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

X     ANNUAL REPORT PURSUANT TO SECTION 13 OR 15 (D) OF THE SECURITIES
			EXCHANGE ACT OF 1934
      For the fiscal year ended December 31, 2001
				 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 Registrant
		  as specified in its charter,
Commission       address of principal executive      IRS Employer
File Number       offices and telephone number    Identification Number
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
Preferred Stock Purchase Rights                   New York and Pacific


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

Indicate by check mark whether the registrant (1) has filed all
reports required to be filed by Section 13 or 15(d) of the
Securities Exchange Act of 1934 during the preceding 12 months (or
for such shorter period that the registrant was required to file
such reports), and (2) has been subject to such filing requirements
for the past 90 days.
Yes  ( X  )  No  (    )

Indicate by check mark if disclosure of delinquent filers pursuant
to Item 405 of Regulation S-K is not contained herein, and will not
be contained, to the best of 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:  None

Number of shares of common stock outstanding at February 28, 2002:
37,612,351 shares, all of which are held by
					 IDACORP, Inc.

Documents Incorporated by Reference:
Part III,Item 10 - 13    Portions of the joint definitive proxy
	       statement of the Registrant to be filed pursuant to
	       Regulation 14A for the 2002 Annual Meeting of
	       Shareholders to be held on May 16, 2002.








			  GLOSSARY

AFDC         - Allowance for Funds Used During Construction
APB          - Accounting Principles Board
BPA          - Bonneville Power Administration
CSPP         - Cogeneration and Small Power Production
DIG          - Derivatives Implementation Group
DSM          - Demand-Side Management
EITF         - Emerging Issue Task Force
EPA          - Environmental Protection Agency
FASB         - Financial Accounting Standards Board
FERC         - Federal Energy Regulatory Commission
FPA          - Federal Power Act
Ida-West     - Ida-West Energy
IE           - IDACORP Energy
IFS          - IDACORP Financial Services
IPC          - Idaho Power Company
IPUC         - Idaho Public Utilities Commission
IRP          - Integrated Resource Plan
kW           - kilowatt
kWh          - kilowatt-hour
MD&A         - Management's Discussion and Analysis
MW           - Megawatt
MWh          - Megawatt-hour
OPUC         - Oregon Public Utility Commission
PCA          - Power Cost Adjustment
PUCN         - Public Utility Commission of Nevada
PURPA        - Public Utilities Regulatory Policy Act
REA          - Rural Electrification Administration
RFP          - Request for proposals
RTOs         - Regional Transmission Organizations
SFAS         - Statement of Financial Accounting Standards
SPPCo        - Sierra Pacific Power Company
Valmy        - North Valmy Steam Electric Generating Plant






			  TABLE OF CONTENTS


PART I

PAGE

 ITEM 1. BUSINESS                                              1
 ITEM 2. PROPERTIES                                           10
 ITEM 3. LEGAL PROCEEDINGS                                    11
 ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS  11

 EXECUTIVE OFFICERS OF THE REGISTRANT                         12

PART II

 ITEM 5. MARKET FOR THE REGISTRANT'S COMMON STOCK AND RELATED
	 STOCKHOLDER MATTERS                                  14
 ITEM 6. SELECTED FINANCIAL DATA                              14
 ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
	 CONDITION AND RESULTS OF OPERATIONS                  15
 ITEM 7A.QUANTITATIVE AND QUALITATIVE DISCLOSURE ABOUT
	 MARKET RISK                                          29
 ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA          30
 ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON
	 ACCOUNTING AND FINANCIAL DISCLOSURE                  56

PART III

 ITEM 10.DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT*  56
 ITEM 11.EXECUTIVE COMPENSATION*                              56
 ITEM 12.SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND
	 MANAGEMENT*                                          56
 ITEM 13.CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS*      56

PART IV

 ITEM 14.EXHIBITS, FINANCIAL STATEMENT SCHEDULE AND REPORTS
	 ON FORM 8-K                                          56

 SIGNATURES                                                   61

 *INCORPORATED BY REFERENCE.




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.

PART I


ITEM 1.  BUSINESS


OVERVIEW
Idaho Power Company (IPC) was incorporated under the laws of the
state of Idaho in 1989 as successor to a Maine corporation organized
in 1915.  IPC is a parent to Idaho Energy Resources Co., a joint
venturer in Bridger Coal Company, which supplies coal to IPC's Jim
Bridger generating plant.

The outstanding shares of IPC's common stock were exchanged on a
share-for-share basis into common stock of IDACORP, Inc. (IDACORP)
on October 1, 1998 and are no longer actively traded.  IPC's
preferred stock and debt securities were unaffected and remain
outstanding with IPC.

Over the last several years, IPC has transferred to its parent,
IDACORP, ownership of several of its subsidiaries.  Effective
January 2000, ownership of IDACORP Financial Services (IFS) and
Applied Power Company (sold January 2001) were transferred to
IDACORP.

Effective June 11, 2001 IPC transferred its non-utility wholesale
electricity marketing operations (Energy Marketing) to IDACORP
Energy (IE), a subsidiary of IDACORP.  See Note 11 to the
Consolidated Financial Statements "Discontinued Operations."  After
the transfer of Energy Marketing, IPC consists of one operating
segment, Utility Operations.  The Utility Operations segment has two
primary sources of income, the regulated operations of IPC and
income from its joint venture in Bridger Coal Company.

IPC is an electric utility regulated by the Federal Energy
Regulatory Commission (FERC) and the state regulatory commissions
of Idaho, Oregon, Nevada and Wyoming, and is involved in the
generation, purchase, transmission, distribution and sale of
electric energy in a 20,000 square mile area in southern Idaho and
eastern Oregon, with an estimated population of 873,000.  IPC
holds franchises in 72 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 and three counties in Oregon.  As of December 31, 2001, IPC
supplied electric energy to over 401,000 general business
customers and had 1,688 full-time employees.

IPC owns and operates 17 hydroelectric power plants, one natural
gas-fired plant and shares ownership in three coal-fired
generating plants.  These generating plants and their capacities
are listed in Item 2. "Properties."  IPC's coal-fired plants are
in Wyoming, Oregon and Nevada, and use low-sulfur coal from
Wyoming and Utah.

IPC relies heavily on hydroelectric power for its generating needs
and is one of the nation's few investor-owned utilities with a
predominantly hydroelectric generating base.  Because of its
reliance on hydro generation, IPC's generation operations can be
significantly affected by the weather.  The availability of
inexpensive hydroelectric power depends on snowpack in the
mountains above IPC's hydro facilities, precipitation and other
weather and streamflow management considerations. When
hydroelectric generation decreases and customer demand increases,
IPC increases its use of more expensive thermal generation and
purchased power.

