Institute (EPRI).  EPRI's
mission is to discover, develop and deliver advances in science
and technology.  Some of the subjects of EPRI projects include:
electrification technologies, power quality, electric
transportation systems, EMF assessment/risk management and air
quality issues.  IPC 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 IPC.

In 1992, IPC joined Southern California Edison, the U.S.
Department of Energy (DOE) and others in retrofitting an existing
10-megawatt central receiver solar thermal experimental power plant
now called Solar Two near Barstow, California.  IPC has contributed
$630,500 through 1998 and EPRI contributed an additional $630,500 of
matching funds, bringing credited contribution to approximately
$1.3 million.  Solar Two was first synchronized to Southern
California Edison's system in May 1996.

In 1998, IPC entered into an agreement with Proton Energy Systems
(PES) to purchase an electrolyzer that produces hydrogen from
electricity.  IPC is conducting a pilot program with the
electrolyzer as part of its efforts to gain experience with fuel
cells and to gain first-hand working knowledge and information
about the technology.  Because of IPC's low cost of electrical
power, there is great potential that the electrolyzer can supply
high-value hydrogen to consumers at their plant sites and at a
lower cost than conventional bottled hydrogen.  IPC has an
agreement with the DOE, Lockheed and PES to test the electrolyzer
and validate the operating characteristics of the unit.

In May 1998, a subsidiary of IPC entered into a Research and
Development and Option Agreement with Northwest Power
Systems (NPS) to provide technical and financial resources to NPS
for the on-going development of a fully integrated, small-scale
fuel cell.  NPS has patented a unique fuel reformer that allows
for the processing of a number of fuels into hydrogen that is then
used for the generation of electricity.  A fully operational prototype
has been constructed and successfully tested.

     Energy Efficiency -
As an active member of the Northwest Energy Efficiency Alliance,
IPC has been shifting the focus of its conservation, or demand-
side management (DSM), activities towards regional market
transformation efforts and renewing its commitment to public purpose
programs.  At the same time, IPC has discontinued many of the traditional DSM
programs that required deferral of costs.  In 1998, $2.9 million
was expended on energy-efficiency programs.



POWER SUPPLY

IPC meets its system load requirements using a combination of its
own system generation, mandated purchases from private developers
(see CSPP purchases below) and purchases from other utilities and
power producers.  IPC's generating stations and capacities are
listed in Item 2. Properties.  Historically, under normal water
conditions, IPC's hydro system supplies approximately 56 percent,
thermal generation accounts for 33 percent and purchased power and
other interchanges contribute the remaining 11 percent of total
system requirements.

IPC's system is dual-peaking, with the larger peak demand
generally occurring in the summer.  The system peak demand for 1998 was
2,747 MW, set on July 14, 1998.  Peak demands in 1997 and 1996 were
2,545 MW and 2,661 MW respectively.  IPC periodically updates its load
and resource projections and now expects total system energy
requirements to grow 2.0 percent annually over the next five
years.

Because of its reliance upon hydroelectric generation, which
varies according to streamflows, IPC's generating system is constrained
more by resource availability than by capacity.  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 contract
that expires in 2000 and with Seattle City Light under a contract
that expires in 2003.

During the 1999-2003 period, IPC plans to provide all the energy
required to serve its firm load requirements by using its
hydroelectric and coal-fired generating units, supplemented by
purchases of power from neighboring utilities or marketing
entities.

Even though its significant hydroelectric generation can operate
to meet peak demands, seasonal energy requirements are important to
IPC because its seasonal energy capability is determined in part
by the availability of water.  In 1996, 1997 and 1998, IPC's hydro
generating system experienced above average water years.  Early
reports for 1999 indicate that three major factors affecting hydro
production, mountain snowpack, carryover reservoir storage and
precipitation are all above normal for the time of year.

IPC'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.
IPC's transmission system 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 interchange, purchase and sale of power among most of
the electric systems in the West.  IPC 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.

     CSPP Purchases -
As a result of the enactment of the Public Utilities Regulatory
Policy Act of 1978 (PURPA) and the adoption of avoided cost
standards by the IPUC, IPC has entered into contracts for the
purchase of energy from private developers.  Because IPC's service
territory encompasses substantial irrigation canal development,
forest product production facilities, mountain streams, and food
processing facilities, considerable amounts of energy are
available from these sources.  Such energy comes from hydropower 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 66 CSPP projects on-line as
of December 31, 1998 is $58.0 million.  During 1998, IPC purchased
907.1 million kWh of power from these private developers at a
blended price of 6.0 cents per kWh.

In 1995 IPC received approval from the IPUC to reduce published
CSPP rates for new projects less than one MW.  In addition, the
IPUC determined that negotiated rates for future CSPP projects
larger than one MW should be tied more closely to values
determined in IPC's integrated resource planning process.  In subsequent
orders, the IPUC limited the length of new contracts to a maximum
of five years (see "Rates").

     Wholesale Power Sales -
IPC has firm wholesale power sales contracts with several
entities.  These contracts are for various amounts of energy, ranging up to
100 average MW, and are of various lengths expiring between 1999 and
2009.  IPC is actively participating in the wholesale electricity
markets and as a result, has increased significantly the volume of
electricity sold and purchased.  IPC is actively marketing this
power to other entities as it becomes available.

     Transmission Services -
IPC has long had an informal open-access transmission policy and
is experienced in providing reliable, high quality, economical
transmission service.  IPC provides various firm and non-firm
wheeling services for several surrounding utilities.

In 1996 the FERC issued Order Nos. 888 and 889 dealing with open
access non-discriminatory transmission services by public
utilities, and standards of conduct regarding these services.
These orders require public utilities owning transmission lines to
file open-access tariffs available to buyers and sellers of
wholesale electricity; to require utilities to use the tariffs for
their own wholesale sales; and to allow utilities to recover
stranded costs, subject to certain conditions.  Public utilities
owning transmission lines were required to file compliance tariffs
by July 9, 1996.

In November 1995, IPC 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 IPC uses in its own operations to
anyone seeking them.  IPC requested and received permission to implement
these tariffs beginning February 1, 1996.  On July 8, 1996, IPC
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, the FERC issued an unconditional acceptance of the terms and
conditions of this tariff.  The rate was not subject to review.

IPC'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 allows IPC to provide
transmission services and reach a broad power sales market.


DIVERSIFIED BUSINESS OPERATIONS
The Company has been pursuing a strategy of expanding non-
regulated activities and separating regulated from non-regulated activities.
The following discussion relates to these expanded activities.

In 1997 and 1998 IPC greatly increased its participation in the
western wholesale electricity markets.  In mid-1997, IPC began
trading natural gas.  By December 1998, natural gas sales volumes
exceeded 482 million cubic feet per day.  These changes reflect
the Company's intent to be a competitive energy provider of both of
these commodities.

In 1998, the Company began offering two new products to retail
customers, satellite television and billpayer insurance.

On February 17, 1998, the Company announced it had joined the
Allied Utility Network (AUN), a member-supported alliance that
provides customer research, marketing and other support services
to utilities.  Through its relationship with AUN, the Company is
developing new products and services to offer to retail customers.
Other members of the alliance include Colorado Springs Utilities
of Colorado Springs, Colorado, Omaha Public Power District of Omaha,
Nebraska, Snapping Shoals EMC of Covington, Georgia and Cobb
Electric Membership Corporation of Marietta, Georgia.
Collectively, the utilities serve approximately one million
customers.

By the end of 1999, the Company intends to have transferred IPC's
non-utility business activities and unregulated subsidiaries under
the holding company or its unregulated subsidiaries.


ELECTRIC INDUSTRY RESTRUCTURING
Competition is increasing in the electric utility industry.  The
legislatures and/or the regulatory commissions in several states,
and at a national level, have considered or are considering
"retail wheeling."  Retail wheeling means the movement of electric energy
produced by another entity over an electric utility's transmission
and distribution system, to a retail customer in what was the
utility's traditional service territory.  A requirement to
transmit directly to retail customers would permit retail customers to
purchase electric capacity and energy from their local electric
utility or from any other electric utility or independent power
supplier.

In 1997, the Idaho Legislature appointed a committee to study
restructuring of the electric utility industry.  Legislation
resulting from this committee required the IPUC to begin an
investigation into the unbundling of costs into its various
delivery and energy components.  IPC filed cost unbundling studies
in July and December 1997.  The IPUC compiled cost data presented
by all the electric utilities and presented that information to
the legislature.  Although the committee will continue studying a
variety of restructuring ideas, it is not expected to recommend
restructuring legislation in the foreseeable future.

In response to the changing electric utility industry, IPC has
adjusted its resource acquisition policy to emphasize resource
marketability. IPC 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 IPC's
requirements.  In practice, this policy will result in the
purchase of power from others through the marketplace when purchases are
the lowest cost resources, and new investment in resource ownership by
IPC only when a Company-owned resource would be cost effective.

With a predominantly hydroelectric base and low-cost thermal
plants, IPC 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, IPC has access to
all the major electric systems in the West.


FUEL
IPC, through Idaho Energy Resources Co., owns a one-third interest
in the Bridger Coal Company, which owns the Jim Bridger coal mine
supplying coal to the Jim Bridger generating plant in Wyoming.
The mine, located near the Jim Bridger plant, operates under a long-
term sales agreement that provides for delivery of coal over a 51-
year period ending in 2025 (See Item 2 "Properties").  The Jim
Bridger coal mine has sufficient reserves to provide coal
deliveries pursuant to the sales agreement.  IPC 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 IPC is a ten-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 IPC to take advantage of lower-cost spot market coal for some or
all of the Boardman plant's requirements.

SPPCo, with whom IPC 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 1981 with Southern Utah Fuel Company, a subsidiary of Canyon
Fuel Co., LLC, for the delivery of up to 17.5 million tons of low-
sulfur coal from a mine near Salina, Utah, for Valmy Unit No. 1.

With the commercial operation of Valmy Unit No. 2 in May 1985, an
additional coal source was needed to assure an adequate supply for
both units at the Valmy plant.  Accordingly, in 1986 the Company
and SPPCo signed a long-term coal supply agreement with the Black
Butte Coal Company.  This contract provides for Black Butte to
supply coal to the Valmy project under a flexible delivery
schedule that allows for variations in the number of tons to be delivered
ranging from a minimum of 300,000 tons per year to a maximum of
1,000,000 tons per year.  This flexibility accommodates
fluctuations in energy demand, hydroelectric generating conditions
and purchases of energy from CSPP facilities.


WATER RIGHTS
Except as discussed below, IPC has acquired valid water rights
under applicable state law for all waters used in its
hydroelectric generating facilities.  In addition, IPC 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,
IPC'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 IPC's water rights at certain
hydroelectric generating facilities.  In reaction to these
reductions, IPC initiated and continues to pursue a course of
action to determine and protect its water rights.  As part of this
process, IPC and the state of Idaho signed the Swan Falls
agreement on October 25, 1984, which provided a level of protection for
IPC'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 IPC'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 IPC's
project licenses that the relationship established by the agreement would
not be considered by the FERC as being inconsistent with the terms
of IPC'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 IPC'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.  IPC 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.  IPC does not anticipate any
modification of its water rights as a result of the adjudication
process.


REGULATION
IPC is under the regulatory jurisdiction (as to rates, service,
accounting and other general matters of utility operation) of the
FERC, the IPUC, the Oregon Public Utility Commission (OPUC) and
the Public Service Commission of Nevada.  IPC is also under the
regulatory jurisdiction of the IPUC, OPUC and the Public Service
Commission of Wyoming as to the issuance of securities.  IPC is
subject to the provisions of the Federal Power Act as a "licensee"
and "public utility" as therein defined.  IPC'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 IPC's purchase of power from CSPP facilities.

As a licensee under the Federal Power Act, IPC and its licensed
hydroelectric projects are subject to the provisions of Part I of
the Act.  All licenses are subject to conditions set forth in the
Act and related FERC regulations.  These conditions and
regulations include provisions relating to condemnation of a project upon
payment of just compensation, amortization of project investment
from excess project earnings, possible takeover of a project after
expiration of its license upon payment of net investment,
severance damages, and other matters.

The state of Oregon has a Hydroelectric Act providing for
licensing of hydroelectric projects in that state.  IPC's Brownlee, Oxbow
and Hells Canyon facilities are on the Snake River where it forms the
boundary between Idaho and Oregon and occupy land located in both
states.  With respect to project property located in Oregon, these
facilities are subject to the Oregon Hydroelectric Act.  IPC has
obtained Oregon licenses for these facilities and these licenses
are not in conflict with the Federal Power Act or IPC'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 IPC's operations due to
the cost of installation and operation of equipment required for
compliance with such controls and the modification of system
operations to accommodate such regulation.

Based upon present environmental laws and regulations, IPC
estimates its capital expenditures (excluding allowance for funds
used during construction) for environmental matters for 1999 and
during the period 2000-2003 will total approximately $9.5 million
and $48.0 million, respectively.  Mitigation of environmental
concerns due to relicensing of hydro facilities will be a major
portion of these expenditures.  IPC anticipates incurring
approximately $23.8 million annually of operating expenses for
environmental facilities during the period 1999-2003, based upon
present environmental laws and regulation.

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

On July 16, 1997, the EPA announced new National Ambient Air
Quality Standards for ozone and Particulate Matter (PM).  In addition to
these standards, on July 17, 1997, the EPA proposed regional haze
regulations for protection of visibility in national parks and
wilderness areas.  Impacts of the ozone and PM regulations and the
proposed regional haze regulations on IPC's thermal operations are
unkown at this time.

Although not presently required to meet any federal nitrogen oxide
(NOx) limits, North Valmy, Boardman, and Jim Bridger Unit 4
elected to meet Phase I NOx limits beginning in 1998.  As a result of this
voluntary "early election" these units will not be required to
meet the more restrictive Phase II NOx limits until 2008.  Had the
units not voluntarily "early elected," they would have been required to
meet the Phase II NOx beginning in 2000.  Jim Bridger Units 1, 2
and 3 were accepted as substitution units in 1995 and subject to
NOx limits of Phase I instead of the more restrictive limits of
Phase II.  Jim Bridger is in the process of installing low NOx
burners to reduce NOx levels even lower than currently required.

     Water -
IPC 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.

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

IPC 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.  IPC 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.

IPC 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, IPC sponsors ongoing programs for the control of fish
disease and improvement of fish production.  IPC's anadromous fish
facilities at Hells Canyon, Oxbow, Rapid River, Pahsimeroi and Niagara
Springs continue to be operated under agreements with the Idaho Department
of Fish and Game.  At December 31, 1998, the investment in these
facilities was $12.2 million and the annual cost of operation
pursuant to FERC License 1971 was $2.4 million for 1998.

     Endangered Species -
Several species of salmon and Snake River mollusks living within
IPC's operating area are listed as threatened or endangered.  IPC
continues to review and analyze the effect such designation has on
its operations.  IPC is cooperating with various governmental
agencies to resolve issues related to these species.  (See Part
II, Item 7. "Management's Discussion and Analysis of Financial
Condition and Results of Operation - Environmental Issues".)

     Hazardous/Toxic Wastes and Substances -
Under the Toxic Substances Control Act (TSCA), the Environmental
Protection Agency (EPA) has adopted regulations governing the use,
storage, inspection and disposal of electrical equipment that
contain polychlorinated biphenyls (PCBs).  The regulations permit
the continued use and servicing of certain electrical equipment
(including transformers and capacitors) that contain PCBs.  IPC
continues to meet all federal requirements of TSCA for the
continued use of equipment containing PCBs.  IPC has a program to
make the 200-plus substations on its system non-PCB.  While IPC's
use of equipment containing PCBs falls well within the federal
standards, IPC has voluntarily decided to virtually eliminate
these compounds from its substation sites.  This program will save costs
associated with the long-term monitoring and testing of substation
equipment and grounds for PCB contamination as well as being good
for the environment today.  Total IPC costs for the disposal of
PCBs from the Company's system were $0.9 million, $1.0 million and
$0.5 million  for 1996, 1997 and 1998 respectively.  All
generation facilities are presently non-PCB.  IPC anticipates that all of its
substations, except for capacitors, will be non-PCB by the end of
1999.


RATES

     Idaho Jurisdiction
The May 1998 adjustment to rates includes the deferred costs from
the 1997-98 PCA year as well as the difference between base power
supply cost assumptions and forecasted power supply costs.  The
1998-99 forecast assumed a return to more normal hydroelectric
generating conditions.  This resulted in forecasted net power
supply costs being near the amounts used to establish base rates
in past regulatory proceedings.  The May 1998 rate adjustment
increases expected annual revenue by $34.0 million above the
amount that would have been received at the 1997 rates, and $17.3 million
above what would be expected at base rates during this rate
period.

So far in the current rate period, actual power costs have been
less than forecast, due to better than forecast hydroelectric
generating conditions.  We have recorded a reduction to regulatory
assets of $10.4 million as of December 31, 1998.  The variance
that exists at the end of the 1998-99 rate period will be trued-up in
the next annual PCA adjustment.

The May 1996 PCA adjustment decreased Idaho jurisdictional PCA
rates 5.9%.  IPC's May 1997 PCA adjustment, combined with the
revenue sharing mechanism described below, decreased rates an
additional 0.63%.

On August 3, 1995, IPC filed a proposal with the IPUC to support
IPC's organizational redesign.  In response to IPC's proposal, the
IPUC approved a Settlement that authorizes IPC to defer and
amortize costs related to reorganization in return for a general
rate freeze through the end of 1999.  The Settlement gives IPC
time to pursue and to implement its efficiency and growth initiatives
with the assurance of a reasonable level of financial performance
without the need to change customer prices.

Under the Settlement, which remains in effect through 1999, when
IPC's actual annual earnings exceed an 11.75 percent return on
year-end common equity for the Idaho jurisdiction, IPC will share 50
percent of the additional earnings with its Idaho retail
customers.  IPC set aside approximately $4.9 million and $7.6 million
in 1996 and 1997 respectively for the benefit of its Idaho customers.  Of
the $4.9 million set aside in 1996, $1.4 million was applied
against the regulatory asset balance of Idaho demand-side
management/conservation (DSM) expenditures while the remaining
$3.5 million was refunded.  Of the  $7.6 million set aside in 1997,
$3.0 million was applied against the DSM regulatory asset balance, $2.7
million was used to fund (through May 15, 1999) a DSM-related rate
increase, $0.8 million to recover 1997 Northwest Energy Efficiency
Alliance (NEEA) expenditures, and the remainder was held in
reserve to fund 1998 NEEA expenses once they have been approved for
recovery by the IPUC.  IPC has set aside approximately $5.4
million in 1998 for the benefit of its Idaho customers.  The ultimate
disposition of this benefit is yet to be determined.

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.  IPC has received approval from the Idaho State Tax
Commission and the Internal Revenue Service on the accounting treatment
for the tax credits up to a maximum of $30 million of ADITC's.  As of
December 31, 1998, no ADITCs have been used under the regulatory
agreement.

Other important points in the Settlement are that IPC will not be
allowed to increase its Idaho general rates prior to January 1,
2000, except under special conditions as defined in the
Settlement, and that the Company agrees that its quality of service will not
decline as a result of corporate reorganization.