The rates IPC charges to its general business customers are
determined by the various regulatory authorities.  Approximately
95 percent of IPC's general business revenue and sales come from
customers in Idaho.  The rates charged to these customers are
adjusted annually by a power cost adjustment (PCA) mechanism.  The
PCA adjusts rates to reflect the changes in costs incurred by IPC
to supply power.  Throughout the year, IPC compares its actual
power supply costs to the amounts it is recovering in rates.
Most, but not all, of this difference is deferred and included in
the calculation of rates for future years.  The PCA is discussed
in more detail below in "Rates" and in Note 12 to the Consolidated
Financial Statements.

The primary influences on electricity sales are weather and
economic conditions.  Generally, extreme temperatures increase
sales to customers, who use electricity for cooling and heating,
and moderate temperatures decrease sales.  Precipitation levels
during the growing season affect sales to customers who use
electricity to operate irrigation pumps.  Increased precipitation
reduces electricity usage by these customers.

IPC's principal commercial and industrial customers are involved
in: food processing, electronics and general manufacturing,
lumber, beet sugar refining, and the skiing industry.


Regulation
IPC is under the regulatory jurisdiction (as to rates, service,
accounting and other general matters of utility operation) of the
FERC, the Idaho Public Utilities Commission (IPUC), the Oregon
Public Utility Commission (OPUC) and the Public Utility Commission
of Nevada (PUCN).  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  (FPA) 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
Public Utilities Regulatory Policy Act of 1978 (PURPA), the state
regulatory agencies have each issued orders and rules regulating
IPC's purchase of power from Cogeneration and Small Power
Production (CSPP) facilities.

As a licensee under the FPA, 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 FPA 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 FPA or
IPC's FERC license (see Item 2. "Properties").

Rates
Idaho Jurisdiction:  IPC has a PCA mechanism that provides for
annual adjustments to the rates charged to its Idaho retail electric
customers.  These adjustments, which take effect annually in May,
are based on forecasts of net power supply expenses and the true-up
of the prior year's forecast.  During the year, the difference
between the actual costs incurred and the forecasted costs is
deferred, with interest.  The balance of this deferral, called a
true-up, is then included in the calculation of the next year's PCA
adjustment.

So far in the 2001-2002 rate year actual power supply costs included
in the PCA have been significantly greater than forecast due to
purchased power volumes and prices being greater than originally
forecasted and the implementation of the voluntary load reduction
payments with Astaris and the irrigation customers.  To account for
these higher-than-forecasted costs, and the unamortized portion of
the 2000-2001 PCA balance, IPC has recorded regulatory assets of
$290 million as of December 31, 2001.

In the 2001 PCA filing, IPC requested recovery of $227 million of
power supply costs.  In May, the IPUC authorized recovery of $168
million, but deferred recovery of $59 million pending further
review.  The approved amount resulted in an average rate increase of
31.6 percent.  After conducting hearings on the remaining $59
million the IPUC authorized recovery of $48 million plus $1 million
of accrued interest, beginning in October 2001.  The remaining $11
million not recovered in rates from the PCA filing was written off
in September 2001.

Other Jurisdictions: IPC filed an application with the OPUC to
begin recovering extraordinary 2001 power supply costs in its
Oregon jurisdiction.  On June 18, 2001, the OPUC approved new
rates that would recover $1 million over the next year.  Under the
provisions of the deferred accounting statute, annual rate
recovery amounts were limited to three percent of IPC's 2000 gross
revenues in Oregon.  During the 2001 session, the Oregon
Legislature amended the statute giving the OPUC authority to
increase the maximum annual rate of recovery of deferred amounts
to six percent for electric utilities.  IPC subsequently filed on
October 5, 2001 to recover an additional three percent
extraordinary deferred power supply costs.  As a result of this
filing, the OPUC issued Order No. 01-994 allowing IPC to increase
its rate of recovery to six percent effective November 28, 2001.
The Oregon deferral balance is $15 million as of December 31,
2001, net of the June 18, 2001 and November 28, 2001 recovery.

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 wholesalers. IPC's generating stations and capacities
are listed in "Item 2.  Properties."

IPC's system is dual peaking, with the larger peak demand
generally occurring in the summer.  The system peak demand for
2001 was 2,570 MW, set on July 2, 2001.  Peak demands in 2000 and
1999 were 2,919 MW and 2,839 MW, respectively.  IPC expects total
system energy requirements to grow 2.2 percent annually over the
next three years.

The amounts of electricity IPC is able to generate from its hydro
plants depend on a number of factors, primarily snowpack in the
mountains above its hydro facilities, reservoir storage, and
streamflow requirements.  When these factors are favorable, IPC can
generate more electricity using its hydroelectric plants.  When these
factors are unfavorable, IPC must increase its reliance on more
expensive thermal plants and purchased power.

Below normal water conditions in 2001 yielded a system generation mix
of 43 percent hydro and 57 percent thermal.  Historically, under
normal water conditions, IPC's system generation mix is approximately
57 percent hydro and 43 percent thermal.

The Snake River Basin snowpack numbers offer the promise of
improved streamflows for 2002.  IPC's mid-February 2002
accumulations were 84 percent of normal, compared to 51 percent at
the same time a year earlier.  Even though snowpack is closer to
normal, reservoir storage is not, meaning hydro conditions will
not fully return to normal in 2002.

In September 2001, IPC placed in service Danskin Power Plant, a 90-
MW natural gas-fired combustion turbine plant, located near
Mountain Home, Idaho.

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 NorthWestern Energy
under a contract that expires December 2003 and with Seattle City
Light under a contract that expires October 2002.

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),
Avista Corporation, PacifiCorp, NorthWestern Energy 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 all major 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.  These groups are being formed
to more efficiently coordinate transmission reliability and
planning throughout the western grid.  See "Competition -
Wholesale" discussion below.

Integrated Resource Plan (IRP):  Every two years, IPC is required
to file with the IPUC and OPUC an IRP, a comprehensive look at
IPC's present and future demands for electricity and plans for
meeting that demand.  The 2000 IRP identified a potential
electricity shortfall within our utility service territory by mid-
2004.  The plan projected a 250-MW resource need in 2004 to
satisfy energy demand during IPC's peak periods.  The IRP calls
for IPC to use purchases from the Northwest energy markets to meet
short-term energy needs.  The 2000 IRP anticipates that after
2004, transmission constraints will not allow IPC to cover
increasing demand using wholesale purchases from the Pacific
Northwest.

As a result of the 2000 IRP, IPC issued a request for proposals
(RFP), seeking bids for 250-MWs of additional generation to
support the growing demand in IPC's utility service territory.  A
proposal by Garnet Energy LLC, a subsidiary of Ida-West (a
subsidiary of IDACORP), was selected by IPC.  In December 2001,
IPC signed an agreement with Garnet to define the conditions under
which the utility will purchase energy to be produced by Garnet's
proposed 273-MW natural gas-fired, combined cycle combustion
turbine facility in Canyon County, Idaho, located in the southwest
part of the state.  In December 2001, IPC filed an application
with the IPUC requesting authorization to include Garnet related
expenses in IPC's PCA.  On February 27, 2002, the IPUC tentatively
set hearings in June 2002 to hear Idaho Power's request.

CSPP Purchases:  As a result of the enactment of the 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 total cost of power purchased from
CSPP projects was $45 million in 2001.  During 2001, IPC purchased
728,155 MWh from these private developers at a blended price of 6.2
cents per kWh.

The IPUC has 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 and has
limited the length of new contracts to a maximum of five years.

Wholesale Power Sales:  IPC has firm wholesale power sales contracts
with five entities.  These contracts are for various amounts of
energy, up to 36 average megawatts, and are of various lengths
expiring between 2002 and 2009.

Transmission Services: IPC has a long history of providing wholesale
transmission service and provides various firm and non-firm wheeling
services for several surrounding utilities.  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.

In December 1999, the FERC issued Order No. 2000 encouraging
companies with transmission assets to form Regional Transmission
Organizations (RTOs).  See further discussion in "Competition -
Wholesale."

Fuel
IPC, through its subsidiary Idaho Energy Resources Co., owns a one-
third interest in the Bridger Coal Company, which owns the Jim
Bridger 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.  The Jim Bridger 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 Black Butte and Leucite Hills mines located near
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.

SPPCo, with whom IPC is a joint (50/50) participant in the
ownership and operation of the North Valmy Steam Electric
Generating plant (Valmy), has a long-term coal contract with
Southern Utah Fuel Company, a subsidiary of Canyon Fuel Co., LLC.
This contract, which expires on June 30, 2003, calls 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.

In 1986, IPC and SPPCo signed a long-term coal supply agreement with
the Black Butte Coal Company.  Black Butte is expected to
discontinue delivery to the Valmy project as IPC has fulfilled its
purchase obligation specified in the coal supply agreement.  This
agreement had provided for Black Butte to supply coal to the Valmy
project under a flexible delivery schedule that allowed for
variations in the number of tons to be delivered ranging from a
minimum of 300,000 tons per year to a maximum of one million tons
per year.

SPPCo is currently negotiating a coal sales agreement with Arch Coal
Sales Company, Inc. to supply coal to the Valmy project from 2002
through 2006.  IPC would be obligated to purchase one-half of the
coal, ranging from approximately 515,000 tons to 762,500 tons
annually, under this agreement.

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 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 FPA.  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 proceeding
and is expected to continue for at least the next 10 years.  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.

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

Based upon present environmental laws and regulations, IPC estimates
its 2002 capital expenditures for environmental matters, excluding
allowance for funds used during construction (AFDC), will total $14
million.  Studies and measures related to mitigation of environmental
concerns due to relicensing of hydro facilities account for $10
million and investments in environmental equipment and facilities at
the thermal plants account for $4 million.  During the 2003-2004
period, environmental-related capital expenditures are estimated to
be $31 million.  IPC anticipates $23 million in annual operating
costs for environmental facilities during the 2002-2004 period.

Clean Air:  IPC has analyzed the Clean Air Act legislation and its
effects upon IPC and its customers.  IPC's coal-fired plants in
Oregon and Nevada 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.  IPC has sufficient
SO2 allowances to provide compliance for all three coal-fired
facilities and its Danskin natural gas-fired facility.  Therefore,
IPC does not foresee any material adverse effects upon its operations
with regard to SO2 emissions.

In July 1997, the Environmental Protection Agency (EPA) announced new
National Ambient Air Quality Standards for ozone and Particulate
Matter (PM) and in July 1999 the EPA announced regional haze
regulations for protection of visibility in national parks and
wilderness areas.  On May 14, 1999, a federal court ruling blocked
implementation of these standards, which EPA proposed in 1997.  In
November 2000, the EPA appealed to the U.S. Supreme Court to
reconsider that decision.  No ruling has been made by the court as of
December 31, 2001.  Impacts of the ozone and PM regulations and
regional haze regulations on IPC's thermal operations are unknown at
this time.

Valmy, Boardman and Jim Bridger Unit 4 elected to meet Phase I
nitrogen oxide (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 NO x limits until 2008.  Had
the units not voluntarily "early elected," they would have been
required to meet the Phase II limits in 2000.  Jim Bridger Units
1, 2, and 3 were accepted as substitution units in 1995 and are
subject to NO x limits of Phase I instead of the more restrictive
limits of Phase II.  Jim Bridger has installed low NO x equipment
to reduce NO x levels even lower than currently required.

The Danskin gas turbine plant in Mountain Home is operating in
compliance with a "permit to construct" issued by the Idaho
Department of Environmental Quality.  The units are fitted with dry-
low- NO x burners and a continuous emissions monitoring system.
This will ensure that the facility will operate within the permitted
federal and state NO x and carbon monoxide limits.

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 period
from May 15 to October 15 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, Shoshone Falls,
Twin Falls, Upper Salmon, Lower Salmon and Bliss 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 by the Idaho Department of Fish and Game.  At
December 31, 2001, the investment in these facilities was $10 million
and the annual cost of operation pursuant to FERC License 1971 is
approximately $2 million.

Endangered Species:  Several species of fish and Snake River snails
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 Operations - Environmental and
Legal Issues."

Hazardous/Toxic Wastes and Substances:  Under the Toxic Substances
Control Act (TSCA), the 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.  This program will save costs
associated with the long-term monitoring and testing of equipment and
grounds for PCB contamination as well as being good for the
environment.  Total costs for the identification and disposal of PCBs
from IPC's system were less than $1 million each year for 2001, 2000
and 1999, respectively.  IPC believes that all generation facilities
are presently non-PCB.

Competition
Retail:  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.