In 1998, IPC received an order from the IPUC reducing the
amortization period for the regulatory assets associated with
demand-side management programs from 24 years to 12 years.  At the
same time the IPUC approved an additional $16 million of Idaho
allocated demand-side management expenditures for recovery through
rates resulting in an increase of 0.67 percent to Idaho customers
effective May 16, 1999.  At present this increase is being funded
through amounts set aside for 1997 customer revenue sharing.  The
IPUC order has been appealed to the Idaho Supreme Court by a
customer group.

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


     Other Jurisdictions -
In 1998, IPC received authority from the OPUC to reduce the
amortization period for the regulatory assets associated with
demand-side management programs from 24 years to five years.  The
OPUC also approved additional Oregon allocated demand-side
management expenditures for recovery through rates.  The Oregon
costs will be recovered by extending an existing surcharge until
the amounts are collected.

In 1997, IPC did not file any applications for rate relief before
the FERC or in its Oregon or Nevada retail jurisdictions.  In July
1996, IPC 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 1999-2003 period
(excluding allowances for funds used during construction) is
presently estimated to require cash funds of approximately $642.4
million as follows:



                                   1999    2000-2003 (a)
                                   (Millions of Dollars)
Generating Facilities:
  Hydro                            $14.2     $65.2
  Thermal                            6.5      30.3
Total generating facilities         20.7      95.5
Transmission lines and
substations                         18.1      62.5
Distribution lines and
substations                         43.4     198.3
General                             28.4      53.7
  Total cash construction - IPC    110.6     410.0
Other                                4.9     116.9
   Total IDACORP                  $115.5    $526.9

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


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



FINANCING PROGRAM
The five-year estimates of capital requirements and sources of
capital are outlined in the following tables:


                                 IDACORP, Inc.         Idaho Power
Company
                                1999    2000-2003     1999   2000-2003
                                            (Millions of Dollars)

Capital Requirements:
  Net cash construction
expenditures                     $115.5    $526.9     $110.6   $410.0
  Conservation expenditures         1.9       0.0        1.9      0.0
  Other cash expenditures           3.8       4.8        3.8      4.8
   Total                         $121.2    $531.7     $116.3   $414.8
Sources of Capital:
  Internal generation            $ 94.4    $518.7     $ 94.2   $468.5
  Short-term bank loans - Net      23.4       3.8       19.2      5.0
  First mortgage bonds             (0.1)      9.5        0.0    (58.4)
  Debt repayment                   (0.1)     (0.3)      (0.1)    (0.3)
  Common stock                      0.0       0.0        0.0      0.0
  Cash investments (increase)       3.5       0.0        3.0      0.0
  Total                          $121.2    $531.7     $116.3   $414.8


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.  The Company
will continue to take advantage of any refinancing opportunities
as they become available.

Under the terms of the Indenture relating to IPC'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, 1998, net earnings were 6.40 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, 1998, the actual preferred
dividend earnings coverage was 3.15 times.  If the dividends on
the shares of Auction Preferred Stock were to reach the maximum
allowed, the preferred dividend earnings coverage would be 2.88
times.  The Indenture and IPC'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

IPC's system includes 17 hydroelectric generating plants located
in southern Idaho and eastern Oregon (detailed below) and an interest
in three coal-fired steam electric generating plants.  The system
also includes approximately 4,644 miles of high voltage
transmission lines; 21 step-up transmission substations located at
power plants; 17 transmission substations; 7 transmission
switching stations; and 205 energized distribution substations (excludes
mobile substations and dispatch centers).

IPC 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
        Project                 Operating          Nameplate        License
                                Capacity kW        Capacity kW
Expiration

Properties Subject to
Federal Licenses:
     Lower Salmon                70,000             60,000          1997 (a)
     Bliss                       80,000             75,000          1998 (a)
     Upper Salmon                39,000             34,500          1998 (a)
     Shoshone Falls              12,500             12,500          1999
     C J Strike                  89,000             82,800          2000
     Upper Malad                  9,000              8,270          2004
     Lower Malad                 15,000             13,500          2004
     Brownlee-Oxbow-Hells
        Canyon                1,398,000          1,166,900          2005
     Swan Falls                  25,547             25,000          2010
     American Falls             112,420             92,340          2025
     Cascade                     14,000             12,420          2031
     Milner                      59,448             59,448          2038
     Twin Falls                  54,300             52,737          2041
Other Generating Plants:
     Other Hydroelectric         10,400             11,300
     Jim Bridger (coal-
         fired station)         708,333            709,617
     Valmy (coal-fired
         station)               260,650            260,650
     Boardman (coal-fired
         station)                53,000             56,050

 (a)Renewed on a year-to-year basis; application for relicense
pending.


At December 31, 1998, the composite average ages of the principal
parts of IPC's system, based on dollar investment, were:
production plant, 18.8 years; transmission system and substations, 19.0
years; and distribution lines and substations, 15.1 years.  IPC considers
its properties to be well maintained and in good operating
condition.

IPC owns in fee all of its principal plants and other important
units of real property, except for portions of certain projects
licensed under the Federal Power Act and reservoirs and other
easements.  IPC's property is also subject to the lien of its
Mortgage and Deed of Trust and the provisions of its project
licenses.  In addition, IPC's property is subject to minor defects
common to properties of such size and character that do not
materially impair the value to, or the use by, IPC 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 IPC is the
relicensing of its hydro facilities.  The relicensing of these
projects is not automatic under federal law.  IPC 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 IPC continuing to hold
the federal licenses.  IPC is actively pursuing the relicensing of
its hydroelectric projects, a process that will continue for the
next 10 to 15 years.  IPC submitted its first applications for
license renewal to the FERC in December 1995, seeking renewal of
IPC's licenses for its Bliss, Upper Salmon Falls and Lower Salmon
Falls hydroelectric projects.  In May 1997 IPC submitted its
application for its Shoshone Falls project.  IPC also submitted an
application for license renewal for its C J Strike hydroelectric
project on November 24, 1998.  Although various federal
requirements and issues must be resolved through the license
renewal process, IPC anticipates that its efforts will be
successful.  At this point, however, IPC cannot predict what type
of environmental or operational requirements it may face, nor can
it estimate the eventual cost of licensing renewal.

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

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



ITEM 3.  LEGAL PROCEEDINGS

On November 30, 1995, a complaint entitled Idaho Power Company vs.
Cogeneration, Inc., Case No. 98467, was filed by IPC in the
District Court of the Fourth Judicial District of the State of
Idaho.  The proceeding involves an effort by IPC 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, IPC 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, IPC 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 IPUC
order and has never posted the $1.9 million amount required by the
FESA.

After the IPUC's order became final and non-appealable, IPC 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.  IPC asked the district court to find that
as a matter of law IPC was entitled to either terminate or rescind
the FESA.

In response to IPC's complaint, Cogeneration, Inc. filed
counterclaims alleging that IPC, 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
IPC was entitled to either rescind or terminate the FESA.

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

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

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

Following a court trial, on June 24, 1998 the District Court
issued a   memorandum  decision  finding  that  Cogeneration,   Inc.
had materially  breached  the  FESA and as a result  IPC  had
properly terminated the FESA.

On  July 27, 1998, Cogeneration, Inc. filed a Notice of Appeal
with the Idaho Supreme Court.

Cogeneration,  Inc. filed its opening brief in  the  Idaho
Supreme Court on February 16, 1999.  IPC's brief is due March 16, 1999.
It is  likely  that oral argument will be set during the court's
fall term.

This  matter has been previously reported in IPC's Form 10-K
dated March 12, 1998, and other IPC reports filed with the Securities
and Exchange Commission.





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

     None



EXECUTIVE OFFICERS OF THE REGISTRANTS


     The names, ages and positions of all of the executive
officers of  IDACORP,  Inc. and Idaho Power 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.

                           IDACORP, Inc.

Name, Age and Position     Business Experience During Past Five
                           (5) Years*
Joseph W. Marshall, 60     Appointed February 2, 1998.
Chairman of the Board and
Chief Executive Officer

Jan B. Packwood, 55        Appointed February 2, 1998.
President and Chief
Operating Officer

J. LaMont Keen, 46         Appointed February 2, 1998.
Vice President, Chief
Financial Officer
and Treasurer

Richard Riazzi, 44         Appointed January 14, 1999.
Vice President -
Marketing and Sales

Robert W. Stahman, 54      Appointed February 2, 1998.
Vice President, General
Counsel and Secretary


*IDACORP,  Inc. executive officers serve in the same capacities
at Idaho Power Company. For these officers business experience,
during the past five years, please refer to the next table.

                        Idaho Power Company

Name, Age and Position     Business Experience During Past Five
                           (5) Years
Joseph W. Marshall, 60     Appointed August 18, 1989.
Chairman of the Board and
Chief Executive Officer

Jan B. Packwood, 55        Appointed September 1, 1997.  Mr.
President and Chief        Packwood was Executive Vice President
Operating Officer          from July 11, 1996, to September 1,
                           1997, and Vice President-Power Supply
                           prior to July 11, 1996.

J. LaMont Keen, 46         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.

Kip W. Runyan, 48          Appointed August 1, 1997.  Mr. Runyan
Vice President - Delivery  was CEO of Ida-West Energy Company
                           prior to August 1, 1997.
Richard Riazzi, 44         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.

James C. Miller, 44        Appointed July 10, 1997.  Mr. Miller
Vice President -           was General Manager - Generation
Generation                 prior to July 10, 1997.

Cliff N. Olson, 49         Appointed July 11, 1991.
Vice President -Corporate
Services

Robert W. Stahman, 54      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

IDACORP, Inc.'s common stock (without par value) is traded on the
New York and Pacific Stock Exchanges.  At December 31, 1998, there
were 25,307 holders of record and the year-end stock price was $36
3/16 per share.  The outstanding shares of Idaho Power Company
common stock ($2.50 par value) are held by IDACORP, Inc. and are
not traded.

The following table shows the reported high and low sales price
and dividends paid for the years 1998 and 1997 as reported by the Wall
Street Journal as composite tape transactions.  IDACORP, Inc.
became the holding company of Idaho Power Company on October 1,
1998.  Amounts reported for periods prior to October 1, 1998, were
for Idaho Power Company only.


                                           1998 Quarters
Common Stock, without par value:      1st     2nd        3rd     4th
   High                            $38 1/16  $37 7/8    $35       $36 1/4
   Low                              33 15/16  32 15/16   29 7/8    31 1/8
   Dividends paid per share (cents) 46.5      46.5       46.5      46.5


                  ______________________________


                                           1997 Quarters
Common Stock, without par value:      1st     2nd       3rd       4th
   High                            $31 7/8   $31 1/2    $32 13/16 $37 3/4
   Low                              29 3/4    28 1/2     31        30 5/16
   Dividends paid per share (cents) 46.5      46.5       46.5      46.5


ITEM 6.  SELECTED FINANCIAL DATA


SUMMARY OF OPERATIONS (Thousands of Dollars except for per share amounts)
IDACORP, Inc.
                            1998       1997       1996       1995       1994
For the Years Ended
December 31,

Operating revenues      $1,121,976  $ 748,503  $ 578,445  $ 545,621  $ 543,658
Income from operations     191,221    184,749    187,171    175,991    149,665
Net income                  89,176     87,098     83,155     78,930     67,532
Earnings per average
  common share
  outstanding (basic and
  diluted)                    2.37       2.32       2.21       2.10       1.80
Dividends declared per
share                         1.86       1.86       1.86       1.86       1.86

At December 31,
Total long-term debt*   $  815,937  $ 746,142  $ 769,810  $ 672,618  $ 693,206
Total assets             2,451,620  2,451,816  2,328,738  2,241,753  2,191,816

*Excludes amount due within one year.

The above data should be read in conjunction with IDACORP's
consolidated financial statements and notes to consolidated
financial statements included in this Annual Report on Form 10-K.



SUMMARY OF OPERATIONS (Thousands of Dollars except for per share
amounts and customer data)
IDAHO POWER COMPANY
                            1998       1997       1996       1995       1994
For the Years Ended
December 31,

Operating revenues      $1,121,976  $ 748,503  $ 578,445  $ 545,621  $ 543,658
Income from operations     191,221    184,749    187,171    175,991    149,665
Net income                  95,919     92,274     90,618     86,921     74,930

At December 31,
Total long-term debt*   $  815,937  $ 746,142  $ 769,810  $ 672,618  $ 693,206
Total assets             2,421,790  2,451,816  2,328,738  2,241,753  2,191,816

Utility Customer Data:
General business
customers                  373,730    363,085    352,487    340,708    330,308
Average Kwh per customer    36,368     37,080     37,627     35,740     37,616
Average rate per Kwh          3.85       3.63       3.71       3.85       3.75


*Excludes amount due within one year.

The above data should be read in conjunction with Idaho Power
Company's consolidated financial statements and notes to
consolidated financial statements included in this Annual Report
on Form 10-K.


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

In Management's Discussion and Analysis we explain the general
financial condition and results of operations of IDACORP, Inc. and
its subsidiaries (IDACORP or the Company).  IDACORP is a holding
company formed in 1998 as the parent of Idaho Power Company (IPC),
Ida-West Energy Company, and IDACORP Energy Solutions, Inc. IPC,
an electric utility, is IDACORP's principal operating subsidiary, and
accounts for over 90 percent of our assets, revenue and net
income. The financial condition and results of operations of IPC are
currently the principal factors affecting the financial conditions
and results of operations of IDACORP.

As you read Management's Discussion and Analysis, it may be
helpful to refer to our Consolidated Statements of Income which present
our results of operations for the years ended December 31, 1998, 1997
and 1996.  In our discussion we explain the significant annual
changes between specific line items in the Consolidated Statements
of Income.


FORWARD-LOOKING INFORMATION
In connection with the safe harbor provisions of the Private
Securities Litigation Reform Act of 1995 (Reform Act), we are
hereby filing cautionary statements identifying important factors
that could cause our actual results to differ materially from
those projected in forward-looking statements (as such term is defined
in the Reform Act) made by or on behalf of the Company in this Annual
Report, quarterly report on Form 10-Q, in presentations, in
response to questions or otherwise.  Any statements that express,
or involve discussions as to expectations, beliefs, plans,
objectives, assumptions or future events or performance (often,
but not always, through the use of words or phrases such as
"anticipates", "believes", "estimates", "expects", "intends",
"plans", "predicts", "projects", "will likely result", "will
continue", or similar expressions) are not statements of
historical facts and may be forward-looking.  Forward-looking statements
involve estimates, assumptions, and uncertainties and are
qualified in their entirety by reference to, and are accompanied by, the
following important factors, which are difficult to predict,
contain uncertainties, are beyond our control and may cause actual
results to differ materially from those contained in forward-
looking statements:

  prevailing  governmental policies and regulatory actions,
  including those of the Federal Energy Regulatory Commission
  (FERC), the Idaho Public Utilities Commission (IPUC), the Oregon Public
  Utilities Commission (OPUC), and the Public Utilities Commission
  of Nevada (PUCN), with respect to allowed rates of return, industry
  and rate structure, acquisition and disposal of assets and
  facilities, operation and construction of plant facilities,
  recovery of purchased power and other capital investments, and
  present or prospective wholesale and retail competition
  (including but not limited to retail wheeling and transmission costs):

  economic and geographic factors including political and
  economic risks;

  changes in and compliance with environmental and safety laws
  and policies;

  weather conditions;

  population growth rates and demographic patterns;

  competition for retail and wholesale customers;

  Year 2000 issues;

  pricing and transportation of commodities;

  market demand, including structural market changes;

  changes in tax rates or policies or in rates of inflation;

  changes in project costs;

  unanticipated changes in operating expenses and capital
  expenditures;

  capital market conditions;

  competition for new energy development opportunities; and

  legal and administrative proceedings (whether civil or
  criminal) and settlements that influence the business and
  profitability of the Company.

Any forward-looking statement speaks only as of the date on which
such statement is made, and we undertake no obligation to update
any forward-looking statement to reflect events or circumstances
after the date on which such statement is made or to reflect the
occurrence of unanticipated events.  New factors emerge from time
to time and it is not possible for management to predict all such
factors, nor can it assess the impact of any such factor on the
business or the extent to which any factor, or combination of
factors, may cause results to differ materially from those
contained in any forward-looking statement.

RESULTS OF OPERATIONS
Earnings per Share and Book Value
Earnings per share of common stock (basic and diluted) were $2.37
in 1998, $2.32 in 1997, and $2.21 in 1996.  The 1998 earnings
equate to a 12.2 percent return on year-end common equity, as
compared to 12.2 percent in 1997 and 12.0 percent in 1996.  At
December 31, 1998, the book value per share of common stock was
$19.42, compared to $18.93 at December 31, 1997 and $18.47 at
December 31, 1996.

Overview
A number of factors have contributed to the increase in earnings
per share over the last three years, including excellent
hydroelectric generating conditions, a strong service territory
economy, and continued cost management.

IPC's service territory experienced above average water years from
1996-1998.  Hydro generation was 22 percent above normal in 1998,
30 percent above normal in 1997, and 18 percent above normal in
1996.

Idaho's economy continued its strong performance over the last
three years.  Idaho's non-agricultural employment growth for the
twelve months ended November 1998 was 2.2 percent; annual growth
rates in 1997 and 1996 were 3.2 percent and 3.3 percent,
respectively.  Within the Boise Metropolitan Statistical Area, the
heart of IPC's service territory, non-agricultural employment
increased 2.3 percent for the twelve months ended November 1998,
4.2 percent in 1997 and 3.9 percent in 1996.

General business customer growth continued in 1998, with a 2.9
percent increase, compared with a 3.0 percent increase in 1997 and
3.5 percent increase in 1996.  This growth is attributable to
strong overall economic conditions in our service territory.

Operating revenues increased $373.5 million in 1998, and $170.1
million in 1997, due primarily to increased sales in the wholesale
electricity markets, increased rates, customer growth, and weather
conditions in our service territory.

As part of a regulatory settlement, IPC set aside approximately
$5.4 million in 1998, $7.6 million in 1997, and $4.9 million in
1996 for the benefit of our Idaho customers.  We discuss the
regulatory settlement below in "Regulatory Issues - Regulatory
Settlement."

Total operating expenses increased $367.0 million in 1998 and
$172.5 million in 1997, due primarily to increased purchases in
wholesale electricity markets, and increased purchased power and
fuel costs resulting from increased sales.

Income taxes decreased $7.4 million from 1996 through 1998, due
primarily to an increase in tax credits earned from increasing
investments in affordable housing projects.

General Business Revenue
Our general business revenue is dependent on many factors,
including the number of customers we serve, the rates we charge,
and weather.  The $34.4 million increase in general business
revenue in 1998 is due primarily to the annual change to the power
cost adjustment component of retail electric rates, other rate
adjustments, and to the 2.9 percent increase in general business
customers.  We discuss the power cost adjustment below in
"Regulatory Issues - Power Cost Adjustment."

The $3.7 million decrease in general business revenue in 1997 is
due primarily to rate decreases, more moderate temperatures and
increased precipitation, which reduced average irrigation customer
energy sales by 8.2 percent and average residential customer
energy sales by 1.2 percent.  Precipitation increased 37.1 percent during
the 1997 growing season, compared to 1996, and heating and cooling
degree days, a common measure used in the electric utility
industry to analyze usage, decreased by 3.3 percent in 1997.  These factors
were partially offset by a 3.0 percent increase in the number of
general business customers.

Off-System Sales
Off-system sales are comprised of sales in the wholesale
electricity markets, long-term contracts, and opportunity sales
made when market prices make it cost-effective.  The volume and
price of these latter sales depend on our firm energy demand,
hydroelectric generating conditions in our service territory, and
market conditions throughout the western United States.

Off-system sales increased $336.1 million in 1998 and $173.7
million in 1997.  These increases relate primarily to increases in
the market price of electricity and sales in the wholesale
electricity markets.  Off-system MWh sales increased 86 percent in
1998 and 201 percent in 1997.  Increases in market prices
increased our average price per MWh sold by 28 percent in 1998 and 16
percent in 1997.

Expenses
Purchased power expense increased $321.0 million in 1998 and
$150.2 million in 1997 due primarily to an increase in purchases in the
wholesale electricity markets.  Total MWhs of purchased power
increased 113 percent in 1998 and 213 percent in 1997.  These
increases reflect our increased focus on the wholesale electricity
markets and the availability of low cost energy resulting from the
abundance of hydro generation in the West.

Fuel expense increased by $15.0 million in 1998 and $7.9 million
in 1997 due primarily to increased generation at our coal-fired
plants to take advantage of off-system sales opportunities.  Total
generation at the coal-fired plants was approximately 6.9 million
MWhs in 1998, 5.4 million MWhs in 1997 and 4.8 million MWhs in
1996.

The PCA mechanism increases expenses when power supply costs are
below forecast, and decreases expenses when power supply costs are
above forecast.  In 1998, the PCA expense increased $27.9 million
because our 1998 power supply costs were well below the forecast,
where in 1997 they were somewhat above the forecast.  The 1998
forecast had anticipated near-normal streamflow conditions in the
1998-9 rate period, but conditions have been significantly better
than normal.  We discuss the PCA in more detail in "Regulatory
Issues - Power Cost Adjustment."

The increases in other operation expenses in 1998 and 1997 were
due primarily to increased payroll and benefits and increased
transmission charges for electricity sold.

Maintenance expenses decreased $6.9 million in 1998 and increased
$6.0 million in 1997.  The decrease in 1998 results from decreased
maintenance expense at our steam generation facilities and
distribution facilities.  The 1997 increase is due to extensive
maintenance at our steam generation facilities due to increased
utilization, and repairs to hydro facilities and distribution
facilities damaged by natural causes.

Other Income
Other income decreased $6.2 million in 1998 due primarily to costs
incurred by new subsidiaries and costs of other diversified
business activities.  These subsidiaries and activities were
created to compete in the non-regulated business environment.

Income Taxes
Income taxes decreased $1.8 million in 1998 and $5.6 million in
1997.  The decrease in 1998 is due primarily to an increase in
affordable housing tax credits.  The decrease in 1997 is due
primarily to an increase in affordable housing tax credits and
decreased net income before taxes.

Regulatory Issues

     Power Cost Adjustment (PCA)
IPC has a PCA mechanism that provides for annual adjustments to
the rates we charge to our Idaho retail customers.  These adjustments,
which take effect annually on May 16, are based on forecasts of
net power supply costs and the true-up of the prior year's forecast.
The difference between the actual costs incurred and the
forecasted costs is deferred, with interest, and trued-up in the next annual
rate adjustment.

The May 1998 adjustment to rates includes the deferred costs from
the 1997-98 PCA year as well as the difference between base power
supply cost assumptions and forecasted power supply costs.  The
1998-99 forecast assumed a return to more normal hydroelectric
generating conditions.  This resulted in forecasted power supply
costs being near the amounts used to establish base rates in past
regulatory proceedings.  The May 1998 rate adjustment increases
expected annual revenue by $34.0 million over the amount that
would have been received at the 1997 rates, and $17.3 million over what
would be recovered if we were charging the base rates during this
rate period.

So far in the current rate period, actual power costs have been
less than forecast, due to better than forecast hydroelectric
generating conditions.  We have recorded a reduction to regulatory
assets of $10.4 million as of December 31, 1998.  The variance
that exists at the end of the 1998-99 rate period will be trued-up in
the next annual PCA adjustment.

     Regulatory Settlement
IPC has a settlement agreement with the IPUC that remains in
effect through 1999.  Under the terms of the settlement, when our actual
earnings in a given year exceed an 11.75 percent return on year-
end common equity for the Idaho jurisdiction, we will set aside 50
percent of the excess for the benefit of our Idaho retail
customers.  In 1998, we set aside $5.4 million for the benefit of
our Idaho customers, compared to $7.6 million in 1997 and $4.9
million in 1996.  We requested that approximately $5.0 million of
the 1997 earnings sharing amount be applied against the balance of
deferred demand-side conservation expenditures in order to defer
any rate increases associated with the conservation recovery until
May 16, 1999, the same date as the next PCA adjustment.

In addition, the settlement allows for the accelerated
amortization of regulatory liabilities associated with accumulated deferred
investment tax credits (ADITCs), up to a maximum of $30 million,
to provide a minimum 11.50 percent return on actual year-end common
equity for the Idaho jurisdiction.

We have received approval from the Idaho State Tax Commission and
the Internal Revenue Service on the accounting treatment for the
tax credits.  As of December 31, 1998, no ADITCs have been used
under the regulatory agreement.

Other important points in the settlement are that we will not be
allowed to increase our Idaho general rates prior to January 1,
2000, except under special conditions as defined in the Settlement
Agreement, and that we agree that our quality of service will not
decline as a result of corporate reorganization.

     Demand-Side Management (Conservation) Expenses
We are seeking changes to the regulatory treatment of previously
deferred demand-side management (DSM) expenses in both Idaho and
Oregon.

In Idaho, we requested the IPUC to authorize recovery of post-1993
DSM expenses and acceleration of the recovery of DSM expenditures
authorized in the last general rate case.  We requested a five-
year amortization instead of the 24-year period previously adopted.  In
its Order No. 27660 issued on July 31, 1998, the IPUC set a new
amortization period of 12 years.  The IPUC order reflects an
increase in annual Idaho retail revenue requirements of $3.1
million for 12 years.

As noted above, we are funding the annual revenue requirement with
revenue sharing amounts until May 16, 1999.  A group of our
industrial customers has appealed the IPUC order to the Idaho
Supreme Court.

In December 1998 we filed with the IPUC, a request to recover our
remaining deferred DSM expenditures of approximately $2.0 million.
The IPUC has set this case for hearing in March 1999.  In our
filing we requested that the amount be applied against 1998
earnings sharing amounts.

In Oregon, the OPUC authorized the amortization of the Oregon-
allocated share of the DSM expenditures over five years.  The DSM
charge replaces an expiring rate surcharge related to
extraordinary power supply costs associated with past drought conditions.
We anticipate that the charge will recover approximately $540,000 per
year.

     Ida-West Energy Company
Ida-West Energy Company, a wholly owned subsidiary of IDACORP, was
formed in 1989 to develop, finance, construct, acquire, own and
operate electric power generation facilities.  Ida-West is
actively marketing new projects to utilities located in the West and is
seeking to acquire operating facilities and projects under
development throughout the United States and Canada.  Existing Ida-
West projects produced over 302,000 MWh's of energy in 1998.

In addition, Ida-West has an interest in the Hermiston Power
Project, a 536 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.
To date, we have invested $20 million in Ida-West.

     IDACORP Financial Services, Inc. (IFS)
IFS, a wholly owned subsidiary of IPC, participates in 12
affordable housing programs.  These investments provide a return
by reducing our federal income taxes and by assuring a return on
investment through tax credits and tax depreciation benefits.  To
date, we have invested $6.5 million in IFS.


LIQUIDITY AND CAPITAL RESOURCES

Cash Flow
Our net cash generated from operations totaled $508.6 million for
the three-year period 1996-1998.  After deducting common dividends
of $209.7 million, net cash generation from operations provided
approximately $298.9 million for our construction program and
other capital requirements.  Internal cash generation after dividends
provided 95 percent of our total capital requirements in 1998, 89
percent in 1997, and 74 percent in 1996.

In 1998, we increased our cash and cash equivalents by $12.2
million from life insurance death benefits and the surrender of
life insurance policies.

We forecast that internal cash generation after dividends will
provide approximately 80 percent of total capital requirements in
1999 and over 94 percent during the four-year period 2000-2003.
We expect to continue financing our construction program and other
capital requirements with both internally generated funds and, to
the extent necessary, externally financed capital.  Principal
amounts maturing during the forecast period are $6.0 million in
1999, $86.5 million in 2000, $36.9 million in 2001, $34.1 million
in 2002 and $86.5 million in 2003.

At January 1, 1999, IPC had regulatory authority to incur up to
$200.0 million of short-term indebtedness.  At December 31, 1998,
its short-term borrowing totaled $38.5 million compared to $57.5
million at December 31, 1997 and $54.0 million at December 31,
1996.

On December 19, 1996, IPC replaced its committed lines of credit
arrangements with a $120.0 million multi-year revolving credit
facility under which we pay a facility fee on the commitment,
quarterly in arrears, based on IPC's First Mortgage Bond Rating.

On December 21, 1998, IDACORP established a $100.0 million 364-day
credit facility which will expire December 19, 1999, and a $50.0
million 3-year credit facility which will expire December 21,
2001.  Under these facilities we will pay a facility fee on the
commitment, quarterly in arrears, based on IPC's First Mortgage
Bond Rating.  Commercial paper may be issued up to $150.0 million
and is supported by the bank credit facilities.  (See Note 7 of
"Notes to Consolidated Financial Statements").

Construction Program
Our consolidated cash construction expenditures totaled $89.2
million in 1998, $95.6 million in 1997, and $93.6 million in 1996.
Approximately 27 percent of these expenditures were for generation
facilities, 14 percent for transmission facilities, 44 percent for
distribution facilities, and 15 percent for general plant and
equipment.  We estimate that our cash construction program will
require $115 million in 1999 and $527 million in the four-year
period 2000-2003.  These estimates are subject to revision in
light of changing economic, regulatory, environmental, and conservation
factors.

Financing Program
Our capital structure fluctuated slightly during the three-year
period, with common equity ending at 44 percent, preferred stock
(of IPC) seven percent, and long-term debt 49 percent at December
31, 1998.

IDACORP, Inc. currently has a $300.0 million shelf registration
statement that can be used for the issuance of unsecured debt
securities and preferred or common stock.  IDACORP also has
committed short-term credit arrangements totaling $150.0 million.
At December 31, 1998, none had been issued.

IPC 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.  In September 1998
IPC issued $60 million of Secured Medium Term Notes.  The proceeds
from this issuance were used to redeem at maturity $30 million of First
Mortgage Bonds, and to reduce the balance of commercial paper
issued in connection with ongoing business.

In 1996, IPC issued $57 million of Secured Medium Term Notes.  The
net proceeds were used for repayment of commercial paper issued in
connection with our ongoing construction program and to redeem
preferred stock.  These transactions have reduced the remaining
balance on the shelf registration to $83 million as of December
31, 1998.

In August 1996, IPC issued tax exempt Pollution Control Revenue
Refunding Bonds with a principal amount of $116.3 million.  The
proceeds were used to retire the $116.3 million of Pollution
Control Revenue Bonds due between 2003 and 2014.


OTHER MATTERS

Environmental Issues

     Salmon Recovery Plan
We are continuing to work 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.  We do
not anticipate that the new designation will have any major
effects on our operations.

In September 1991, we modified operations at our three-dam Hells
Canyon Hydroelectric Complex to protect the Fall Chinook
downstream during spawning and juvenile emergence.  From its start, our 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 our 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 our 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 called for 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 not complied 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 our power supply costs.  IPC
and the BPA have negotiated a five-year contract, expiring April
15, 2001, requiring BPA to replace lost energy and capacity
resulting from recovery plans that impact our power supply cost.

     Nez Perce Lawsuit
On March 21, 1997, the United States District Court for the
District of Idaho entered a judgment related to a civil lawsuit
filed against IPC in 1991 by the Nez Perce Tribe.  The suit arose
from the construction, maintenance, and operation of our three-dam
Hells Canyon Complex and the project's alleged impact both on fish
and the Tribe's treaty-reserved fishing rights.  The judgment,
which incorporated the terms of an agreement already reached by
IPC and the Tribe, requires us to pay the Nez Perce Tribe $11.5
million over five years.  All payments under the Agreement will be made in
1996 dollars, which allows for adjusted future inflation within a
minimum range of three percent and a maximum of seven percent.  As
of December 31, 1998, $4.9 million remains payable to the Tribe
over the next three years.

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 shares of the $11.5 million.

In connection with settling the litigation, IPC 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
our application to relicense the project, we 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 we must file our relicense application.
The Tribe will be entitled to earnings from investments on this
account until we accept or reject a new federal license for the
project.  If we accept the new federal license, the Tribe will
take ownership of the money in the account.  If we reject the license,
the money will be returned to us.  This settlement is provisional
because the Tribe retains the right to opt out of this relicensing
settlement at any time prior to our acceptance of a new federal
license.

     Threatened and Endangered Snails
In 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, we have included this possibility in
all of our 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
and their habitat.  Although the hydro facilities on that reach of
the Snake River do not significantly affect water levels during
typical operations, some of them do provide the daily operational
flexibility to meet increased electricity demand during high load
hours.  Recent studies suggest that this has no impact on the
listed snails.  While it is possible that the listing could affect
how we operate our existing hydroelectric facilities on the middle
reach of the Snake River, we believe that such changes will be
minor and will not present any undue hardship.

In 1995, as a part of our federal hydro relicensing process, we
obtained a permit from the USFWS to study the five species of
endangered Snake River snails.  Our biologists have completed
several studies 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.  Results of the
studies indicated that the snail colonies were part of a
biological community well adapted to the influences of hydropower, water
quality, and irrigation run-off.  Company-sponsored studies
continue to review how these and other factors affect the status
of the various colonies and their habitats.

     Clean Air Act
We have analyzed the Clean Air Act's effects on us and our
customers.  Our coal-fired plants in Oregon and Nevada already
meet the federal emission rate standards for sulfur dioxide (SO2) and
our coal-fired plant in Wyoming meets that state's even more
stringent SO2 regulations.  Therefore, we foresee no adverse
effects on our operations with regard to SO2 emissions.

     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 us and our operations.

Electric Industry Restructuring
Competition is increasing in the electric utility industry.  Our
goal is to anticipate and fully integrate into our operations any
legislative, regulatory or competitive changes.  We are pursuing a
rapid, but orderly transition to at least a partially and possibly
a totally deregulated environment in the years ahead.  The
following items describe some of the changes to date, as well as
steps we are taking.

     Legislative Actions
In 1997, the Idaho Legislature appointed a committee to study
restructuring of the electric utility industry.  Legislation
resulting from this committee required the IPUC to begin an
investigation into the unbundling of costs into its various
delivery and energy components.  We filed cost unbundling studies
in July and December 1997.  The IPUC compiled cost data presented
by all the electric utilities and presented that information to
the legislature.  Although the committee will continue studying a
variety of restructuring ideas, it is not expected to recommend
restructuring legislation in the foreseeable future.

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

In November 1995, we 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 we use in our own operations to anyone
seeking them.  We requested and received permission to implement
these tariffs beginning February 1, 1996.  On July 8, 1996, we
filed a new open-access transmission tariff to replace the 1995
tariffs.  This provides full compliance with Final Order No. 888.
This 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.

     Energy Trading
We intend to be a competitive energy provider, including both
electricity and natural gas.  In mid-1997, IPC opened a gas
trading office in Houston, Texas, to serve the southern and eastern United
States and a Boise, Idaho office to serve the Northwest and
Canadian markets.  We also participate in the western wholesale
electricity markets, the results of which are included in off-
system revenue and purchased power expense.

Inherent in the energy trading business are risks related to
market movements and the creditworthiness of counterparties.  When buying
and selling energy, the high volatility of energy prices can have
a significant impact on profitability if not managed.  Also,
counterparty creditworthiness is key to ensuring that transactions
entered into withstand dramatic market fluctuations.

To mitigate these risks while implementing our business strategy,
the IPC Board of Directors gave approval for executive management
to form a Risk Management Committee, comprised of Company
officers, to oversee a risk management program.  The program is intended to
minimize fluctuations in earnings while managing the volatility of
energy prices.  Embedded within the Risk Management policy and
procedures is a credit policy requiring ongoing evaluation of the
financial condition of counterparties, the securitization of
credit support where needed, and ongoing monitoring of credit exposure.
The objective of our risk management program is to mitigate
commodity price risk, credit risk, and other risks related to the
energy trading business.

Market Rate Sensitive Instruments and Risk Management
The following discussion summarizes the financial instruments,
derivative instruments and derivative commodity instruments
sensitive to changes in interest rates and commodity prices that
IPC held at December 31, 1998.  IPC buys and sells financial and
physical natural gas and electricity commodity contracts as part
of our ongoing business.  These contracts are subject to electricity
and natural gas commodity price risk.  We have a trading and risk
management policy defining the limits within which we contain our
commodity price risk.  We trade commodity futures, options and
swaps as a method of managing the commodity price risk associated
with electricity and natural gas trading.  We have minimal foreign
exchange exposure related to natural gas trading activities in
Canadian dollars.  This exposure is periodically offset through
the use of foreign exchange swap instruments.  Our sensitivity related
to foreign exchange rate fluctuations as of December 31, 1998, is
immaterial.

     Interest Rate Risk Sensitivity
This table presents descriptions of our financial instruments at
December 31, 1998, that are sensitive to changes in interest
rates.  We did not hold any interest rate derivative instruments at
December 31, 1998.  The majority of our debt is held in fixed rate
securities with embedded call options.  We hold $48.2 million in
variable-rate tax-exempt debt for pollution control financings and
4.5 percent of our total debt is variable in the form of
commercial paper.  The variable rate  debt is not interest rate sensitive by
nature and the commercial paper borrowings do not give rise to
significant interest rate risk because these borrowings generally
have maturities of less than three months.

The table below presents principal cash flows by maturity date and
the related average interest rate.  The table also presents the
fair value for all fixed rate instruments as of December 31, 1998,
based on market rates for similar instruments as of that date.

                          Expected Maturity Date
                 1999  2000  2001  2002  2003  Thereafter  Total   Fair Value

Fixed rate debt
 (in millions) $ 6.0  $87.8  $38.4 $35.7 $88.2   $519.3   $775.4     $829.2
Average
interest rate   7.52%  8.55%  7.05% 7.00% 6.50%    7.76%    7.64%

     Commodity Price Risk Sensitivity
This analysis presents the estimated December 31, 1998 value-at-
risk related to our energy commodity contracts and related
derivative instruments that are sensitive to changes in commodity
prices.  We use commodity derivative instruments such as futures,
options and swaps to hedge against exposure to commodity price
risk in the electricity and natural gas markets.  The objective of our
hedging program is to mitigate the risk associated with the
purchase and sale of natural gas and electricity.  Company policy
also allows the use of these commodity derivative instruments for
trading purposes in support of our operations.

The aggregate potential loss in earnings from our energy trading
activity is estimated to be $500,000 at a 95-percent confidence
interval and for a holding period of one business day.  The
potential loss in earnings was estimated using a value-at-risk
methodology with a monte carlo simulation.  The monte carlo
simulation averages outcomes from multiple scenarios based on our
exposure at December 31, 1998.  The multiple scenarios assume
potential commodity prices based on historical prices, volatility
and correlations to generate outcomes.  Limitations of the value-
at-risk analysis arise from uncertainties in assumptions.  Historical
prices, volatility and correlations are not necessarily a
predictor of future prices, volatility and correlations.  The use of a 95
percent confidence interval implies there is a 2.5 percent chance
the value-at-risk is greater than that which is stated.  A holding
period of one day implies that all exposures could be liquidated
in one business day.  A lack of liquidity in the market could result
in a holding period of more than one day.