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 changes
and conforming regulations may result in increased retail
competition.  In 1997, the Idaho Legislature appointed a committee
to study restructuring of the electric utility industry.  Although
the committee will continue studying a variety of restructuring
ideas, it has not recommended any restructuring legislation and is
not expected to in the foreseeable future.  In 1999, the Oregon
legislature passed legislation restructuring the electric utility
industry,
but exempted IPC's service territory.

Wholesale:  The 1992 Energy Act (Energy Act) and the FERC's
rulemaking activities have established the regulatory framework to
open the wholesale energy market to competition.  The Energy Act
permits utilities to develop independent electric generating
plants for sales to wholesale customers, and authorizes the FERC
to order transmission access for third parties to transmission
facilities owned by another entity.  The Energy Act does not,
however, permit the FERC to require transmission access to retail
customers.  Open-access transmission for wholesale customers
provides energy suppliers with opportunities to sell and deliver
electricity at market-based prices.

In December 1999 the FERC, in its landmark Order 2000, said that all
companies with transmission assets must file to form RTOs or explain
why they cannot.  Order 2000 is a follow up to Orders No. 888 and
889 issued in 1996, which required transmission owners to provide
non-discriminatory transmission service to third parties.  By
encouraging the formation of RTOs, the FERC seeks to further
facilitate the formation of efficient, competitive wholesale
electricity markets.

In response to FERC Order 2000, IPC and other regional transmission
owners filed, in October 2000, a plan to form RTO West, an entity
that will operate the transmission grid in seven western states.
RTO West will have its own independent governing board.  The
participating transmission owners will retain ownership of the
lines, but will not have a role in operating the grid.

This previous FERC filing represents a portion of the filing
necessary to form RTO West.  However, substantial additional filings
will be necessary to include the tariff and integration agreements
associated with the new entity.  There will also need to be filings
for state approvals.  IPC expects the "Stage 2" FERC filing to be
completed by March 2002.  State filings may be initiated in late
2002.

Utility Operating Statistics
The following table presents IPC's revenues and volumes for the last
three years:

				       Years Ended December 31,
				      2001        2000        1999

Revenues (thousands of dollars)
     Residential                   $260,251      225,336       213,547
     Commercial                     164,019      132,023       123,069
     Industrial                     154,318      133,171       117,366
     Irrigation                      72,020       74,827        62,166
       Total general business       650,608      565,357       516,148
     Off-system sales               219,966      229,986       119,785
     Other                           41,738       40,319        22,403
       Total                       $912,312      835,662       658,336


Energy use (thousands of MWhs)
     Residential                      4,307        4,393         4,200
     Commercial                       3,380        3,404         3,194
     Industrial                       3,925        4,808         4,666
     Irrigation                       1,419        1,993         1,706
       Total general business        13,031       14,598        13,766
     Off-system sales                 2,387        4,529         5,924
       Total                         15,418       19,127        19,690


RESEARCH AND DEVELOPMENT
In 2001, IPC spent approximately $2 million to promote energy
efficiency, including payments of $1 million to the Northwest
Energy Efficiency Alliance and amounts totaling less than $1
million to low-income weatherization programs in Idaho and Oregon.
In addition to increasing the funding level for low-income
weatherization, IPC began a new conservation program late in the
year funded through a conservation credit from the BPA to assist
customers coping with higher winter electricity bills.

During 2001, IPC spent less than $1 million on research and
development through membership in Electric Power Research
Institute (EPRI).  EPRI creates science technology solutions for
the global energy and energy service.  Some of the subjects of
EPRI projects include: risk based system planning, understanding
green power markets, wind generated electricity and renewable
energy application in distribution generation.

CAPITAL REQUIREMENTS
Capital expenditures of $391 million and debt maturities of $157
million are expected to be paid from 2002 through 2004.  IPC
utility construction expenditures exclude AFDC.  Over the next
three years internally generated cash and debt issuances are
expected to meet the majority of the funds needed to meet our
capital requirements.  Internally generated cash is expected to
provide 100 percent in 2002 and an average of 82 percent in 2003
and 2004.

					 2002        2003-2004
					 (Millions of dollars)
 Capital Expenditures (excluding
 AFDC):
  Construction Expenditures:
    Generating facilities
      Hydro                             $ 15          $ 35
      Thermal                             13            27
	Total generating facilities       28            62
    Transmission lines and
      substations                         18            46
    Distribution lines and
      substations                         57           119
    General                               21            40
	Total construction
	  expenditures                   124           267
  Long-term debt maturities               27           130
  Other                                    3             9
    Total capital requirements          $154          $406


IPC has no nuclear involvement and its future construction plans
do not include development of any nuclear generation.  IPC's
capital expenditures are primarily for maintaining current
infrastructures and meeting anticipated electricity demands.
Various options that may be available to meet the future energy
requirements of its customers including efficiency improvements on
IPC's generation, transmission and distribution systems and
purchased power and exchange agreements with other utilities or
other power suppliers.  IPC will pursue the projects that best
meet its future energy needs.

The above 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.  IPC 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, 2001, net earnings were 6.44 times.
Additional preferred stock may be issued when earnings for twelve
consecutive months within the preceding fifteen months are at
least equal to 1.75 times the aggregate annual interest
requirements on all debt securities and dividend requirements on
preferred stock.  At December 31, 2001, the actual preferred
dividend earnings coverage was 2.79 times.  If the dividends on
the shares of Auction Preferred Stock were to reach the maximum
allowed, the preferred dividend earnings coverage would be 2.55
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.

CREDIT RATINGS
All of the Company's publicly traded debt have received investment
grade ratings from each of the three major credit rating agencies.
The changes in the energy industry and the recent bankruptcy of
Enron Corp. have caused the rating agencies to refocus their
attention on the credit characteristics and credit protection
measures of industry participants and in some cases the rating
agencies appear to have tightened the standards for a given rating
level.  The Company will continue to evaluate its capital structure,
financing requirements, competitive strategies and future capital
expenditures to try to maintain investment grade ratings.  However,
there is no assurance that these current ratings will continue for
any given period of time or that they will not be revised by the
rating agencies, if, in their respective judgments, circumstances
so warrant.  Any downgrade or revision may adversely affect the
market price of the Company's securities and serve to increase
its cost of capital.


ITEM 2.  PROPERTIES
IPC's system includes 17 hydroelectric generating plants located
in southern Idaho and eastern Oregon (detailed below), one natural
gas-fired plant and an interest in three coal-fired steam electric
generating plants.  The system also includes approximately 4,653
miles of high voltage transmission lines; 21 step-up transmission
substations located at power plants; 18 transmission substations;
7 transmission switching stations; and 208 energized distribution
substations (excludes mobile substations and dispatch centers).