Relicensing of Hydroelectric Projects
We are actively pursuing the relicensing of our hydroelectric
projects, a process that will continue for the next 10 to 15
years.  We submitted our first applications for license renewal to the
FERC in December 1995.  We have now filed applications seeking renewal
of our licenses for our Bliss, Upper Salmon Falls, Lower Salmon
Falls, C J Strike and Shoshone Falls Hydroelectric Projects.
Although various federal requirements and issues must be resolved
through the license renewal process, we anticipate that our
efforts will be successful.  At this point, however, we cannot predict
what type of environmental or operational requirements we may face, nor
can we estimate the eventual cost of license renewal.  At December
31, 1998, $10.7 million of relicensing costs were included in
Construction Work in Progress.

Year 2000 Costs
Many existing computer systems use only two digits to identify a
year in the date field.  These programs were designed and
developed without considering the impact of the upcoming change in the
century.  Unless proper modifications are made, the program logic
in many of these systems will start to produce erroneous results
because, among other things, the systems will read the date
"01/01/00" as being January 1 of the year 1900 or another
incorrect date.  In addition, the systems may fail to detect that the year
2000 is a leap year.  Similar problems could arise prior to the
year 2000 as dates in the next millennium are entered into systems
that are not Year 2000 compliant.

We recognize the Year 2000 problem as a serious threat to the
Company and our customers.  Our Year 2000 effort has been underway
for over two years and is being addressed at the highest levels
within the Company.  The IPC Vice President of Corporate Services
is responsible for coordinating the corporate effort.  Each IPC
vice president is responsible for addressing the problem within
their respective business units and each has assigned a Year 2000
Project Leader to execute the project plan.  Each subsidiary
President is responsible for addressing the problem within their
subsidiary in coordination with the corporate effort.  In
addition, we have appointed a full-time Year 2000 Project Manager to direct
the project.  Additional staff has been committed to complete the
conversion and implementation needed to bring non-compliant items
into compliance.  This staff consists of a mix of end users, IPC
Information Services staff and contract programmers.  Currently,
there are over 20 full-time employees devoted to the project with
dozens of others involved to varying degrees.  We have retained
third parties who have recently completed technical and legal
audits of our plan.  With respect to the technical audit, we have
completed our review of the audit report, have begun
implementation of most of the recommendations and are discussing the
remainder of the recommendations with the auditing company.  Regarding the
legal audit, we have received a draft audit and are presently reviewing
the draft report internally.

We have targeted July 1999 as the date by which we expect to be
ready for the Year 2000.  This means that all critical systems are
expected to be capable of handling the century rollover and that
we will be able to continue servicing our customers without
interruption.  It also means that all of the less critical systems
are expected to have been identified and that contingency and/or
repair plans are expected to be in place for dealing with the
change of century.

We are following a detailed project plan.  The methodology is
modeled after those used by some of the top companies in the world
and has been adapted to meet our unique requirements.  This
process includes all the phases and steps commonly found in such plans,
including the (i) identification and analysis of critical systems,
key manufacturers, service providers, embedded systems, generation
plants (part of which is owned by the Company but is operated by
another electric utility), (ii) remediation and testing,
(iii) education and awareness and (iv) contingency planning.

With respect to that key component of the methodology related to
the identification of critical systems, we have identified those
critical systems which must be Year 2000 compliant in order to
continue operations.  Many are already compliant or are in the
process of vendor upgrades to become compliant.  The largest of
these critical systems and their status regarding compliance are
set forth below:

  System        Description                           Status

  Business      The business systems include the      Our testing
  Systems       financial and administrative          has shown
                functions common to most companies.   PeopleSoft and
                Business systems include accounts     PassPort
                payable, general ledger, accounts     both to be
                receivable, labor entry, inventory,   compliant
                purchasing, cash management,          vendor
                budgeting, asset management,          packages.
                payroll, and financial reporting.

  Customer      This system is used to, among other   In-house
  Information   things, bill customers, log calls     system has
  System        from customers and create service or  been repaired.
                work requests and track them through  Testing is
                completion.  At this time, the        underway.
                Company uses an in-house developed,
                mainframe-based Customer Information
                System to accomplish these tasks.

  Energy        The most critical function the        The packages
  Management    Company offers is the delivery of     comprising the
  System (EMS)  electricity from the source to the    EMS are now
                consumer.  This must be done with     fully
                minimal interruption in the midst of  compliant and
                high demand, weather anomalies and    rollout is
                equipment failures.  To accomplish    underway.
                this, we rely on a server-based       Testing is
                energy management system provided by  currently
                Landis & Gyr.  This system monitors   underway.
                and directs the delivery of
                electricity throughout our service
                area.
  Metering      We rely on several processes for      In-house code
  Systems       metering electricity usage,           has been
                including some hand-held devices      repaired.
                with embedded chips.  It is critical  Vendor
                for metering systems to operate       packages are
                without interruption so as not to     being
                jeopardize our revenue stream.        upgraded.
                                                      Testing is
                                                      underway.

  Embedded      There is a category of systems on     Non-Year 2000
  Systems       which the Company is highly reliant   compliant
                called embedded systems.  These are   chips have
                typically computer chips that         been replaced.
                provide for automated operations      Test bench has
                within some device other than a       been
                computer such as a relay or a         established.
                security system.  We are highly       Testing is
                reliant on these systems throughout   about 75%
                our generation and delivery systems   complete.
                to monitor and allow manual or
                automatic adjustments to the desired
                devices.

  Other         We also rely on a number of other     In various
  Systems       important systems to support          stages of
                engineering, human resources, safety  repair and
                and regulatory compliance, etc.       testing.

Regarding third parties, the plan methodology has required us to
identify those third parties with which we have a material
relationship.  We have identified as material (1) our ownership
interest in thermal generating facilities which are operated and
maintained by third party electric utilities; (2) our fuel
suppliers for those thermal generating facilities; and (3) our
telecommunication providers.  In addition, we have identified
ninety-three (93) key manufacturers that provide materials and
supplies to us.  With respect to the thermal plants, fuel
suppliers and telecommunication providers, the plan methodology includes a
process wherein some members of the Year 2000 team meet
periodically with the third parties to assess the status of their
efforts.  This is an ongoing process and will continue until such
time as the third party has completed compliance testing and
certified to us that they are compliant.  Regarding the 93 key
manufacturers, we have contacted all via mail and requested they
complete a survey indicating the extent and status of their Year
2000 efforts.  The survey is followed up with contact by telephone
to further document their Year 2000 status.

Finally, we are connected to an electric grid that connects
utilities throughout the western portion of North America.  This
interconnection is essential to the reliability and operational
integrity of each connected utility.  This also means that failure
of one electric utility in the interconnected grid could cause the
failure of others.  In the context of the Year 2000 problem, this
interconnectivity compounds the challenge faced by the electric
utility industry.  Our Company could do a very thorough and
effective job of becoming Year 2000 compliant and yet encounter
difficulties supplying services and energy because another utility
in the interconnected grid failed to achieve Year 2000 compliance.
In this regard, we are working closely with other electric
industry organizations concerned with reliability issues and technical
collaboration.

Our estimate of the cost of our Year 2000 plan remains at
approximately $5.3 million which is being expensed as incurred.
This includes costs incurred to date (approximately $1.8 million)
and estimated costs through the year 2000.  This level of
expenditure is not expected to have a material effect on our
operations or our financial position.  Funds to cover Year 2000
costs in 1999 have been budgeted by business unit, subsidiary and
within the IPC Information Services Department with approximately
10 percent of the IPC Information Services budget used for
remediation.  No IPC Information Services Department projects have
been deferred due to our year 2000 efforts.

The Year 2000 issue poses risks to our internal operations due to
the potential inability to carry on our business activities and
from external sources due to the potential impact on the ability
of our customers to continue their business activities.  The major
applications that pose the greatest risks internally are those
systems, embedded or otherwise, which impact the generation,
transmission and distribution of energy and the metering and
billing systems.  The potential risks related to these systems are
electric service interruptions to customers and associated
reduction in loads and revenue, and interrupted data gathering and
billing, and the resultant delay in receipt of revenues.  All of
this would negatively impact our relationship with our customers,
which may enhance the likelihood of losing customers in a
restructured industry.  Externally, those customers who
inadequately prepare for the Year 2000 issue may be unable to
continue their business activities.  This would affect us in a
number of ways.  Our loads and revenue would be reduced because of
the lost load from discontinued business activities, and customers
who lose jobs because of discontinued business activities may face
difficulties in paying their power bills.  The impact of this on
us is dependent upon the number and the size of those businesses that
are forced to discontinue business activities because of the Year
2000 issue.

As part of our Year 2000 plan, we are in the process of developing
a contingency plan and expect to complete this process on or
before July 1999.


Management Changes
In January 1999 IDACORP's Board of Directors approved the
retirement plans of Chairman of the Board of Directors and Chief
Executive Officer Joseph W. Marshall.  Mr. Marshall will retire
effective June 1, 1999, and Jan B. Packwood, currently serving as
President, will assume the responsibilities of Chief Executive
Officer.  Jon Miller, a Board member since 1988, will replace
Marshall as Chairman of the Board in a non-executive capacity.

New Accounting Pronouncements
In June 1998, the FASB issued SFAS No. 133 "Accounting for
Derivative Instruments and Hedging Transactions."  This statement
establishes accounting and reporting standards for derivative
financial instruments and other similar financial instruments and
for hedging activities.  It is effective for fiscal years
beginning after June 15, 1999.  We are reviewing this statement to determine
its effect on our financial position and results of operations.

Emerging Issues Task Force 98-10 (EITF 98-10), "Accounting for
Contracts Involved in Energy Trading and Risk Management
Activities" is issued and effective for financial statements for
fiscal years beginning after December 15, 1998.  We anticipate the
impact of adoption on our financial position and results of
operations will be immaterial.


ITEM 7a.  QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET
      RISK

The information required by this item is included in Item 7
"Management's Discussion and Analysis of Financial Condition and
Results of Operations" under "Market Rate Sensitive Instruments
and Risk Management"



ITEM 8.  FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA


  INDEX TO FINANCIAL STATEMENTS AND FINANCIAL STATEMENT SCHEDULES

                                                            PAGE

Management's Responsibility for Financial Statements          38

Consolidated Financial Statements:
                           IDACORP, Inc.
Consolidated Statements of Income for the Years Ended
December 31, 1998, 1997 and 1996                              39
Consolidated Balance Sheets as of December 31, 1998,
1997 and 1996                                              40-41
Consolidated Statements of Capitalization as of December 31,
1998, 1997 and 1996                                           42
Consolidated Statements of Cash Flows for the Years Ended
December 31, 1998, 1997 and 1996                              43
Consolidated Statements of Retained Earnings and Consolidated
Statements of Comprehensive Income for the Years Ended
December 31, 1998,1997 and 1996                               44
Notes to Consolidated Financial Statements                 45-59
Independent Auditors' Report                                  60

                        Idaho Power Company
Consolidated Statements of Income for the Years Ended
December 31,1998, 1997 and 1996                               61
Consolidated Balance Sheets as of December 31, 1998, 1997 and
1996                                                       62-63
Consolidated Statements of Capitalization as of December
31, 1998, 1997 and 1996                                       64
Consolidated Statements of Cash Flows for the Years Ended
December 31, 1998, 1997 and 1996                              65
Consolidated Statements of Retained Earnings and Consolidated
Statements of Comprehensive Income for the Years Ended
December 31, 1998, 1997 and 1996                              66
Notes to Consolidated Financial Statements                 67-69
Independent Auditors' Report                                  70

Supplemental Financial Information and Financial Statement
Schedules:
Supplemental Financial Information (Unaudited)                71
Financial Statement Schedules for the Years Ended December 31,
1998, 1997 and 1996:
  Schedule II-Consolidated Valuation and Qualifying Accounts-
  IDACORP, Inc.                                               77
  Schedule II-Consolidated Valuation and Qualifying Accounts-
  Idaho Power Company.                                        77



          MANAGEMENT'S RESPONSIBILITY FOR FINANCIAL STATEMENTS

The management of IDACORP, Inc. and 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. 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 Companies maintain 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 conducts special and operational
audits in support of these accounting controls throughout the
year.

Each Company's Board of Directors, through their Audit Committees
comprised entirely of outside directors, meet periodically with
management, internal auditors and 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
Committees.

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



Joseph W. Marshall
Chairman and Chief Executive Officer



J.   LaMont Keen
Vice President, Chief Financial Officer and Treasurer


IDACORP, Inc.
Consolidated Statements of Income

                                      Year Ended December 31,
                                     1998       1997       1996
                                  (Thousands of Dollars except for
                                         per share amounts)

  REVENUES:
     General business           $ 514,856    $ 480,458   $ 484,145
     Off system sales             579,984      243,874      70,222
     Other revenues                27,136       24,171      24,078
       Total revenues           1,121,976      748,503     578,445

  EXPENSES:
     Operation:
       Purchased power            540,200      219,200      69,038
       Fuel expense                86,237       71,271      63,334
       Power cost adjustment       21,866       (6,032)
(6,859)
       Other                      145,374      137,458     132,667
     Maintenance                   41,872       48,722      42,731
     Depreciation                  74,481       71,973      69,705
     Taxes other than income
       taxes                       20,725       21,162      20,658
        Total expenses            930,755      563,754     391,274

  INCOME FROM OPERATIONS          191,221      184,749     187,171

  OTHER INCOME:
     Allowance for equity funds       300           34          46
  used during construction
     Gas trading activities -
       Net                         (3,208)      (1,181)        -
     Other - Net                   10,928       15,402      12,488
        Total other income          8,020       14,255      12,534

  INTEREST EXPENSE AND OTHER:
     Interest on long-term debt    52,270       53,215      52,165
     Other interest                 8,407        7,546       5,183
     Allowance for borrowed funds
     used during                     (900)        (503)       (353)
     construction
     Preferred dividends of Idaho
     Power Company                  5,658        5,176       7,463
        Total interest expense
           and other               65,435       65,434      64,458

  INCOME BEFORE INCOME TAXES      133,806      133,570     135,247

  INCOME TAXES                     44,630       46,472      52,092

NET INCOME                      $  89,176    $  87,098   $  83,155

AVERAGE COMMON SHARES
   OUTSTANDING (000)               37,612       37,612      37,612

EARNINGS PER SHARE OF
   COMMON STOCK (basic and
   diluted)                     $    2.37    $    2.32   $    2.21

 The accompanying notes are an integral part of these statements.


IDACORP, Inc.
Consolidated Balance Sheets

Assets

                                             December 31,
                                      1998       1997       1996
                                        (Thousands of Dollars)

ELECTRIC PLANT:
   In service (at original cost)   $2,659,441  $2,605,697  $2,537,565
   Accumulated provision for
   depreciation                    (1,009,387)   (942,400)   (886,885)
     In service - Net               1,650,054   1,663,297   1,650,680
   Construction work in progress       59,717      51,892      42,178
   Held for future use                  1,738       1,738       1,773

      Electric plant - Net          1,711,509   1,716,927   1,694,631

INVESTMENTS AND OTHER PROPERTY        129,437      97,065      69,903

CURRENT ASSETS:
   Cash and cash equivalents           22,867       6,905       7,928
   Receivables:
     Customer                          81,245      63,076      34,962
     Allowance for uncollectible
     accounts                          (1,397)     (1,397)     (1,394)
     Gas trading                       21,426      42,128         -
     Notes                              4,643       4,613       5,104
     Employee notes                     4,510       4,757       4,486
     Other                              6,059       8,854       8,489
   Accrued unbilled revenues           34,610      33,312      27,709
   Materials and supplies (at
   average cost)                       30,157      29,156      24,639
   Fuel stock (at average cost)         7,096       7,172      11,631
   Prepayments                         16,042      15,381      16,165
   Regulatory assets associated
   with income taxes                    2,965       3,164       4,397
      Total current assets            230,223     217,121     144,116

DEFERRED DEBITS:
   American Falls and Milner water
   rights                              31,830      32,055      32,260
   Company-owned life insurance        35,149      51,915      57,291
   Regulatory assets associated
   with income taxes                  201,465     198,521     196,696
   Regulatory assets - other           62,013      90,239      89,507
   Other                               49,994      47,973      44,334

      Total deferred debits           380,451     420,703     420,088

      TOTAL                        $2,451,620  $2,451,816  $2,328,738


 The accompanying notes are an integral part of these statements.

IDACORP, Inc.
Consolidated Balance Sheets

Capitalization and Liabilities

                                                 December 31,
                                       1998         1997          1996
                                            (Thousands of Dollars)

CAPITALIZATION:
   Common stock equity:
     Common stock without par
      value (shares authorized
      120,000,000; shares
      outstanding - 37,612,351)    $  451,564    $  452,519    $  452,486
     Retained earnings                278,607       259,299       242,088
     Accumulated other
     comprehensive income                 226            -           -

      Total common stock equity       730,397       711,818       694,574

   Preferred stock of Idaho Power
   Company                            105,968       106,697       106,975

   Long-term debt                     815,937       746,142       769,810

      Total capitalization          1,652,302     1,564,657     1,571,359

CURRENT LIABILITIES:
   Long-term debt due within one
   year                                 6,029        33,998         2,212
   Notes payable                       38,524        57,516        54,016
   Accounts payable                    73,499        69,064        36,370
   Accounts payable gas trading        28,476        42,874           -
   Taxes accrued                       24,785        24,295        17,304
   Interest accrued                    18,365        17,918        15,886
   Deferred income taxes                2,965         3,164         4,397
   Other                               12,275        13,703        12,439

      Total current liabilities       204,918       262,532       142,624

DEFERRED CREDITS:
 Regulatory liabilities associated
 with deferred investment
   tax credits                         69,396        70,196        71,283
   Deferred income taxes              422,196       423,736       411,890
   Regulatory liabilities
   associated with income taxes        28,075        34,072        35,028
   Regulatory liabilities - other       4,161           509           616
   Other                               70,572        96,114        95,938

      Total deferred credits          594,400       624,627       614,755

COMMITMENTS AND CONTINGENT
   LIABILITIES

      TOTAL                        $2,451,620    $2,451,816    $2,328,738

 The accompanying notes are an integral part of these statements.



IDACORP, Inc.
Consolidated Statements of Capitalization
                                              December 31,
                                    1998       %    1997      %    1996     %
                                         (Thousands of Dollars)
COMMON STOCK EQUITY
   Common stock                    $  451,564     $  452,519     $ 452,486
   Retained earnings                  278,607        259,299       242,088
   Accumulated other comprehensive        226           -             -
      Total common stock equity       730,397  44    711,818  45   694,574  44

PREFERRED STOCK OF IDAHO POWER
COMPANY
   4% preferred stock                  15,968         16,697        16,975
   7.68% Series, serial preferred
   stock                               15,000         15,000        15,000
   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           105,968   7    106,697   7    106,975  7

LONG-TERM DEBT OF IDAHO POWER
COMPANY
   First mortgage bonds:
     5.33 %       Series due 1998        -            30,000        30,000
     8.65 %       Series due 2000      80,000         80,000        80,000
     6.93 %       Series due 2001      30,000         30,000        30,000
     6.85 %       Series due 2002      27,000         27,000        27,000
     6.40 %       Series due 2003      80,000         80,000        80,000
     8    %       Series due 2004      50,000         50,000        50,000
     5.83 %       Series due 2005      60,000           -             -
     Maturing 2021 through 2031
     with rates ranging from 7.5%
     to 9.52%                         230,000        230,000       230,000
      Total first mortgage bonds      557,000        527,000       527,000
   Amount due within one year            -           (30,000)         -
      Net first mortgage bonds        557,000        497,000       527,000
   Pollution control revenue
   bonds:
     7 1/4 % Series due 2008            4,360          4,360         4,360
     8.30 %  Series 1984 due 2014      49,800         49,800        49,800
     6.05 % Series 1996A due 2026      68,100         68,100        68,100
     Variable Rate Series 1996B
     due 2026                          24,200         24,200        24,200
     Variable Rate Series 1996C
     due 2026                          24,000         24,000        24,000
     Total pollution control
     revenue bonds                    170,460        170,460       170,460
   REA notes                            1,489          1,561         1,632
     Amount due within one year           (74)           (72)          (71)
      Net REA notes                     1,415          1,489         1,561
   American Falls bond guarantee       20,130         20,355        20,560
   Milner Dam note guarantee           11,700         11,700        11,700
   Debt related to investments in
     affordable housing with
     rates ranging from 6.97% to
     8.59% due 1999 to 2009            62,103         46,385        33,401
     Amount due within one year        (5,955)        (3,926)       (2,141)
      Net affordable housing debt      56,148         42,459        31,260
   Unamortized premium/discount - Net  (1,539)        (1,637)       (1,731)
      Net Idaho Power Company debt    815,314        741,826       760,810

OTHER SUBSIDIARY DEBT                     623          4,316         9,000

      Total long-term debt            815,937  49    746,142  48   769,810  49

TOTAL CAPITALIZATION               $1,652,302 100 $1,564,657 100$1,571,359 100
The accompanying notes are an integral part of these statements.

IDACORP, Inc.
Consolidated Statements of Cash Flows
                                           Year Ended December 31,
                                      1998         1997         1996
                                           (Thousands of Dollars)

OPERATING ACTIVITIES:
   Net income                     $ 89,176     $  87,098     $ 83,155
   Adjustments to reconcile net
   income to net cash:
     Depreciation and amortization  87,143        80,485       78,228
     Deferred taxes and investment
     tax credits                   (10,182)        5,978       7,967
     Accrued PCA costs              21,658        (7,038)     (6,768)
     Change in:
      Accounts receivable and
      prepayments                    4,883       (69,589)      5,482
      Accrued unbilled revenue      (1,298)       (5,603)     (2,684)
      Materials and supplies and
      fuel stock                      (925)          (57)      2,730
      Accounts payable              (9,963)       75,731      (4,277)
      Taxes accrued                    489         6,991       1,895
      Other current assets and
      liabilities                     (825)        3,296         673
     Other - net                   (10,269)       (5,562)        551
   Net cash provided by operating
     activities                    169,887       171,730     166,952

INVESTING ACTIVITIES:
   Additions to utility plant      (89,184)      (95,633)    (93,645)
   Investments in affordable
   housing projects                (19,139)      (17,021)    (18,281)
   Other investments                  -             -        (20,153)
   Other - net                       3,206        (1,302)        825
     Net cash used in investing
       activities                 (105,117)     (113,956)   (131,254)

FINANCING ACTIVITIES:
   Proceeds from issuance of:
     First mortgage bonds           60,000          -         57,000
     Pollution control revenue
     bonds                            -             -        116,300
     Long-term debt related to
     affordable housing projects    15,718        12,984      17,924
     Other long-term debt             -             -          9,000
   Retirement of:
     Subsidiary long-term debt      (4,316)       (4,700)        -
     First mortgage bonds          (30,000)         -        (20,249)
     Pollution control revenue        -             -       (116,300)
     bonds
     Preferred stock of Idaho
     Power Company                     -             -       (26,530)
   Dividends on common stock        (69,868)      (69,887)   (69,924)
   Increase (decrease) in short-
   term borrowings                  (18,992)        3,500        996
   Other - net                       (1,350)         (694)    (4,455)
     Net cash used in financing
     activities                     (48,808)      (58,797)   (36,238)

Net increase (decrease) in cash
and cash equivalents               15,962         (1,023)       (540)

Cash and cash equivalents
beginning of period                 6,905          7,928       8,468

Cash and cash equivalents at end
of period                         $ 22,867     $   6,905     $ 7,928

SUPPLEMENTAL DISCLOSURE OF CASH
FLOW INFORMATION:
   Cash paid during the period
for:
     Income taxes                 $ 55,527     $  41,786     $45,050
     Interest (net of amount      53,806       $  53,319     $53,273
capitalized)

 The accompanying notes are an integral part of these statements.




IDACORP, Inc.
Consolidated Statements of Retained Earnings

                                            Year Ended December
31,
                                        1998         1997       1996
                                            (Thousands of Dollars)

RETAINED EARNINGS, BEGINNING OF YEAR  $259,299     $242,088     $229,827

NET INCOME                              89,176       87,098       83,155

   Total                               348,475      329,186      312,982

COMMON STOCK DIVIDENDS                 (69,868)     (69,887)     (69,924)

PREFERRED STOCK REDEMPTION - Idaho
  Power Company                           -            -            (970)

RETAINED EARNINGS, END OF YEAR        $278,607     $259,299     $242,088

 The accompanying notes are an integral part of these statements.



Consolidated Statements of Comprehensive Income

                                            Year Ended December 31,
                                        1998         1997         1996
                                       (Thousands of Dollars)

NET INCOME                            $ 89,176     $ 87,098     $ 83,155

OTHER COMPREHENSIVE INCOME:
   Unrealized gains on securities
(net of tax of $2,185)                   3,385         -          -
   Minimum pension liability
adjustment (net of tax of $2,054)       (3,159)        -          -


TOTAL COMPREHENSIVE INCOME            $ 89,402     $ 87,098     $ 83,155

  The accompanying notes are an integral part of these statements


IDACORP, Inc.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Nature of Business

 IDACORP, Inc. (the Company) is a holding company formed in 1998
as the parent to Idaho Power Company (IPC), Ida-West Energy Company,
and IDACORP Energy Solutions Inc.  IPC's outstanding common stock
was converted on a share-for-share basis into common stock of the
Company.  However, IPC's preferred shares and debt securities
outstanding were unaffected and remain with IPC.

IPC, a public utility, represents over 90% of the total assets of
the Company and is its principal operating subsidiary.  IPC is
regulated by the Federal Energy Regulatory Commission (FERC) and
the state commissions of Idaho, Oregon, Nevada and Wyoming, is
engaged in the generation, transmission, distribution, sale and
purchase of electric energy, and has approximately 374,000 retail
customers and 1,669 employees.

1.  SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES:
Principles of Consolidation

The consolidated financial statements include the accounts of the
Company and its wholly owned or controlled subsidiaries.  All
significant intercompany transactions and balances have been
eliminated in consolidation.  Investments in business entities in
which the Company and its subsidiaries do not have control, but
have the ability to exercise significant influence over operating
and financial policies, are accounted for using the equity method.

System of Accounts

The accounting records of IPC conform to the Uniform System of
Accounts prescribed by the 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, IPC's weighted-
average monthly AFDC rates for 1998, 1997 and 1996 were 6.0
percent, 5.8 percent and 6.1 percent, respectively.

Revenues

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

Under terms and conditions of a regulatory settlement with the
Idaho Public Utilities Commission (IPUC), if IPC's actual earnings
in a given year exceed an 11.75 percent return on year-end common
equity, it will set aside 50 percent of the excess for the benefit
of IPC's Idaho retail customers.  In 1998, 1997 and 1996,
approximately $5.4 million, $7.6 million and $4.9 million of
revenues were set aside for the benefit of Idaho retail customers.

Power Cost Adjustment

IPC has a Power Cost Adjustment (PCA) mechanism that provides for
annual adjustments to the rates charged to Idaho retail customers.
These adjustments are based on forecasts of net power supply
costs, and take effect annually on May 16.  The difference between the
actual costs incurred and the forecasted costs are deferred, with
interest, and trued-up in the next annual rate adjustment.

Depreciation

All electric plant is depreciated using the straight-line method.
Annual depreciation provisions as a percent of average depreciable
electric plant in service approximated 2.87 percent in 1998, 2.93
percent in 1997 and 2.89 percent in 1996 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 the 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, IPC's 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, IPC received an accounting order from the IPUC that
allowed for accelerated 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 1998, 1997 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
maturity dates at date of acquisition of three months or less.
The Company has changed the presentation of operating activities in
its consolidated statements of cash flows from the direct to the
indirect method.  The years 1997 and 1996 have been reclassified
to conform to the new presentation.

Management Estimates

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

Regulation of Utility Operations

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

Some state regulatory authorities are in the process of changing
utility regulations in response to federal and state statutory
changes and evolving competitive markets.  These statutory and
conforming regulations may result in increased wholesale and
retail competition.  Due to IPC's low cost structure, it is well
positioned to compete in the evolving utility market place.
However, the Company is unable to predict what financial impact or
effect the adoption of any such legislation would have on IPC's
operations.

IPC 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 IPC.  Pursuant to SFAS No. 71 IPC capitalizes, as
deferred regulatory assets, incurred costs that are expected to be
recovered in future utility rates.  IPC also records as deferred
regulatory liabilities the current recovery in utility rates of
costs that are expected to be paid in the future.

The following is a breakdown of IPC's regulatory assets and
liabilities for the years 1998, 1997 and 1996:

                           1998               1997
1996
                    Assets Liabilities  Assets Liabilities  Assets  Liabilities
                                       (Millions of Dollars)
Income taxes        $204.4   $ 28.1     $201.7   $ 34.1     $201.1    $ 35.0
Conservation          43.3      -         42.4      -         40.3      -
Employee benefits      5.6      -          6.5      -          7.4      -
PCA deferral and
   amortization       (5.2)     -         16.6      -          9.6      -
Other                 18.3      4.1       24.7      0.5       32.2       0.6
Deferred investment
tax credits             -      69.4         -      70.2         -       71.3
   Total            $266.4   $101.6     $291.9   $104.8     $290.6    $106.9

At December 31, 1998, IPC had $14.1 million of regulatory assets
that were not earning a return on investment excluding the $204.4
million that relates to income taxes.

In the event that recovery of costs through rates becomes unlikely
or uncertain, SFAS No. 71 would no longer apply.  If the Company
were to discontinue application of SFAS No. 71 for some or all of
IPC's operations, then these items may represent stranded
investments.  If the Company is not allowed recovery of these
investments, it would be required to write off the applicable
portion of regulatory assets and the financial effects could be
significant.

Derivative Financial Instruments

IPC uses financial instruments such as commodity futures, options
and swaps to hedge against exposure to commodity price risk in the
electricity and natural gas markets.  The objective of IPC's
hedging program is to mitigate the risk associated with the
purchase and sale of natural gas and electricity.  The accounting
for derivative financial instruments that are used to manage risk
is in accordance with the concepts established in SFAS No. 80,
"Accounting for Futures Contracts," American Institute of
Certified Public Accountants Statement of Position 86-2, "Accounting for
Options," and various Emerging Issues Task Force (EITF)
pronouncements.

Deferral (hedge) accounting is used if certain hedging criteria
are met and is applied only if the derivative reduces the risk of the
underlying hedged item and is designated at inception as a hedge
with respect to the hedged item.  Additionally, the derivative
must result in payoffs that are expected to be inversely correlated to
those of the hedged item.

Gains and losses from derivatives that reduce the commodity price
risk related to electricity are recognized as purchased power
expenses when the hedged transaction occurs.  Gains and losses
from derivatives that reduce the commodity price risk related to
natural gas are recognized as a component of gas trading activities when
the hedged transaction occurs.  Cash flows from derivatives are
recognized in the statement of cash flows and are in the same
category as that of the hedged item.

IPC's policy also allows for the use of financial instruments
noted above for trading purposes in support of Company operations.
Gains or losses on financial instruments that do not qualify for hedge
accounting are recognized in income on a current basis.

The following table shows a summary of IPC's derivative positions
as of December 31, 1998 and 1997.  No derivative positions existed
at December 31, 1996.

                               1998                   1997
                        Gas     Electricity     Gas    Electricity
                      MMBTU's      MWh's      MMBTU's      MWh's
Futures:
  Purchase          21,210,000   286,304    3,560,000     21,344
  Sale              18,590,000   370,944    3,510,000        -
Options:
  Purchase              -         18,400        -            -
  Sale                  -         43,200        -            -
Swaps               27,568,610      -          15,104        -

Comprehensive Income

The Company adopted SFAS No. 130, "Reporting Comprehensive Income"
effective January 1, 1998.  The statement establishes standards
for reporting and displaying comprehensive income and its components
in the Company's financial statements.

Components of the Company's comprehensive income include net
income, the Company's proportionate share of unrealized holding
gains on marketable securities held by an equity investee, and the
changes in additional minimum liability under a deferred
compensation plan for certain senior management employees and
directors.

New Accounting Pronouncements

In June 1998, the Financial Accounting Standards Board (FASB)
issued SFAS No. 133, "Accounting for Derivative Instruments and
Hedging Activities."  This statement is effective for all fiscal
quarters of all fiscal years beginning after June 15, 1999, and
establishes accounting and reporting standards for derivative
instruments, including certain derivative instruments embedded in
other contracts, and for hedging activities.  The Company is
evaluating the effect of this statement on its financial position
and results of operations.

EITF 98-10, "Accounting for Contracts Involved in Energy Trading
and Risk Management Activities" is issued and effective for
financial statements for fiscal years beginning after December 15,
1998.  The Company anticipates the impact of adoption on its
financial position and results of operations will be immaterial.


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 1998 have
been reclassified to conform to the current year's presentation.



2.  INCOME TAXES:
IPC has settled Federal and Idaho tax liabilities on all open
years through the 1995 tax year except for amounts related to a
partnership which have been, in management's opinion, adequately
accrued. A reconciliation between the statutory federal income tax rate and
the effective rate is as follows:

                                 1998       1997       1996
Computed income taxes based
on statutory
federal income tax rate        $ 46,832  $ 46,750    $ 47,336
Change in taxes resulting
from:
  Investment tax credits         (2,934)   (2,887)     (2,835)
  Repair allowance               (2,800)   (2,800)     (2,800)
  Settlement of prior years
tax returns                      (1,965)       23         (16)
  Current state income taxes      6,258     3,587       2,823
  Depreciation                    5,237     5,766       5,945
  Affordable housing tax
credits                          (6,880)   (4,519)     (1,777)
  Preferred dividends of IPC      1,980     1,811       2,613
  Other                          (1,098)   (1,259)        803
Total provision for federal
and state income taxes         $ 44,630  $ 46,472    $ 52,092
  Effective tax rate               33.4 %    34.8 %      38.5 %

The provision for income taxes consists of the following:

                                 1998       1997       1996
  Income taxes currently
payable:
   Federal                     $ 45,606  $ 35,038    $ 40,379
   State                          9,206     5,456       3,746
    Total                        54,812    40,494      44,125
  Income taxes deferred -
Net of amortization:
   Federal                       (8,006)    6,717       6,877
   State                         (1,376)      348         314
    Total                        (9,382)    7,065       7,191
  Investment tax credits:
   Deferred                       2,134     1,800       3,611
   Restored                      (2,934)   (2,887)     (2,835)
    Total                          (800)   (1,087)        776
  Total provision for income
taxes                          $ 44,630  $ 46,472    $ 52,092

The tax effects of significant items comprising the Company's net
deferred tax liability are as follows:

                                 1998       1997       1996
  Deferred tax assets:
   Regulatory liabilities      $ 28,075  $ 34,072    $ 35,028
   Advances for construction     10,401    18,665      17,736
   Other                         20,512    16,536      13,550
    Total                        58,988    69,273      66,314
  Deferred tax liabilities:
   Electric plant               247,270   251,938     245,652
   Regulatory assets            204,430   201,685     201,093
   Investment tax credits        69,396    70,196      71,283
   Conservation programs         16,866    14,377      13,720
   Other                         15,583    28,173      22,136
    Total                       553,545   566,369     553,884

  Net deferred tax             $494,557  $497,096    $487,570
liabilities




3.  COMMON STOCK:
Changes in shares of IDACORP common stock for 1998, 1997 and 1996
were as follows:

                                 Shares        Amount
Balance at December 31, 1995   37,612,351     $452,948
Other - Net                                       (462)
Balance at December 31, 1996   37,612,351      452,486
Other - Net                                         33
Balance at December 31, 1997   37,612,351      452,519
Other - Net                                       (955)
Balance at December 31, 1998   37,612,351     $451,564

As of December 31, 1998; 2,791,321 of authorized but unissued
shares of IDACORP common stock were reserved for future issuance
under the Company's Dividend Reinvestment and Stock Purchase Plan
and IPC's Employee Savings Plan.  In addition, 314,114 shares are
reserved for the Restricted Stock Plan (see Note 9).

The Company has a Shareholder 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 Share
Purchase Right (Right) for each of the Company's outstanding Common Shares
held on October 1, 1998 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 of such
stock.  The Company may redeem all but not less than all of the Rights at
a price of $0.01 per Right or exchange the Rights for cash,
securities (including Common Shares of the Company) or other
assets at any time prior to the close of business on the 10th day after
acquisition by an Acquiring Person of a 20 percent or greater
position.

Additionally, the IDACORP Board created the A Series Preferred
Stock, without Par Value, and reserved 1,200,000 shares for
issuance upon exercise of the Rights.

Following the acquisition of a 20 percent or greater position,
each Right will entitle its holder to purchase for $95 that number of
shares of Common Stock or Preferred Stock having a market value of
$190.

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 $95, shares of the acquiring company's
common stock having a market value of $190.

Any Rights that are or were held by an Acquiring Person become
void if any of these events occurs.  The Rights expire on September 30,
2008.

The Rights themselves do not give any voting or other rights as
shareholders to their holders.  The terms of the Rights may be
amended without the approval of any holders of the Rights until an
Acquiring Person obtains a 20 percent or greater position, and
then may be amended as long as the amendment is not adverse to the
interests of the holders of the Rights.


4.  PREFERRED STOCK OF IDAHO POWER COMPANY:
The number of shares of IPC preferred stock outstanding at
December 31, 1998, 1997 and 1996 were as follows:

                                Shares Outstanding at
                                     December 31,           Call Price
                               1998      1997      1996     Per Share
Preferred stock:
 Cumulative, $100 par value:
  4% preferred stock
  (authorized
   215,000 shares)            159,680   166,972   169,753     $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:
  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                     560,180   567,472   570,253

(a)   The preferred stock is not redeemable prior to July 1, 2003.
(b)   Dividend rate at December 31, 1998 was 4.02% and ranged
 between 4.29% and 3.97% during the year.

During 1998, 1997 and 1996 IPC reacquired and retired 7,292;
2,781; and 2,060 shares of 4% preferred stock.  As of December 31, 1998
the overall effective cost of all outstanding preferred stock was
5.57 percent.