IPC holds licenses under the FPA for 13 hydroelectric projects
from the FERC.  These and the other generating stations and their
capacities are listed below:

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

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    1999   (a)
 Shoshone Falls                    12,500      12,500    1999   (a)
 C J Strike                        89,000      82,800    2000   (a)
 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    2040
Steam and Other Generating
  Plants:
 Other Hydroelectric               10,400      11,300
 Jim Bridger (coal-fired)         706,667     709,617
 Valmy (coal-fired)               260,650     260,650
 Boardman (coal-fired)             55,200      56,050
 Danskin (gas-fired)              100,000      90,000
 Salmon (diesel-internal            5,500       5,000
   combustion)

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

At December 31, 2001, the composite average ages of the principal
parts of IPC's system, based on dollar investment, were:
production plant, 18 years; transmission system and substations,
20 years; and distribution lines and substations, 15 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 FPA 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.

Jim Bridger, Valmy and Boardman are jointly owned generating
facilities.  IPC's ownership percentages are thirty-three, fifty
and ten, respectively.

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.

Relicensing
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 it is in the public interest for IPC to continue to hold the
federal licenses.

IPC is actively pursuing new licenses for 10 of its 17
hydroelectric projects from the FERC.  This process will continue
for the next ten to 15 years, depending on environmental issues
and political processes.

The most significant relicensing effort is the Hells Canyon
Complex, which provides over half of IPC's hydro generation
capacity and 40 percent of its total generating capacity.
Presently, IPC is developing its draft license application with
the assistance of a collaborative team made up of individuals
representing state and federal agencies, businesses,
environmental, tribal, customer, local government and local
landowner interests.  IPC expects to file the draft license
application in September 2002, with the final application
following in July 2003.

Shoshone Falls, Upper Salmon Falls, Lower Salmon Falls and Bliss
hydroelectric projects are awaiting an Environmental Impact
Statement (EIS) from the federal government, which is necessary
prior to license issuance.  IPC completed 64 Additional
Information Requests (AIRs) from the agencies and non-governmental
organizations in early 2000 which, combined with recently filed,
final recommendations, terms and conditions, was used by the FERC
to produce a draft EIS for these projects in January 2002.
A final EIS is expected in August 2002.

IPC filed its application for a new license for the C J Strike
project in November 1998.  Similarly, 21 AIRs were issued on this
project and the FERC has noticed that this project is Ready for
Environmental Analysis, which gives the agencies and interested
parties 60 days to provide their final recommendations, terms and
conditions for this project.  A draft EIS is expected by June
2002.

The Upper and Lower Malad projects are on schedule to file the new
license application in July 2002.  The draft application was sent
to agencies and non-governmental organizations in October 2001.




ITEM 3.  LEGAL PROCEEDINGS
     None




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


     None





EXECUTIVE OFFICERS OF THE REGISTRANT

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

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

Jan B. Packwood, 57          Appointed March 1, 2002.  Mr.
Chief Executive Officer      Packwood was President and Chief
			     Executive Officer from May 30, 1999
			     to March 1, 2002, President and Chief
			     Operating Officer from September 1,
			     1997 to May 30, 1999 and Executive
			     Vice President from July 11, 1996 to
			     September 1, 1997.

J. LaMont Keen, 49           Appointed March 1, 2002.  Mr. Keen
President and Chief          was Senior Vice President-
Operating Officer            Administration and Chief Financial
			     Officer from May 5, 1999 to March 1,
			     2002, Senior Vice President-
			     Administration, Chief Financial
			     Officer and Treasurer from March 15,
			     1999 to May 5, 1999 and Vice
			     President, Chief Financial Officer
			     and Treasurer from March 14, 1996 to
			     March 15, 1999.

James C. Miller, 47          Appointed November 18, 1999.  Mr.
Senior Vice President -      Miller was Vice President -
Delivery                     Generation from July 10, 1997 to
			     November 18, 1999 and was General
			     Manager - Generation prior to July
			     10, 1997.

Darrel T. Anderson, 43       Appointed March 1, 2002.  Mr.
Vice President, Chief        Anderson was Vice President-Finance
Financial Officer and        and Treasurer from May 5, 1999 to
Treasurer                    March 1, 2002, Corporate Controller
			     from January 25, 1999 to May 5, 1999,
			     Executive Vice President of Finance
			     and Operations at Applied Power Corp.
			     from June 5, 1998 to January 25,
			     1999, and Corporate Controller from
			     February 26, 1996 to June 5, 1998.

John R. Gale, 51             Appointed March 15, 2001.  Mr. Gale
Vice President, Regulatory   was General Manager of Pricing &
Affairs                      Regulatory Services (1997-2001).

Bryan A.B. Kearney, 39       Appointed November 18, 1999.  Mr.
Vice President and Chief     Kearney was Vice President and Chief
Information Officer          Technology Officer at Bear Creek Corp
			     (1998-1999) and Chief Information
			     Officer for Shasta County, California
			     (1996-1998).

Gregory W. Panter, 53        Appointed April 1, 2001.  Mr. Panter
Vice President - Public      was self-employed with Panter &
Affairs                      Associates from 1989 to 2001.

John P. Prescott, 45         Appointed November 18, 1999.  Mr.
Vice President - Generation  Prescott was Vice President of
			     Business Development for IDACORP
			     Technologies, Inc. from August 1999
			     to November 18, 1999, and President
			     and Treasurer of Stellar Dynamics
			     from October 5, 1995 to August 1999.

Cliff N. Olson, 52           Appointed July 11, 1991.
Vice President - Corporate
Services

Robert W. Stahman, 57        Appointed July 13, 1989.
Vice President - General
Counsel and Secretary

Marlene K. Williams, 49      Appointed May 5, 1999.  Ms. Williams
Vice President - Human       was Director of Human Resources at
Resources                    Arizona Public Service prior to May
			     5, 1999.





PART II




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

The outstanding shares of Idaho Power Company common stock ($2.50
par value) are held by IDACORP, Inc. and are not traded. IDACORP,
Inc. became the holding company of Idaho Power Company on October
1, 1998.



ITEM 6.  SELECTED FINANCIAL DATA

SUMMARY OF OPERATIONS (thousands of dollars)
For the Years Ended
December 31,                 2001       2000       1999       1998       1997

Operating revenues       $  912,312 $  835,662 $  658,336 $  756,410 $  605,183
Income from operations       90,020    169,636    172,458    180,584    180,731
Income from continuing
  operations                 28,295     79,968     83,465     90,743     90,429

At December 31,
Total long-term debt*    $  802,201    808,977    821,558    815,937    746,142
Total assets**            2,859,704  2,617,092  2,559,374  2,421,790  2,451,816


Utility Customer Data:
General business
  customers                 401,739    393,831    384,421    373,730    363,085
Average kWh per customer     30,846     37,068     36,379     36,368     37,080
Average rate per kWh (in
  cents)                       5.25       3.87       3.75       3.85       3.63

*Excludes amount due within one year.
** 1997-1999 include assets of discontinued operations.