On November 7, 1996, IPC redeemed for $26.4 million, the $25.0
million principal amount of 8.375% Series, serial preferred stock
without par value, ($100 stated value) from proceeds of the
issuance of $27.0 million principal amount of secured medium term
notes, Series B, 6.85%, Due 2002.


5.  LONG-TERM DEBT:
The Company currently has a $300.0 million shelf registration
statement that can be used for the issuance of unsecured debt
securities and preferred or common stock.  At December 31, 1998,
none had been issued.

The amount of first mortgage bonds issuable by IPC is limited to a
maximum of $900.0 million 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 IPC and are held by a Trustee for the benefit
of the bondholders.

IPC currently has a $200.0 million shelf registration statement
with a balance of $83.0 million that remains to be issued.  This
can be used for first mortgage bonds (including medium term notes)
or preferred stock.

First mortgage bonds maturing during the five-year period ending
2003 are $0 in 1999, $80.0 million in 2000, $30.0 million in 2001,
$27.0 million in 2002 and $80.0 million in 2003.

On July 29, 1996, IPC issued $30.0 million 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 IPC's ongoing construction program.  On October 2,
1996, $27.0 million principal amount of Secured Medium Term Notes,
Series B, 6.85% Due 2002 were issued with net proceeds from this
sale used to redeem IPC's $25.0 million of 8.375% Series, Serial
Preferred Stock, Without Par Value.

On September 9, 1998, $60.0 million principal amount of Secured
Medium Term Notes, Series B 5.83% Series due 2005 were issued by
IPC.  Proceeds from this issuance were used to redeem at maturity,
the $30.0 million First Mortgage Bonds 5.33% Series B due
September 1998, with the balance used for repayment of commercial paper
issued in connection with IPC's ongoing business.

On August 29, 1996, tax exempt Pollution Control Revenue Refunding
Bonds were issued by IPC in principal amount of $68.1 million
Series 1996A, $24.2 million Series 1996B and $24.0 million Series
1996C.  The proceeds were used to retire the $24.2 million
Pollution Control Revenue Bonds due 2003, $24.0 million Pollution
Control Revenue Bonds due 2007 and the $68.1 million Pollution
Control Revenue Bonds due 2013-2014.  At December 31, 1998, 1997
and 1996 the overall effective cost of all outstanding first
mortgage bonds and pollution control revenue bonds was 7.69
percent, 7.84 percent and 7.73 percent, respectively.

At December 31, 1998, IDACORP Financial Services, Inc., a wholly
owned subsidiary of IPC, has $62.1 million of debt with interest
rates ranging from 6.97 percent to 8.59 percent.  This debt is
collateralized by investments in affordable housing projects with
a book-value of $65.9 million at December 31, 1998.  Principal
amounts maturing during the five-year period ending 2003 are $6.0
million in 1999, $6.5 million in 2000, $6.9 million in 2001, $7.1
million in 2002 and $6.5 million in 2003.


6.  FAIR VALUE OF FINANCIAL INSTRUMENTS:

The estimated fair value of the Company's financial instruments
has 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 estimated fair values for long-term debt
and investments are based upon quoted market prices of the same or
similar issues or discounted cash flow analyses as appropriate.

The total estimated fair value of the Company's debt was
approximately $877.4 million in 1998, $801.8 million in 1997 and
$806.8 million for 1996.  Included in investments and other
property were financial instruments totaling $14.2 million in
1998, $16.5 million in 1997 and $18.0 million in 1996.  Estimated fair
value of these instruments was $20.3 million in 1998, $19.9
million in 1997 and $18.7 million in 1996.


7.  NOTES PAYABLE:
On December 21, 1998, the Company established a $100.0 million 364-
day credit facility which will expire December 19, 1999, and a
$50.0 million 3-year credit facility which will expire December
21, 2001.  Under these facilities the Company pays a facility fee on
the commitment, quarterly in arrears, based on IPC's First
Mortgage Bond Rating.  Commercial paper may be issued up to the $150.0
million and are supported by the bank credit facilities.

The Company has no short-term balance outstanding at December 31,
1998.

At December 31, 1998, IPC had regulatory authority to incur up to
$200.0 million of short-term indebtedness.  On December 19, 1996,
IPC replaced its committed lines of credit arrangements with a
$120.0 million multi-year revolving credit facility, which will
expire on December 19, 2001.  Under this facility IPC pays a
facility fee on the commitment, quarterly in arrears, based on
IPC'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 $200.0 million maximum and are
supported by bank lines of credit of an equal amount.

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

                                          Year Ended December
                                                 31,
                                        1998      1997      1996
                                         (Thousands of Dollars)

Balance at end of year                $38,524   $57,516   $54,016
Effective annual interest rate            6.0 %     6.1 %     5.7%
at end of year


8.  COMMITMENTS AND CONTINGENT LIABILITIES:
Commitments under contracts and purchase orders relating to IPC's
program for construction and operation of facilities amounted to
approximately $10.5 million at December 31, 1998.  The commitments
are generally revocable by IPC subject to reimbursement of
manufacturers' expenditures incurred and/or other termination
charges.

IPC is currently purchasing energy from 66 on-line cogeneration
and small power production facilities with contracts ranging from 1 to
32 years.  Under these contracts IPC is required to purchase all
of the output from these facilities.  During the fiscal year ended
December 31, 1998, IPC purchased 907,096 MWh at a cost of $55.0
million.

The Company is party to various legal claims, actions, and
complaints, certain of which involve material amounts.  Although
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:
Pension Plans

IPC sponsors a 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.  IPC'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.  IPC
was not required to contribute to the plan during 1998, 1997 and
1996.  The trustee invests the plan's assets primarily in listed
stocks (both U.S. and foreign), fixed income securities and
investment grade real estate.

IPC has a nonqualified, deferred compensation plan for certain
senior management employees and directors that provides for
supplemental retirement and death benefit payments to the
participant and his or her family.  IPC financed this plan by
purchasing life insurance policies for which it is the beneficiary
and through investments in marketable securities held by a
trustee. The cash value of the policies and investments exceed the
projected benefit obligation of the plan but do not qualify as plan assets
in the actuarial computation of the funded status.

The following table shows the components of net periodic pension
cost for these plans (in thousands of dollars):

                              Pension Plan      Deferred
Compensation Plan
                           1998     1997    1996     1998     1997   1996
Service cost             $  7,133  $ 6,152  $ 6,273  $   572 $  515  $   596
Interest cost              15,458   14,445   13,647    1,747  1,731    1,679
Expected return on assets (22,724) (20,248) (18,145)     -      -        -
Recognized net actuarial
(gain) loss                  (111)     -        -        255    222      248
Amortization of prior
service cost                  424      424      424     (332)  (346)    (339)
Amortization of
transition asset             (263)    (263)    (263)     613    613      613
Net periodic pension
cost                     $    (83) $   510  $ 1,936  $ 2,855 $2,735  $ 2,797


The following table sets forth the funded status of these plans
(in thousands of dollars):

                               Pension Plan       Deferred
Compensation Plan
                           1998     1997    1996     1998     1997    1996
Change in projected
benefit obligation:
  Beginning of year
  benefit obligation   $224,073 $202,049 $193,133  $ 25,067  $24,122  $ 23,692
  Service cost            7,133    6,152    6,273       572      516       596
  Interest cost          15,458   14,445   13,647     1,747    1,731     1,679
  Actuarial loss (gain)  14,139   12,763     (564)    1,297      806       189
  Benefits paid         (11,774) (11,336) (10,440)   (2,049)  (2,303)   (1,958)
  Plan amendments         4,700      -        -         395      195       (76)
  End of year benefit   253,729  224,073  202,049    27,029   25,067    24,122
  obligation
Change plan assets:
  Plan assets at fair
  value at beginning
    of year             256,893  230,478  204,760       -        -         -
  Actual return on plan
  assets                 44,961   37,751   30,234       -        -         -
  Employer contributions    -        -      5,924       -        -         -
  Benefit payments      (11,774) (11,336) (10,440)      -        -         -
  Plan assets at fair
  value at end of year  290,080  256,893  230,478       -        -         -

Funded status            36,351   32,820   28,429   (27,029) (25,067)  (24,122)
Unrecognized actuarial
loss/(gain)             (33,722) (25,734) (20,994)    6,612    5,569     4,985
Unrecognized prior
service cost              9,370    5,093    5,517    (1,166)  (1,893)   (2,434)
Unrecognized net
transition liability     (1,704)  (1,967)  (2,230)    3,988    4,601     5,214
(Accrued)/ Prepaid cost
 (net amount recognized) 10,295   20,212   10,722   (17,595) (16,790)  (16,357)
Additional minimum
liability                   -        -        -      (8,036)  (7,867)   (6,402)
Minimum liability      $ 10,295 $ 10,212 $ 10,722  $(25,631)$(24,657) $(22,759)

Amount recognized in
the statement of
financial position
consist of:
Prepaid (accrued)
pension cost            $ 10,295 $ 10,212 $ 10,722 $(25,631)$(24,657) $(22,759)
Intangible asset             -        -        -      2,822    7,867     6,402
Accumulated other
comprehensive income         -        -        -      5,214      -         -
Net amount recognized   $ 10,295 $ 10,212 $ 10,722 $(17,595)$(16,790) $(16,357)

The following table sets forth the assumptions used at the end of
each year for all IPC-sponsored pension and postretirement benefit
plans:

                            Pension Benefits     Postretirement
Benefits
                           1998   1997   1996    1998     1997     1996
Discount rate              6.75 % 7.10 % 7.35 %  6.75 %   7.35 %   7.60 %
Expected long-term rate of
return on assets            9.0    9.0    9.0     9.0      9.0     9.0
Annual salary increases     4.5    4.5    4.5      -        -       -

Restricted Stock Plan

IPC implemented a restricted stock plan in 1995 as an equity-based
long-term incentive plan for certain key employees.  Each grant
has a three-year restricted period and final award amounts depend on
the attainment of a cumulative earnings per share performance
goal. At December 31, 1998, there were 314,114 shares of common stock
reserved for the plan.

Restricted stock awards are compensatory awards and IPC accrues
compensation expense (which is charged to operations) based upon
the market value of the granted shares.  For the years 1998, 1997
and 1996, total compensation accrued for the plan was $567,000,
$539,000 and, $184,000 respectively.

IPC applies APB Opinion 25 and related interpretations in
accounting for this plan.  Had compensation cost for IPC's grants
of restricted stock been determined consistent with the optional
fair value based method provisions of SFAS No. 123, "Account for
Stock-Based Compensation," IPC's net income and earnings per share
of common stock for 1998, 1997 and 1996 would not be significantly
different from such amounts as reported.

The following table summarizes restricted stock activity for the
years 1998, 1997 and 1996:

                                   1998     1997    1996
 Shares outstanding -
beginning of year,                38,365   18,140   9,120
 Shares granted                   21,361   20,225   9,740
 Shares forfeited                 (4,063)     -      (720)
 Shares issued                   (12,600)     -        -
 Shares outstanding - end of
year                              43,063   38,365  18,140
 Weighted average fair value
of current year
  stock grants on grant date     $ 37.00  $ 31.25 $ 30.25

Savings Plan

IPC sponsors an Employee Savings Plan under which employees may
contribute a percentage of their base salary.  IPC matches the
first two percent of salary contributed by the employee and 50
percent of the next four percent of salary contributed by the
employee.  All amounts are invested by a trustee in any or all of
seven investment options.  Matching contributions amounted to $3.0
million in 1998, $2.4 million in 1997 and, $2.3 million in 1996.

Postretirement Benefits

IPC 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.

IPC has a retiree medical benefits funding program which consists
of life insurance policies on active employees for which IPC is
the beneficiary, and a qualified Voluntary Employees Beneficiary
Association (VEBA) Trust.  IPC was not required to contribute to
the plan in 1998, 1997 and 1996.  The VEBA trust represents plan
assets that are invested in variable life insurance policies,
Trust Owned Life Insurance (TOLI), on active employees.  Inside buildup
in the TOLI policies is tax deferred and tax free if the policy
proceeds are paid to the Trust as death benefits.  The investment
return assumption reflects an expectation that investment income
in the VEBA will be substantially tax free.




The net periodic postretirement benefit cost was as follows (in
thousands of dollars):

                                    1998       1997       1996
  Service cost                    $   720   $   713    $   794
  Interest cost                     2,913     3,029      3,172
  Expected return on plan assets   (1,761)   (1,511)    (1,410)
  Amortization of unrecognized
  transition obligation             2,040     2,040      2,040
  Amortization of prior service
  cost                               (280)      (87)        -
  Amortization of unrecognized
  net gains                          (220)     (240)       (57)
  Net periodic postretirement
  benefit cost                    $ 3,412   $ 3,944    $ 4,539

The following table sets forth the funded status of this
postretirement health and life insurance benefit plan (in
thousands
of dollars):
                                    1998       1997       1996
  Change in accumulated benefit
  obligation:
    Benefit obligation at
  beginning of year               $43,459   $44,439    $48,928
    Service cost                      720       713        794
    Interest cost                   2,913     3,029      3,172
    Plan amendments                (9,071)   (1,214)       -
    Actuarial loss (gain)           3,483    (1,940)    (6,984)
    Benefits paid                  (2,889)   (1,568)    (1,471)
    Benefit obligation at end of
  year                             38,615    43,459     44,439
  Change in plan assets:
    Fair value of plan assets at
  beginning of year                19,493    17,341     15,920
    Actual return on plan assets    4,853     2,152      1,421
    Employer (excess)
  contributions                     2,789     1,553      1,421
    Benefits paid                  (2,789)   (1,553)    (1,421)
    Fair value of plan assets at
  end on year                      24,346    19,493     17,341

  Funded status                   (14,269)  (23,966)   (27,098)
  Unrecognized prior service cost  (9,918)   (1,127)       -
  Unrecognized actuarial
  (gain)/loss                      (7,256)   (7,867)    (5,526)
  Unrecognized transition
  obligation                       28,560    30,600     32,640
  Accrued postretirement benefit
  obligations included with othe
    long-term liabilities         $(2,883)  $(2,360)   $    16
  liabilities

The assumed health care cost trend rate used to measure the
expected cost of benefits covered by the plan is 6.75%.  A one-
percentage point change in the assumed health care cost trend rate
would have the following effect (in thousands of dollars):


                                  1-Percentage-    1-Percentage-
                                  Point increase   Point decrease

Effect on total of service and
interest cost components             $    279       $    (259)
Effect on accumulated
postretirement benefit obligation       2,286          (2,159)


Postemployment Benefits

The Company provides certain benefits to former or inactive
employees, their beneficiaries, and covered dependents after
employment but before retirement.  These benefits include salary
continuation, health care and life insurance for those employees
found to be disabled under our disability plans, and health care
for surviving spouses and dependents.  The Company accrues a
liability for such benefits.  In accordance with an IPUC order,
the portion of the liability attributable to regulated activities in
Idaho as of December 31, 1993, was deferred as a regulatory asset,
and is being amortized over ten years.  The following table
summarizes postemployment benefits amounts included in the
Company's consolidated balance sheet (in thousands of dollars):


                                1998      1997       1996
  Included with regulatory
  assets - other               $2,260    $2,632    $3,003
  Included with other
  deferred credits             (3,372)   (3,093)   (4,128)


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, accumulated provision for
depreciation and annual depreciation provisions as a percent of
average depreciable balance for the years 1998, 1997 and 1996 (in
thousands of dollars):

                            1998               1997
1996
                      Balance  Avg Rate   Balancc Avg Rate   Balance Avg Rate


  Production        $1,344,526  2.60%   $1,333,768  2.60%    $1,323,090  2.58%
  Transmission         389,011  2.30       378,190  2.28        371,123  2.29
  Distribution         736,527  3.15       715,091  3.38        688,232  3.35
  General and Other    189,377  5.45       178,648  5.39        155,120  5.23
   Total In Service  2,659,441  2.87     2,605,697  2.93      2,537,565  2.89
    Less accumulated
provision for
depreciation         1,009,387             942,400              886,885
   In Service - Net $1,650,054          $1,663,297           $1,650,680

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

Each facility and extent of IPC participation as of December 31,
1998 are as follows:

                                        Company Ownership
                                                  Accumulated
                                  Electric Plant  Provision
Name of Plant       Location      In Service      for Depreciation %   MW
                                       (Thousands of Dollars)
Jim Bridger      Rock Springs,    $383,139        $190,139         33  708
Units 1-4        WY
Boardman         Boardman, OR       61,486          32,071         10   53
Valmy Units 1    Winnemucca, NV    299,763         130,118         50  261
and 2

IPC'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 IPC
from the joint venture amounted to $46.2 million in 1998, $40.7 million
in 1997 and, $35.0 million in 1996.

IPC has contracts to purchase the energy from five PURPA Qualified
Facilities that are 50 percent owned by Ida-West Energy Company, a
wholly owned subsidiary of the Company.  Power purchased from
these facilities amounted to $8.7 million in 1998, $9.8 million in 1997
and $9.0 million in 1996.


11.  INDUSTRY SEGMENT INFORMATION:

In June 1997 the FASB issued SFAS No. 131, "Disclosures about
Segments of an Enterprise and Related Information."  This
Statement requires financial and descriptive disclosure for fiscal years
beginning after December 15, 1997, about certain operating
segments of an enterprise as well as enterprise-wide disclosure of certain
product and geographic information.

The Company is predominantly a one operating segment company with
the regulated electric operations of IPC being the most dominant
segment.  Other subsidiaries of the Company, subsidiaries of IPC
and non-utility operating segments of IPC do not individually
constitute more than 10% of enterprise revenues, income or assets,
nor in aggregate do they comprise more than 25% of enterprise
revenues, income or assets.

IPC's primary business is the generation, transmission,
distribution, purchase and sale of electricity.  IPC also began
natural gas trading activities in May 1997 and reports this
activity in Other Income in the Consolidated Statements of Income.
The following table summarizes the segment information for IPC
Utility with a reconciliation to total enterprise information:

                        IPC                        Total
                      Utility        Other      Enterprise
                            (Thousands of Dollars)
1998
Revenues             $1,121,976   $     -        $1,121,976
Income from
operations              191,221         -           191,221
Other income              5,909       2,111           8,020
Interest expense         56,646       3,131          59,777
Income before income
taxes                   140,484      (6,678)        133,806
Income taxes             51,447      (6,817)         44,630
Net income               89,037         139          89,176
Total assets          2,310,322     141,298       2,451,620
Expenditures for
long-lived assets        91,803      19,205         111,008

1997
Revenues            $   748,503   $     -       $   748,503
Income from
operations              184,749         -           184,749
Other income              3,894      10,361          14,255
Interest expense         57,653       2,605          60,258
Income before income
taxes                   130,990       2,580         133,570
Income taxes             49,125      (2,653)         46,472
Net income               81,865       5,233          87,098
Total assets          2,338,524     113,292       2,451,816
Expenditures for
long-lived assets        98,219      17,457         115,676

1996
Revenues            $   578,445   $     -       $   578,445
Income from
operations              187,171         -           187,171
Other income              2,759       9,775          12,534
Interest expense         56,110         885          56,995
Income before income
taxes                   133,821       1,426         135,247
Income taxes             51,386         706          52,092
Net income               82,435         720          83,155
Total assets          2,245,880      82,858       2,328,738
Expenditures for
long-lived assets        97,484      34,595         132,079

Substantially all of the Company's revenue comes from the sale of
electricity and related services, predominately in the United
States.  The Company sells natural gas, solar electric products
and
systems, control systems integration services for substations and
semiconductor manufacturing, and miscellaneous other services
however, these revenues are not significant.
INDEPENDENT AUDITORS' REPORT


To The Board of Directors and Shareowners of
IDACORP, Inc.
Boise, Idaho

We have audited the accompanying consolidated balance sheets and
statements of capitalization of IDACORP, Inc. and its subsidiaries
as of December 31, 1998, 1997 and 1996, and the related
consolidated statements of income, cash flows, retained earnings
and comprehensive income for the years then ended.  Our audits
also included the consolidated financial statement schedule listed in
the Index at Item 8.  These financial statements and financial
statement schedule are the responsibility of the Company's
management.  Our responsibility is to express an opinion on the
financial statements and financial statement schedule based on our
audits.

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

In our opinion, such consolidated financial statements present
fairly, in all material respects, the financial position of
IDACORP, Inc. and subsidiaries at December 31, 1998, 1997 and
1996, 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

Boise, Idaho
January 29, 1999


Idaho Power Company
Consolidated Statements of Income

                                    Year Ended December 31,
                                 1998          1997         1996
                                     (Thousands of Dollars)

REVENUES:
   General business            $ 514,856    $ 480,458    $ 484,145
   Off system sales              579,984      243,874       70,222
   Other revenues                 27,136       24,171       24,078
     Total revenues            1,121,976      748,503      578,445

EXPENSES:
   Operation:
     Purchased power             540,200      219,200       69,038
     Fuel expense                 86,237       71,271       63,334
     Power cost adjustment        21,866       (6,032)      (6,859)
     Other                       145,374      137,458      132,667
   Maintenance                    41,872       48,722       42,731
   Depreciation                   74,481       71,973       69,705
   Taxes other than income taxes  20,725       21,162       20,658
      Total expenses             930,755      563,754      391,274

INCOME FROM OPERATIONS           191,221      184,749      187,171

OTHER INCOME:
   Allowance for equity funds used
during construction                  300           34           46
   Gas trading activities - Net   (3,208)      (1,181)         -
   Other - Net                    12,364       15,402       12,488
      Total other income           9,456       14,255       12,534

INTEREST CHARGES
   Interest on long-term debt     52,270       53,215       52,165
   Other interest                  8,323        7,546        5,183
   Allowance for borrowed funds
used during construction            (900)        (503)        (353)
      Total interest charges      59,693       60,258       56,995

INCOME BEFORE INCOME TAXES       140,984      138,746      142,710

INCOME TAXES                      45,065       46,472       52,092

NET INCOME                        95,919       92,274       90,618
   Dividends on preferred stock    5,658        5,176        7,463

EARNINGS ON COMMON STOCK       $  90,261    $  87,098    $  83,155


 The accompanying notes are an integral part of these statements.




Idaho Power Company
Consolidated Balance Sheets

Assets

                                         December 31,
                                     1998         1997        1996
                                       (Thousands of Dollars)

ELECTRIC PLANT:
   In service (at original cost)   $2,659,441  $2,605,697     $2,537,565
   Accumulated provision for
depreciation                       (1,009,387)   (942,400)      (886,885)
     In service - Net               1,650,054   1,663,297      1,650,680
   Construction work in progress       58,904      51,892         42,178
   Held for future use                  1,738       1,738          1,773

      Electric plant - Net          1,710,696   1,716,927      1,694,631

INVESTMENTS AND OTHER PROPERTY        105,600      97,065         69,903

CURRENT ASSETS:
   Cash and cash equivalents           20,029       6,905          7,928
   Receivables:
     Customer                          81,227      63,076         34,962
     Allowance for uncollectible
accounts                               (1,397)     (1,397)        (1,394)
     Gas trading                       21,426      42,128            -
     Notes                                467       4,613          5,104
     Employee notes                     4,510       4,757          4,486
     Other (includes $3,164 from
related parties in 1998)                8,502       8,854          8,489
   Accrued unbilled revenues           34,610      33,312         27,709
   Materials and supplies (at
average cost)                          30,143      29,156         24,639
   Fuel stock (at average cost)         7,096       7,172         11,631
   Prepayments                         16,011      15,381         16,165
   Regulatory assets associated
with income taxes                       2,965       3,164          4,397

      Total current assets            225,589     217,121        144,116

DEFERRED DEBITS:
   American Falls and Milner water
rights                                 31,830      32,055         32,260
   Company-owned life insurance        35,149      51,915         57,291
   Regulatory assets associated
with income taxes                     201,465     198,521        196,696
   Regulatory assets - other           62,013      90,239         89,507
   Other                               49,448      47,973         44,334

      Total deferred debits           379,905     420,703        420,088

      TOTAL                        $2,421,790  $2,451,816     $2,328,738

 The accompanying notes are an integral part of these statements.


Idaho Power Company
Consolidated Balance Sheets

Capitalization and Liabilities

                                                December 31,
                                       1998        1997          1996
                                           (Thousands of Dollars)
CAPITALIZATION:
   Common stock equity:
     Common stock, $2.50 par value
(50,000,000 shares authorized;
37,612,351 shares outstanding)     $   94,031   $   94,031   $   94,031
     Premium on capital stock         362,156      362,328      362,297
     Capital stock expense             (3,823)      (3,840)      (3,842)
          Retained earnings           252,137      259,299      242,088
     Accumulated other
comprehensive income                      226         -            -

      Total common stock equity       704,727      711,818      694,574

   Preferred stock                    105,968      106,697      106,975

   Long-term debt                     815,937      746,142      769,810

      Total capitalization          1,626,632    1,564,657    1,571,359

CURRENT LIABILITIES:
   Long-term debt due within one
year                                    6,029       33,998        2,212
   Notes payable                       38,508       57,516       54,016
   Accounts payable                    72,660       69,064       36,370
   Accounts payable gas trading        28,476       42,874         -
   Taxes accrued                       25,164       24,295       17,304
   Interest accrued                    18,364       17,918       15,886
   Deferred income taxes                2,965        3,164        4,397
   Other                               12,117       13,703       12,439

      Total current liabilities       204,283      262,532      142,624

DEFERRED CREDITS:
 Regulatory liabilities associated
with deferred investment
   tax credits                         69,396       70,196       71,283
   Deferred income taxes              420,268      423,736      411,890
   Regulatory liabilities
associated with income taxes           28,075       34,072       35,028
   Regulatory liabilities - other       4,161          509          616
   Other                               68,975       96,114       95,938

      Total deferred credits          590,875      624,627      614,755

COMMITMENTS AND CONTINGENT
   LIABILITIES

      TOTAL                        $2,421,790   $2,451,816   $2,328,738

 The accompanying notes are an integral part of these statements.


Idaho Power Company
Consolidated Statements of Capitalization
                                                 December 31,
                                    1998      %      1997    %   1996   %
                                            (Thousands of Dollars)
COMMON STOCK EQUITY
   Common stock                  $   94,031      $   94,031      $ 94,031
   Premium on capital stock         362,156         362,328       362,297
   Capital stock expense             (3,823)         (3,840)       (3,842)
   Retained earnings                252,137         259,299       242,088
   Accumulated other comprehensive
income                                  226            -             -
      Total common stock equity     704,727   43    711,818  45   694,574  44

PREFERRED STOCK
   4% preferred stock                15,968          16,697        16,975
   7.68% Series, serial preferred
stock                                15,000          15,000        15,000
   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         105,968    7    106,697   7   106,975   7

LONG-TERM DEBT
   First mortgage bonds:
     5.33 % Series due 1998            -             30,000        30,000
     8.65 % Series due 2000          80,000          80,000        80,000
     6.93 % Series due 2001          30,000          30,000        30,000
     6.85 % Series due 2002          27,000          27,000        27,000
     6.40 % Series due 2003          80,000          80,000        80,000
     8    % Series due 2004          50,000          50,000        50,000
     5.83 % Series due 2005          60,000            -             -
     Maturing 2021 through 2031
     with rates ranging
     from 7.5% to 9.52%             230,000         230,000       230,000
      Total first mortgage bonds    557,000         527,000       527,000
   Amount due within one year          -            (30,000)        -
      Net first mortgage bonds      557,000         497,000       527,000
   Pollution control revenue
bonds:
     7 1/4% Series due 2008           4,360           4,360         4,360
     8.30 %  Series 1984 due 2014    49,800          49,800        49,800
     6.05 % Series 1996A due 2026    68,100          68,100        68,100
     Variable Rate Series 1996B
due 2026                             24,200          24,200        24,200
     Variable Rate Series 1996C
due 2026                             24,000          24,000        24,000
      Total pollution control
revenue bonds                       170,460         170,460       170,460
   REA notes                          1,489           1,561         1,632
     Amount due within one year         (74)            (72)          (71)
      Net REA notes                   1,415           1,489         1,561
   American Falls bond guarantee     20,130          20,355        20,560
   Milner Dam note guarantee         11,700          11,700        11,700
   Debt related to investments in
affordable housing with rates
     ranging from 6.97% to
     8.59% due 1999 to 2009          62,103          46,385        33,401
     Amount due within one year      (5,955)         (3,926)       (2,141)
      Net affordable housing debt    56,148          42,459        31,260
   Other subsidiary debt                623           4,316         9,000
   Unamortized premium/discount -    (1,539)         (1,637)       (1,731)
Net

      Total long-term debt          815,937  50     746,142  48   769,810  49

TOTAL CAPITALIZATION             $1,626,632 100  $1,564,657 100$1,571,359 100

 The accompanying notes are an integral part of these statements.



Idaho Power Company
Consolidated Statements of Cash Flows
                                       Year Ended December 31,
                                    1998         1997         1996
                                       (Thousands of Dollars)

OPERATING ACTIVITIES:
   Net income                     $ 95,919     $  92,274   $  90,618
   Adjustments to reconcile net
income to net cash:
     Depreciation and amortization  87,044        80,485      78,228
     Deferred taxes and investment
tax credits                        (10,127)        5,978       7,967
     Accrued PCA costs              21,658        (7,038)     (6,768)
     Change in:
      Accounts receivable and
prepayments                          1,985       (69,589)      5,482
      Accrued unbilled revenue      (1,298)       (5,603)     (2,684)
      Materials and supplies and
fuel stock                            (911)          (57)      2,730
      Accounts payable             (10,658)       75,731      (4,277)
      Taxes accrued                  1,312         6,991       1,895
      Other current assets and
liabilities                           (857)        3,296         673
     Other - net                   (10,340)       (5,562)        551
   Net cash provided by operating
activities                         173,727       176,906     174,415

INVESTING ACTIVITIES:
   Additions to utility plant      (89,644)      (95,633)    (93,645)
   Investments in affordable
housing projects                   (19,139)      (17,021)    (18,281)
   Other investments                  -             -        (20,153)
   Other - net                         867        (1,302)        825
     Net cash used in investing
activities                        (107,916)     (113,956)   (131,254)

FINANCING ACTIVITIES:
   Proceeds from issuance of:
     First mortgage bonds          60,000           -         57,000
     Pollution control revenue       -              -        116,300
bonds
     Long-term debt related to
affordable housing projects        15,718         12,984      17,924
     Other long-term debt            -              -          9,000
   Retirement of:
     Subsidiary long-term debt     (3,316)        (4,700)       -
     First mortgage bonds          (30,000)         -        (20,249)
     Pollution control revenue        -             -       (116,300)
bonds
     Preferred stock                  -             -        (26,530)
   Dividends on common stock       (69,889)      (69,887)    (69,924)
   Dividends on preferred stock     (5,658)       (5,176)     (7,463)
   Increase (decrease) in short-   (18,992)        3,500         996
term borrowings
   Other - net                        (550)         (694)     (4,455)
     Net cash used in financing
activities                         (52,687)      (63,973)    (43,701)

Net increase (decrease) in cash     13,124        (1,023)       (540)
and cash equivalents

Cash and cash equivalents            6,905         7,928       8,468
beginning of period

Cash and cash equivalents at end
of period                         $ 20,029      $  6,905   $   7,928

SUPPLEMENTAL DISCLOSURE OF CASH
FLOW INFORMATION:
   Cash paid during the period
for:
     Income taxes                 $ 55,527      $ 41,786   $  45,050
     Interest (net of amount
capitalized)                      $ 53,806      $ 53,319   $  53,273
   Net assets of affiliates
transferred to parent             $ 27,534          -           -


 The accompanying notes are an integral part of these statements.



Idaho Power Company
Consolidated Statements of Retained Earnings

                                            Year Ended December 31,
                                        1998         1997        1996
                                            (Thousands of Dollars)

RETAINED EARNINGS, BEGINNING OF YEAR   $259,299    $242,088      $229,827

NET INCOME                               95,919      92,274        90,618

   Total                                355,218     334,362       320,445

DIVIDENDS
   Common stock ($1.86 per share)       (69,889)    (69,887)      (69,924)
   Preferred stock                       (5,658)     (5,176)       (7,463)

TRANSFER TO IDACORP, INC.               (27,534)       -             -

PREFERRED STOCK REDEMPTION                 -           -             (970)

RETAINED EARNINGS, END OF YEAR         $252,137    $259,299      $242,088

 The accompanying notes are an integral part of these statements.



Consolidated Statements of Comprehensive Income

                                            Year Ended December 31,
                                        1998         1997           1996
                                            (Thousands of Dollars)

NET INCOME                             $ 95,919    $ 92,274    $  90,618

OTHER COMPREHENSIVE INCOME:
   Unrealized gains on securities
(net of tax of $2,185)                    3,385        -            -
   Minimum pension liability
adjustment (net of tax of $2,054)        (3,159)       -            -

TOTAL COMPREHENSIVE INCOME             $ 96,145    $ 92,274    $  90,618

 The accompanying notes are an integral part of these statements.




Idaho Power Company


Notes to the Consolidated Financial Statements
On October 1, 1998, IDACORP, Inc. (IDACORP) became the parent of
Idaho Power Company and its subsidiaries (IPC).  At that time,
IPC's ownership interests in two subsidiaries were transferred to
IDACORP at book value.  IPC's financial statements include the
following amounts attributable to the transferred subsidiaries for
the periods prior to October 1, 1998:

                                 As of/Year Ended December 31,
                                   1998     1997      1996
                                    (Thousands of Dollars)
  Total assets                  $    -    $ 31,369  $ 33,258
  Net assets                         -      23,311    21,255
  Net income                       3,024     2,057     1,249


Except as modified below, the Notes to the Consolidated Financial
Statements of IDACORP beginning on page 45 of this 1998 Annual
Report on Form 10-K are incorporated herein by reference insofar
as they relate to IPC.

     Note 1  - Summary of Significant Accounting Policies
     Note 3  - Common Stock
     Note 4  - Preferred Stock of Idaho Power Company
     Note 5  - Long-Term Debt
     Note 7  - Notes Payable
     Note 8  - Commitments and Contingent Liabilities
     Note 9  - Employee Benefit Plans
     Note 10 - Electric Plant in Service and Jointly Owned
               Projects



Note 2 - Income Taxes
IPC has settled Federal and Idaho tax liabilities on all open
years through the 1995 tax year except for amounts related to a
partnership which have been, in management's opinion, adequately
accrued.

A reconciliation between the statutory federal income tax rate and
the effective rate is as follows:

                                      1998      1997       1996

  Computed income taxes based on
statutory federal
  income tax rate                 $ 49,344   $ 48,561   $ 49,949
  Change in taxes resulting
from:
   Investment tax credits           (2,934)    (2,887)    (2,835)
   Repair allowance                 (2,800)    (2,800)    (2,800)
   Settlement of prior years tax    (1,965)        23        (16)
returns
   Current state income taxes        6,309      3,587      2,823
   Depreciation                      5,237      5,766      5,945
   Affordable housing tax           (6,880)    (4,519)    (1,777)
credits
   Other                            (1,246)    (1,259)       803
  Total provision for federal    $  45,065   $ 46,472   $ 52,092
and state income taxes
  Effective tax rate                  32.0 %     33.5 %     36.5 %



The provision for income taxes consists of the following:

                                      1998       1997       1996
  Income taxes currently payable:
   Federal                         $ 45,909  $ 35,038    $ 40,379
   State                              9,283     5,456       3,746
    Total                            55,192    40,494      44,125
  Income taxes deferred - Net of
amortization:
   Federal                           (8,006)    6,717       6,877
   State                             (1,321)      348         314
    Total                            (9,327)    7,065       7,191
  Investment tax credits:
   Deferred                           2,134     1,800       3,611
   Restored                          (2,934)   (2,887)     (2,835)
    Total                              (800)   (1,087)        776
  Total provision for income
taxes                              $ 45,065  $ 46,472    $ 52,092



The tax effects of significant items comprising the Company's net
deferred tax liability are as follows:


                                      1998       1997       1996
  Deferred tax assets:
   Regulatory liabilities          $ 28,075  $ 34,072    $ 35,028
   Advances for construction         10,401    18,665      17,736
   Other                             20,457    16,536      13,550
    Total                            58,933    69,273      66,314
  Deferred tax liabilities:
   Electric plant                   247,270   251,938     245,652
   Regulatory assets                204,430   201,685     201,093
   Investment tax credits            69,396    70,196      71,283
   Conservation programs             16,866    14,377      13,720
   Other                             13,600    28,173      22,136
    Total                           551,562   566,369     553,884

  Net deferred tax liabilities     $492,629  $497,096    $487,570




Note 6 - Fair Value of Financial Instruments
The estimated fair value of IPC's financial instruments has been
determined by 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 estimated fair values for long-term debt
and investments are based upon quoted market prices of the same or
similar issues or discounted cash flow analyses as appropriate.

The total estimated fair value of IPC's debt was approximately
$877.4 million in 1998, $801.8 million in 1997 and $806.8 million
for 1996.  Included in investments and other property were
financial instruments totaling $16.5 million in 1997 and $18.0
million in 1996.  Estimated fair value of these instruments was
$19.9 million in 1997 and $18.7 million in 1996.  These
investments were included in the net assets transferred to IDACORP during
1998.


Note 11 - Industry Segment Information
In June 1997 the FASB issued SFAS No. 131, "Disclosures about
Segments of an Enterprise and Related Information."  This
Statement requires financial and descriptive disclosure for fiscal years
beginning after December 15, 1997, about certain operating
segments of an enterprise as well as enterprise-wide disclosure of certain
product and geographic information.

IPC is predominantly a one operating segment company with its
regulated electric operations being the most dominant segment.
Other subsidiaries and non-utility operating segments do not
individually constitute more than 10% of enterprise revenues,
income or assets, nor in aggregate do they comprise more than 25%
of enterprise revenues, income or assets.