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



MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS


INTRODUCTION
In Management's Discussion and Analysis we explain the general
financial condition and results of operations of Idaho Power Company
(IPC).  IPC is an electric utility with a service territory covering
over 20,000 square miles, primarily in southern Idaho and eastern
Oregon.  IPC is the parent of Idaho Energy Resources Co., a joint
venturer in Bridger Coal Company, which supplies coal to IPC's Jim
Bridger generating plant.

Over the last several years, IPC has transferred to its parent,
IDACORP, Inc. (IDACORP), ownership of several of its subsidiaries.
Effective January 2000, ownership of IDACORP Financial Services
(IFS) and Applied Power Company were transferred to IDACORP.  In
June 2001, IPC transferred its non-utility wholesale electricity
marketing operations to IDACORP Energy (IE), a subsidiary 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, 2001, 2000
and 1999.  Results of the non-utility wholesale electricity
marketing operations are presented as discontinued operations on our
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 IPC in this Annual Report,
any 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);
     the current energy situation in the western United States;
     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;
     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 IPC.

Any forward-looking statement speaks only as of the date on which
such statement is made.  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
In this section we discuss our earnings and the factors that
affected them, beginning with a general overview:

			      2001          2000         1999
				  (thousands of dollars)
Income from continuing
   operations                $ 28,295    $ 79,968     $ 83,465
Discontinued energy
   marketing operations        49,943      57,520       14,063
 Net income                  $ 78,238     137,488       97,528

High wholesale energy prices and a severe drought had a negative
effect on income from continuing operations from 2000 to 2001. Of
the $51 million decrease from 2000, $26 million is attributable to
increases in power supply expenses absorbed by IPC and $7 million is
due to the write-off of amounts disallowed in IPC's 2001 power cost
adjustment.  Additional increases in operating expenses for
maintenance, depreciation, interest and customer expenses decreased
earnings by approximately $13 million.

The decrease in income from continuing operations from 1999 to 2000
is predominantly the result of increased net power supply costs of
$69 million, due to declining hydroelectric generating conditions
and increased market prices for purchased power.  These costs were
partially offset by a $49 million increase in increased general
business revenue resulting from rate increases, customer growth, and
weather conditions.  In 2000 we recorded a $7 million pension credit
and in 1999 we recorded a $9 million reduction to income for shared
revenue (see "Regulatory Issues - Regulatory Settlement").

UTILITY OPERATIONS
IPC's utility operations are subject to regulation by, among others,
the state public utility commissions of Idaho, Oregon and Nevada and
by the FERC.  Before we discuss the changes in income from our
utility operations, we'll describe these operations and the
significant factors that influenced them in 2001 and 2000.

The main catalysts for the changes that occurred in our utility
operations were high wholesale energy prices and the drought in the
Northwest.  In late 2000 and early 2001, prices for electricity in
the wholesale markets became highly volatile, reaching unprecedented
levels.

Faced with soaring demand, exorbitant prices and very little water
to produce power, we set in motion a number of measures to decrease
our reliance on the wholesale power markets, by decreasing demand
and increasing our generating capabilities.  Some of these measures
were:

     The IPUC approved a two-year agreement through which we
     compensate our largest industrial customer, Astaris, for
     reducing its load by 50 MW.
     The IPUC and OPUC approved programs that compensated irrigation
     customers capable of reducing usage by at least 100 MWh.
     As part of the May 2001 Power Cost Adjustment (PCA), the IPUC
     required IPC to implement a tiered rate structure for Idaho
     residential customers.  This rate structure increases rates as
     a customer's usage increases.
     In September 2001, we placed in service Danskin Power Plant, a
     90-MW natural gas-fired combustion turbine plant, located near
     Mountain Home, Idaho.
     Mobile generators with total generating capacity of 40 MW were
     sited at various locations in Boise during portions of the
     year.

In May 2001, we made the largest filing in the nine years that our
PCA mechanism has been in effect, seeking recovery of $227 million,
96 percent of which we are now recovering.

IPC owns and operates 17 hydroelectric power plants, one natural gas-
fired plant and shares ownership in three coal-fired generating
plants.  The following table presents IPC's system generation for
the last three years:

					      Percent of total
			MWhs (in thousands)     generation
		     2001     2000     1999     2001  2000   1999

Hydroelectric        5,638   8,500   10,652      43%    52%    59%
Thermal              7,622   7,701    7,266      57     48     41
 Total system
   generation       13,260  16,201   17,918     100%   100%   100%


As the table shows, we rely on low-cost hydroelectric plants for a
significant portion of our generation.  Over the last ten years,
hydro generation has averaged 8.7 million MWh, 57 percent of our
total generation.

The amounts of electricity we are able to generate from these hydro
plants depend on a number of factors, primarily snowpack in the
mountains above our hydro facilities, reservoir storage, and
streamflow requirements.  When these factors are favorable, we can
generate more electricity using our hydroelectric plants.  When
these factors are unfavorable, we must increase our reliance on more
expensive thermal plants and purchased power.

As of this writing, Snake River Basin snowpack numbers offer the
promise of improved streamflows.  Our mid-February 2002
accumulations were 84 percent of normal, compared to 51 percent at
the same time a year earlier.  Even though snowpack is closer to
normal, reservoir storage is not, meaning hydro conditions will not
fully return to normal in 2002.

Regulatory authorities determine the rates we charge to our general
business customers.  Approximately 95 percent of our general
business revenue and sales come from customers in the state of
Idaho.  The rates we charge these customers are adjusted annually by
a PCA mechanism.  The PCA adjusts rates to reflect the changes in
costs incurred by IPC to supply power.  Throughout the year, we
compare our actual power supply costs to the amounts we are
recovering in rates.  Most, but not all, of this difference is
deferred and included in the calculation of rates for future years.

The primary influences on electricity sales volumes are weather and
economic conditions.  Generally, extreme temperatures increase sales
to customers, who use electricity for cooling and heating, and
moderate temperatures decrease sales.  Precipitation levels during
the growing season affect sales to customers who use electricity to
operate irrigation pumps.  Increased precipitation reduces
electricity usage by these customers.  In addition, in 2001 we put
in place several demand management programs designed to reduce
energy consumption by our customers.  Finally, the significant rate
increases implemented in this year's PCA have reduced demand.

General business customer growth continued, with 2.5 percent and 2.4
percent annual increases over the last two years in our Idaho-Oregon
service territory.

The following table summarizes our income from operations.  Each
line is analyzed in more detail below.

					   2000-2001              1999-2000
					    Increase              Increase
		       2001      2000      (Decrease)   1999     (Decrease)
				 (thousands of dollars)
Revenues:
 General           $ 650,608   $565,357   $ 85,251    $516,148    $ 49,209
   business
 Off-system          219,966    229,986    (10,020)    119,785     110,201
 Other                41,738     40,319      1,419      22,403      17,916
  Total revenues     912,312    835,662     76,650     658,336     177,326
Expenses:
 Purchased power     584,209    398,649    185,560     106,344     292,305
 Fuel                 98,318     94,215      4,103      86,617       7,598
 PCA                (175,925)  (120,688)   (55,237)       (502)   (120,186)
 Other operating     315,690    293,850     21,840     293,419         431
   expenses
  Total expenses     822,292    666,026    156,266     485,878     180,148
Income from        $  90,020   $169,636   $(79,616)   $172,458    $ (2,822)
  operations



General Business Revenue
The following table presents IPC's general business revenues and
volumes for the last three years:

			 Revenues                   Volumes
		  (thousands of dollars)        (in thousands of MWh)
		  2001      2000       1999      2001    2000     1999
Residential    $260,251   $225,336   $213,547   4,307   4,393    4,200
Commercial      164,019    132,023    123,069   3,380   3,404    3,194
Industrial      154,318    133,171    117,366   3,925   4,808    4,666
Irrigation       72,020     74,827    62,166    1,419   1,993    1,706
 Total         $650,608   $565,357   $516,148  13,031  14,598   13,766


As mentioned above, our general business revenue is dependent on
many factors, including the number of customers we serve, the rates
we charge, and weather conditions.

2001 vs. 2000:  In 2001, the following factors influenced the 15.0
percent increase in general business revenue:
     Increased average rates, resulting from the PCA, increased
     revenue $137 million. We discuss the PCA in more detail below
     in "Regulatory Issues - Power Cost Adjustment";
     A 2.5 percent increase in general business customers increased
     revenue $16 million;
     Conservation programs, including irrigation and large customer
     buybacks, and other usage factors, decreased energy
     consumption, reducing revenues $67 million.

2000 vs. 1999:  The 9.5 percent increase in general business
revenues is due to the following factors:
     Increased average rates, resulting from the PCA and special-
     contract customers, increased revenues $17 million;
     Increased usage per customer, resulting from weather conditions
     and other factors, increased revenues $26 million.  Decreased
     precipitation during the growing season increased sales to
     irrigation customers, and hotter summer and colder winter
     temperatures increased sales to the other customer classes;
     Our average number of customers increased 2.4 percent over
     1999, increasing revenue $6 million.

Off-system sales
Off-system sales consist primarily of long-term sales contracts and
opportunity sales of surplus system energy.

   $ (in thousands)          MWh (in thousands)     Revenue per MWh
  2001     2000     1999     2001   2000   1999    2001    2000    1999
$219,966 $229,986 $119,785  2,387  4,529  5,924  $92.14  $50.78  $20.22

2001 vs. 2000:  Off-system sales decreased due principally to a 47
percent decrease in volume sold, a result of poor hydro generating
conditions.  The volume decrease was partially offset by an 81
percent increase in price per MWh.

2000 vs. 1999:  Off-system sales increased due predominantly to
significant increases in prices for surplus system energy, which
increased our average revenue per MWh by over 150 percent.  A 24
percent decrease in volumes of electricity sold, due to decreased
availability, partially offset the increase in market prices.

Power Supply
The power supply components of operating income include off-system
sales (described and analyzed above) and purchased power, fuel and
PCA expenses (analyzed below).

The impact of the changes in net power supply costs was an increase
in net power supply expense of $144 million in 2001 and $70 million
in 2000.

Purchased power

   $ (in thousands)          MWh (in thousands)        Cost per MWh
  2001      2000    1999     2001   2000   1999    2001   2000    1999
$584,209 $398,649 $106,344  3,445  4,311  3,127  $169.58 $92.47  $34.01


2001 vs. 2000:  Purchased power expenses increased $185 million in
2001.  Contributing to these results are a number of factors,
including wholesale market conditions, and $132 million of
irrigation and Astaris load reduction program costs.

2000 vs. 1999:  Purchased power expenses increased $293 million in
2000 due to major increases in prices in the energy markets, and to
increased volumes purchased.  The increase in volumes was
necessitated by decreased generation at our hydroelectric plants and
increased customer demand.

Fuel expense

				Thermal MWh generated
       $ (in thousands)            (in thousands)
     2001     2000     1999    2001     2000     1999
  $98,318  $94,215  $86,617   7,622    7,701    7,266



2001 vs. 2000:  Expenses increased in 2001, despite decreased
generation.  Average coal prices increased, and our new 90-MWH gas-
fired plant went on-line in September 2001.

2000 vs. 1999:  Fuel expenses increased by $7 million in 2000, due
primarily to increased generation at our coal-fired plants,
necessitated by decreased generation at our hydroelectric plants and
increased customer demand.

Power Cost Adjustment
The PCA component of expenses is related to IPC's PCA regulatory
mechanism.  The PCA mechanism increases expenses when power supply
costs are below forecast, and decreases expenses when power supply
costs are above forecast. We discuss the PCA in more detail in
"Regulatory Issues - Power Cost Adjustment."

2001 vs. 2000:  The PCA credit increased $55 million in 2001, due to
2001's power supply costs being greater than forecast, a result of
higher prices and greater volumes of purchased power and the costs
related to the load reduction programs that we introduced this year.

2000 vs. 1999:  The PCA expense was a credit of $121 million in
2000, due predominantly to the considerable increases in purchased
power costs not anticipated in our 2000-2001 rate year forecast.
In 1999, actual power supply costs were near forecast, causing the
PCA component of expense to be minimal.


Other Utility Operating Expenses
2001 vs. 2000:  Other operations and maintenance expenses increased
$22 million in 2001.  The most significant changes were:

     Depreciation and amortization expenses increased $7 million,
     due primarily to plant additions;
     Costs at thermal plants increased a total of $7 million,
     primarily due to unscheduled maintenance;
     Leased diesel generators to protect against electricity supply
     shortages, totaled $5 million;
     Operating costs related to the implementation of our new
     customer accounting system, and write-offs of uncollectible
     accounts increased $4 million.