IPC's primary business is the generation, transmission,
distribution, purchase and sale of electricity.  IPC also began
natural gas trading activities in May 1997 and reports this
activity in Other Income in the Consolidated Statements of Income.
The following table summarizes the segment information for the
regulated electric operations with a reconciliation to total
enterprise information:

                        Regulated
                        Electric                  Total
                       Operations      Other      Enterprise
                               (Thousands of Dollars)
1998
Revenues                $1,121,976   $     -       $1,121,976
Income from operations     191,221         -          191,221
Other income                 5,909        3,547         9,456
Interest expense            56,646        3,047        59,693
Income before income       140,484          500       140,984
taxes
Income taxes                51,447       (6,382)       45,065
Net income                  89,037        6,882        95,919
Total assets             2,312,919      108,871     2,421,790
Expenditures for long-      91,803       19,197       111,000
lived assets

1997
Revenues                $  748,503   $     -       $  748,503
Income from operations     184,749         -          184,749
Other income                 3,894       10,361        14,255
Interest expense            57,653        2,605        60,258
Income before income       130,990        2,580       133,570
taxes
Income taxes                49,125       (2,653)       46,472
Net income                  81,865        5,233        87,098
Total assets             2,338,524      113,292     2,451,816
Expenditures for long-      98,219       17,457       115,676
lived assets

1996
Revenues                $  578,445   $     -       $  578,445
Income from operations     187,171         -          187,171
Other income                 2,759        9,775        12,534
Interest expense            56,110          885        56,995
Income before income       133,821        1,426       135,247
taxes
Income taxes                51,386          706        52,092
Net income                  82,435          720        83,155
Total assets             2,245,880       82,858     2,328,738
Expenditures for long-      97,484       34,595       132,079
lived assets

Substantially all revenues come from the sale of electricity and
related services, predominately in the United States.  IPC sells
natural gas, solar electric products and systems, control systems
integration services for substations and semiconductor
manufacturing, and miscellaneous other services however, these
revenues are not significant.
INDEPENDENT AUDITORS' REPORT


To The Board of Directors and Shareowners of
Idaho Power Company
Boise, Idaho

We have audited the accompanying consolidated balance sheets and
statements of capitalization of Idaho Power Company and its
subsidiaries as of December 31, 1998, 1997 and 1996, and the
related consolidated statements of income, cash flows, retained
earnings, and comprehensive income for the years then ended.  Our
audits also included the consolidated financial statement schedule
listed in the Index at Item 8.  These financial statements and
financial statement schedule are the responsibility of the
Company's management.  Our responsibility is to express an opinion
on the financial statements and financial statement schedule based
on our audits.

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

In our opinion, such consolidated financial statements present
fairly, in all material respects, the financial position of Idaho
Power Company and subsidiaries at December 31, 1998, 1997 and
1996, 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

Boise, Idaho
January 29, 1999 SUPPLEMENTAL FINANCIAL INFORMATION, UNAUDITED

QUARTERLY FINANCIAL DATA:
The following unaudited information is presented for each quarter
of 1998, 1997 and 1996 (in thousands of dollars, except for per
share amounts).  In the opinion of the Companies, 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.

IDACORP, INC.                           Quarter Ended
                             March 31   June 30  September 30    December 31

1998
 Revenues                   $238,170   $221,622    $392,378      $269,805
 Income from operations       56,555     42,783      47,459        44,424
 Income taxes                 13,125      9,213      12,392         9,900
 Net income                   28,050     20,351      22,305        18,468
 Earnings per share of          0.75       0.54        0.59          0.49
common stock

1997
 Revenues                    155,447    166,975     217,174       208,908
 Income from operations       59,073     41,778      43,877        40,025
 Income taxes                 16,361      9,126      10,715        10,270
 Net income                   28,986     19,377      19,719        19,018
 Earnings per share of          0.77       0.52        0.52          0.51
common stock

1996
 Revenues                    146,629    140,384     149,652       141,781
 Income from operations       58,489     46,741      41,780        40,161
 Income taxes                 17,466     12,828      11,597        10,201
 Net income                   28,259     21,106      17,197        16,593
 Earnings per share of          0.75       0.56        0.45          0.44
common stock



Idaho Power Company                     Quarter Ended
                             March 31   June 30  September 30     December 31
1998
 Revenues                   $238,170   $221,622    $392,378      $269,805
 Income from operations       56,555     42,783      47,459        44,424
 Income taxes                 13,125      9,213      12,392        10,335
 Net income                   29,455     21,768      23,715        20,979
 Dividends on preferred        1,405      1,417       1,410         1,426
stock
 Earnings on common stock     28,050     20,351      22,305        19,553

1997
 Revenues                    155,447    166,975     217,174       208,908
 Income from operations       59,073     41,778      43,877        40,025
 Income taxes                 16,361      9,126      10,715        10,270
 Net income                   30,380     20,042      21,141        20,715
 Dividends on preferred        1,394        665       1,422         1,696
stock
 Earnings on common stock     28,966     19,377      19,719        19,019

1996
 Revenues                    146,629    140,384     149,652       141,781
 Income from operations       58,489     46,741      41,780        40,161
 Income taxes                 17,466     12,828      11,597        10,201
 Net income                   30,211     23,033      19,151        18,225
 Dividends on preferred        1,952      1,927       1,954         1,632
stock
 Earnings on common stock     28,259     21,106      17,197        16,593

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

     None

PART III


Part III has been omitted because the registrants 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 SCHEDULES 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 schedules.
(b)  Reports on SEC Form 8-K.  The following reports on Form 8-K
  were filed for the three months ended December 31, 1998:
              Items Reported                    Date of Report    Filed by
           Item 5, Other Events             September 15, 1998    IDACORP,Inc.
           Item 7, Exhibits

           Item 5, Other Events             October 1, 1998       IDACORP, Inc.
           Item 7, Financial Statements                           and IPC
                   and Exhibits
(c)  Exhibits.

*Previously Filed and Incorporated Herein by Reference

Exhibit      File Number     As Exhibit
*2           333-48031       2           Agreement and Plan of Exchange
                                          between IDACORP, Inc.,and IPC dated
                                          as of February 2, 1998.

*3(a)        33-00440        4(a)(xiii)   Restated Articles of Incorporation
                                          of IPC as filed with the Secretary
                                          of State of Idaho on June 30, 1989.

*3(a)(i)     33-65720        4(a)(ii)     Statement of Resolution Establishing
                                          Terms of Flexible Auction Series A,
                                          Serial Preferred Stock, Without Par
                                          Value (cumulative stated value of
                                          $100,000 per share) of IPC, as filed
                                          with the Secretary of State of Idaho
                                          on November 5, 1991.

*3(a)(ii)    33-65720     4(a)(iii)       Statement of Resolution Establishing
                                          Terms of 7.07% Serial Preferred
                                          Stock, Without Par Value (cumulative
                                          stated value of $100 per share) of
                                          IPC, as filed with the Secretary of
                                          State of Idaho on June 30, 1993.

*3(b)        33-41166     4(b)            Waiver resolution to Restated
                                          Articles of Incorporation of IPC
                                          adopted by Shareholders on May 1,
                                          1991.

*3(c)        33-00440     4(a)(xiv)       By-laws of IPC amended on June 30,
                                          1989, and presently in effect.

*3(d)        33-56071     3(d)            Articles of  Share  Exchange   of
                                          IDACORP,  Inc.  as filed  with  the
                                          Secretary  of  State  of Idaho   on
                                          September 29, 1998.

*3(e)        333-64737    3.1             Articles of Incorporation    of
                                          IDACORP, Inc.

*3(f)        333-64737    3.2             Articles of Amendment to Articles of
                                          Incorporation  of IDACORP,  Inc.  as
                                          filed with the Secretary of State of
                                          Idaho on March 9, 1998.

*3(g)        333-00139    3(b)            Articles  of  Amendment to  Restated
                                          Articles    of Incorporation    of
                                          IDACORP,  Inc.  creating A   Series
                                          Preferred  Stock, without par  value
                                          as filed with the Secretary of State
                                          of Idaho on September 17, 1998.

*3(h)        333-48031    3(c)            Amended  Bylaws of IDACORP, Inc.  as
                                          of September 10, 1998.

*4(a)(i)     2-3413       B-2             Mortgage and Deed of Trust, dated as
                                          of  October 1, 1937, between IPC and
                                          Bankers     Trust Company     and
                                          R. G. Page, as Trustees.

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

*4(b)                                     Instruments relating to IPC American
                                          Falls bond guarantee.  (see Exhibit
                                          10(c)).

*4(c)        33-65720     4(f)            Agreement of IPC 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 IPC and  First Chicago
                                          Trust Company of New York, as Rights
                                          Agent (The Bank of New York,
                                          successor Rights Agent).

*4(e)(i)     1-3198       4(e)(i)          Amendment, dated as of January 30,
             Form 10-K                     1998, related to agreement filed as
             for 1997                      Exhibit 4(e).

*4(f)        Form 8-K     4                Rights Agreement, dated as of
             dated                         September 10, 1998, between IDACORP,
             September 15,                 Inc. and the Bank of New York as
             1998                          Rights Agent.

*10(a)       2-49584      5(b)            Agreements, dated September 22,
                                          1969, between IPC and Pacific
                                          Power & Light Company relating to
                                          the operation, construction and
                                          ownership of the Jim Bridger
                                          Project.

*10(a)(i)    2-51762      5(c)            Amendment, dated February 1, 1974,
                                          relating to operation agreement
                                          filed as Exhibit 10(a).

*10(b)       2-49584      5(c)            Agreement, dated as of October 11,
                                          1973, between IPC and Pacific
                                          Power & Light Company.

*10(c)       33-65720     10(c)           Guaranty  Agreement, dated March 1,
                                          1990, between IPC and West One Bank,
                                          as Trustee, relating to $21,425,000
                                          American Falls Replacement Dam Bonds
                                          of the American Falls Reservoir
                                          District, Idaho.

*10(d)       2-62034      5(r)            Guaranty Agreement, dated as of
                                          August 30, 1974, between IPC and
                                          Pacific Power & Light Company.

*10(e)       2-56513      5(i)            Letter Agreement, dated January 23,
                                          1976, between IPC and Portland
                                          General Electric Company.

*10(e)(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 IPC.

*10(e)(ii)   2-62034      5(t)            Amendment, dated September 30, 1977,
                                          relating to agreement filed as
                                          Exhibit 10(e).

*10(e)(iii)  2-62034      5(u)            Amendment, dated October 31, 1977,
                                          relating to agreement filed as
                                          Exhibit 10(e).

*10(e)(iv)   2-62034      5(v)            Amendment, dated January 23, 1978,
                                          relating to agreement filed as
                                          Exhibit 10(e).

*10(e)(v)    2-62034      5(w)            Amendment, dated February 15, 1978,
                                          relating to agreement filed as
                                          Exhibit 10(e).

*10(e)(vi)   2-68574      5(x)            Amendment, dated September 1, 1979,
                                          relating to agreement filed as
                                          Exhibit 10(e).

*10(f)       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(g)       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
                                          IPC.


*10(h)(i)1   1-3198       10(n)(i)        The Revised Security Plan for Senior
             Form 10-K                    Management Employees - a non-
             for 1994                     qualified, deferred compensation
                                          plan effective August 1, 1996.

*10(h)(ii)1  1-3198       10(n)(ii)       The Executive Annual Incentive Plan
             Form 10-K                    for senior management employees of
             for 1994                     IPC effective January 1, 1995.

*10(h)(iii)1 1-3198       10(n)(iii)      The 1994 Restricted Stock Plan for
             Form 10-K                    officers and key executives of
             for 1994                     IDACORP, Inc. and IPC effective July
                                          1, 1994.

10(h)(iv)1                                The Revised Security Plan for Board
                                          of Directors - a non-qualified,
                                          deferred compensation plan effective
                                          August 1, 1996, revised March 2,
                                          1999.

*10(i)       33-65720     10(h)           Framework Agreement, dated October
                                          1, 1984, between the State of Idaho
                                          and IPC relating to IPC's Swan Falls
                                          and Snake River water rights.

*10(i)(i)    33-65720     10(h)(i)        Agreement, dated October 25, 1984,
                                          between the State of Idaho and IPC
                                          relating to the agreement filed as
                                          Exhibit 10(i).

*10(i)(ii)   33-65720     10(h)(ii)       Contract to Implement, dated October
                                          25, 1984, between the State of Idaho
                                          and IPC relating to the agreement
                                          filed as Exhibit 10(i).

*10(j)       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 IPC and the Twin Falls Canal
                                          Company and the Northside Canal
                                          Company Limited.

*10(j)(i)    33-65720     10(m)(i)        Guaranty Agreement, dated February
                                          10, 1992, between IPC and New York
                                          Life Insurance Company, as Note
                                          Purchaser, relating to  $11,700,000
                                          Guaranteed Notes due 2017 of Milner
                                          Dam Inc.

*10(k)       1-3198       10(y)           Executive Employment Agreement dated
             Form 10-K                    November 20, 1996 between IPC and
             for 1997                     Richard R. Riazzi.

12                                        Statement Re: Computation of Ratio
                                          of Earnings to Fixed Charges.
                                          (IDACORP, Inc.)

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

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

12(c)                                     Statement Re: Computation of
                                          Supplemental Ratio of Earnings to
                                          Combined Fixed Charges and Preferred
                                          Dividend Requirements. (IDACORP,
                                          Inc.)

12(d)                                     Statement Re: Computation of Ratio
                                          of Earnings to Fixed Charges. (IPC)

12(e)                                     Statement Re: Computation of
                                          Supplemental Ratio of Earnings to
                                          Fixed Charges. (IPC)

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

12(g)                                     Statement Re: Computation of
                                          Supplemental Ratio of Earnings to
                                          Combined Fixed Charges and Preferred
                                          Dividend Requirements.
(IPC)

21                                        Subsidiaries of IDACORP,Inc. and
                                          IPC.

23                                        Independent Auditors'   Consent.

27(a)                                     Financial Data Schedule for IDACORP,
                                          Inc.

27(b)                                     Financial Data Schedule for IPC.



IDACORP, Inc.
SCHEDULE II - CONSOLIDATED VALUATION AND QUALIFYING ACCOUNTS
Years Ended December 31, 1998, 1997 and 1996

       Column A        Column B        Column C       Column D    Column E
                                       Additions

                                              Charged
                       Balance At  Charged  (Credited)            Balance At
                       Beginning     to      to Other  Deductions (1)End
    Classification     of Period   Income    Accounts             Of Period

                                    (Thousands of Dollars)

1998:
 Reserves Deducted From
  Applicable Assets:
   Reserve for
uncollectible
     accounts        $1,397      $  -        $ 3,299(2)    $3,299   $1,397
  Other Reserves:
   Rate refunds      $8,740      $4,188      $   -         $7,572   $5,356
   Injuries and
damages reserve      $1,500      $  -        $   -         $  -     $1,500
   Miscellaneous
operating reserves   $8,388      $  512      $   -         $1,993   $6,907

1997:
 Reserves Deducted From
  Applicable Assets:
   Reserve for
uncollectible
     accounts        $1,394     $   -        $3,384(2)     $3,381   $1,397
  Other Reserves:
   Rate refunds      $4,873     $8,740       $   -         $4,873   $8,740

   Injuries and
damages reserve      $1,500     $   -        $   -         $  -     $1,500

   Miscellaneous
operating reserves   $1,774     $  592       $7,245        $1,223   $8,388

1996:
 Reserves Deducted
From
  Applicable Assets:
   Reserve for
uncollectible
     accounts        $1,397     $   -        $3,003(2)     $3,006   $1,394
  Other Reserves:
   Rate refunds      $  -       $4,873       $   -         $  -     $4,873
   Injuries and
damages reserve      $1,500     $   -        $   -         $  -     $1,500

   Miscellaneous
operating reserves   $1,143     $  681       $   -         $   50   $1,774


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


IDAHO POWER COMPANY
SCHEDULE II - CONSOLIDATED VALUATION AND QUALIFYING ACCOUNTS
Years Ended December 31, 1998, 1997 and 1996

Amounts for Idaho Power Company are same as the above Schedule II
for IDACORP, Inc.

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

                                   IDACORP, Inc.
                                   (Registrant)

March 11, 1999                     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 11, 1999
   Joseph W. Marshall            Chief Executive Officer
                                     and Director

By: /s/Jan B. Packwood           President and Chief        "
                                 Operating
   Jan B. Packwood               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/Rotchford L. Barker    By: /s/Evelyn Loveless            "
   Rotchford L. Barker          Evelyn Loveless
   Director                     Director

By: /s/Robert D. Bolinder     By: /s/Jon H. Miller              "
   Robert D. Bolinder           Jon H. Miller
   Director                     Director

By: /s/Roger L. Breezley      By: /s/Peter S. O'Neill           "
   Roger L. Breezley            Peter S. O'Neill
   Director                     Director

By: /s/John B. Carley         By: /s/Phil Soulen                "
   John B. Carley               Phil Soulen
   Director                     Director

By: /s/Peter T. Johnson       By: /s/Robert A. Tinstman         "
   Peter T. Johnson             Robert A. Tinstman
   Director                     Director

By: /s/Jack K. Lemley                                          "

   Jack K. Lemley
   Director

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

                                   IDAHO POWER COMPANY.
                                   (Registrant)

March 11, 1999                     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 11, 1999
   Joseph W. Marshall            Chief Executive Officer
                                     and Director

By: /s/Jan B. Packwood              President and Chief        "
                                     Operating
   Jan B. Packwood                 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/Rotchford L. Barker    By: /s/Evelyn Loveless            "
   Rotchford L. Barker          Evelyn Loveless
   Director                     Director

By: /s/Robert D. Bolinder     By: /s/Jon H. Miller              "
   Robert D. Bolinder           Jon H. Miller
   Director                     Director

By: /s/Roger L. Breezley      By: /s/Peter S. O'Neill           "
   Roger L. Breezley            Peter S. O'Neill
   Director                     Director

By: /s/John B. Carley         By: /s/Phil Soulen                "
   John B. Carley               Phil Soulen
   Director                     Director

By: /s/Peter T. Johnson       By: /s/Robert A. Tinstman         "
   Peter T. Johnson             Robert A. Tinstman
   Director                     Director

By: /s/Jack K. Lemley                                          "
   Jack K. Lemley
   Director




EXHIBIT INDEX

Exhibit                                                    Page
Number                                                    Number

10(h)(iv)      The Revised Security Plan for               81
               Board of Directors - a non-
               qualified, deferred
               compensation plan effective
               August 1, 1996, revised March
               2, 1999.

12             Statements Re: Computation of               103
               Ratio of Earnings to Fixed
               Charges.  (IDACORP, Inc.)

12(a)          Statements Re: Computation of               104
               Supplemental Ratio of
               Earnings to Fixed Charges.
               (IDACORP, Inc.)

12(b)          Statements Re: Computation of               105
               Ratio of Earnings to Combined
               Fixed Charges and Preferred
               Dividend Requirements.
               (IDACORP, Inc.)

12(c)          Statements Re: Computation of               106
               Supplemental Ratio of
               Earnings to Combined Fixed
               Charges and Preferred
               Dividend Requirements.
               (IDACORP, Inc.)

12(d)          Statements Re: Computation of               107
               Ratio of Earnings to Fixed
               Charges.  (IPC)

12(e)          Statements Re: Computation of               108
               Supplemental Ratio of
               Earnings to Fixed Charges.
               (IPC)

12(f)          Statements Re: Computation of               109
               Ratio of Earnings to Combined
               Fixed Charges and Preferred
               Dividend Requirements.  (IPC)

12(g)          Statements Re: Computation of               110
               Supplemental Ratio of
               Earnings to Combined Fixed
               Charges and Preferred
               Dividend Requirements.  (IPC)

21             Subsidiaries of IDACORP, Inc.               111
               and IPC

23             Independent Auditors'                       112
               Consent.

27(a)          Financial Data Schedule for                 113
               IDACORP, Inc.

27(b)          Financial Data Schedule for                 114
               IPC