2000 vs. 1999:  Other operations and maintenance expenses in 2000
were substantially unchanged from 1999.  The most significant
changes were:

     Pension expenses decreased $7 million due to favorable returns
     on plan assets;
     Distribution line maintenance expenses increased $4 million,
     primarily due to increased tree clearing and pole maintenance;
     Operating costs related to our customer accounting system
     increased $2 million;
     Depreciation expenses increased $2 million, primarily due to
     plant additions.

OTHER INCOME AND EXPENSES

Other Income
2001 vs. 2000:  The $7 million increase in other income results
primarily from a $6 million increase in interest on deferred PCA
balances.

2000 vs. 1999:  The $6 million increase in other income is primarily
the result of the transfer of IFS.  In 1999 IFS recorded $6 million
of amortization expense on affordable housing investments.  IFS was
transferred to IDACORP on January 1, 2000.

Interest Charges
2001 vs. 2000:  Interest charges increased $7 million in 2001,
predominantly the result of higher short-term debt balances to
finance power purchased for IPC's system, partially offset by
significant decreases in borrowing rates.  Our average short-term
debt in 2001 was $145 million, compared to $21 million in 2000.

2000 vs. 1999:  The $5 million decrease in interest charges is
primarily the result of the transfer of IFS.  In 1999 IFS recorded
$6 million of interest expense related to affordable housing
investments.

Income taxes
Fluctuations in income tax expense result primarily from changes in
net income before taxes, and, for 2000, the transfer of IFS.  IFS
recorded $9 million in affordable housing credits in 1999.


LIQUIDITY AND CAPITAL RESOURCES
Cash Flow
Operating cash flows and working capital levels declined in 2001,
predominantly due to the growth in our PCA regulatory asset balance,
reflecting increased power supply expenditures that we have not yet
recovered through PCA rate adjustments.  Our net cash generated from
operations totaled $316 million for the three-year period 1999-2001.
After deducting common dividends of $210 million, net cash
generation from operations provided approximately $106 million for
our construction program and other capital requirements.  Internal
cash generation after dividends provided 68 percent of our total
capital requirements in 2000 and 105 percent in 1999.

We forecast that internal cash generation after dividends will
provide approximately 100 percent of total capital requirements in
2002 and 82 percent during the two-year period 2003-2004.  We expect
to continue financing our utility construction program and other
capital requirements with both internally generated funds and, as
discussed below, externally financed capital.  The following table
presents IPC's total contractual cash obligations:

			2002  2003  2004  2005  2006  Thereafter
			      (millions of dollars)
Long-term debt          $27   $80   $50   $60   $ -     $612
Fuel supply contracts    38    33    30    27    19       11


At December 31, 2001, IPC had regulatory authority to incur up to
$500 million of short-term indebtedness.  At December 31, 2001,
IPC's short-term borrowing totaled $282 million, consisting of $100
million of floating rate notes and $182 million of commercial paper,
compared to $60 million of commercial paper at December 31, 2000.
The increase is primarily a result of the unrecovered power supply
expenditures mentioned above.

IPC has a $165 million credit facility that expires April 26, 2002
and a $120 million facility that expires April 18, 2002.  Under
these facilities IPC pays a facility fee on the commitment,
quarterly in arrears, based on IPC's First Mortgage Bond Rating.
IPC's commercial paper may be issued up to the amount supported by
the bank credit facilities.

We are currently in the process of renewing our credit lines, for
$200 million, with closing anticipated in March 2002.

Credit Ratings
All of the Company's publicly traded debt have received investment
grade ratings from each of the three major credit rating agencies.
The changes in the energy industry and the recent bankruptcy of
Enron Corp. have caused the rating agencies to refocus their
attention on the credit characteristics and credit protection
measures of industry participants and in some cases the rating
agencies appear to have tightened the standards for a given rating
level.  The Company will continue to evaluate its capital structure,
financing requirements, competitive strategies and future capital
expenditures to try to maintain investment grade ratings.  However,
there is no assurance that these current ratings will continue for
any given period of time or that they will not be revised by the
rating agencies, if, in their respective judgments, circumstances
so warrant.  Any downgrade or revision may adversely affect the
market price of the Company's securities and serve to increase
its cost of capital.

Working Capital
Net working capital (current assets less current liabilities)
decreased approximately $156 million from December 31, 2000 to
December 31, 2001.  The most significant fluctuation was a $222
million increase in notes payable resulting from increased power
supply expenditures that we have not yet recovered through rate
adjustments.  We discuss recovery of these costs in "Regulatory
Issues" later in the MD&A.  In addition, accounts payable decreased
$95 million, due primarily to decreased purchased power payables
resulting from decreased market prices and volumes purchased at
December 31, 2001.

Construction Program
Our consolidated cash construction expenditures totaled $157 million
in 2001, $132 million in 2000, and $108 million in 1999.
Approximately 27 percent of these expenditures were for generation
facilities, 20 percent for transmission facilities, 32 percent for
distribution facilities, and 21 percent for general plant and
equipment.

We estimate that our cash construction and acquisition programs will
require $124 million in 2002 and $267 million in 2003-2004.  These
estimates are subject to revision in light of changing economic,
regulatory, environmental, and conservation factors.

Financing Program
Our consolidated capital structure fluctuated slightly during the
period, with common equity ending at 46 percent, preferred stock 6
percent, and long-term debt 48 percent at December 31, 2001.

At December 31, 2001, IPC also had $100 million of floating rate
notes outstanding, payable on September 1, 2002 included in notes
payable.

In February 2002, IPC notified holders of its $50 million 8 3/4%
First Mortgage Bonds due 2027 of its intent to redeem these bonds on
March 15, 2002.

In March 2000 IPC filed a $200 million shelf registration statement
that could be used for first mortgage bonds (including medium-term
notes), unsecured debt, or preferred stock.  In December 2000, $80
million of Secured Medium-Term Notes were issued by IPC.  Proceeds
from this issuance were used in January 2001 for the early
redemption of $75 million of First Mortgage Bonds originally due in
2021.  In March 2001, IPC issued $120 million of Secured Medium-Term
Notes, with the proceeds used to reduce short-term borrowing
incurred in support of ongoing long-term construction requirements.

In August 2001, IPC filed a $200 million shelf registration that can
be used for first mortgage bonds (including medium-term notes),
unsecured debt, or preferred stock.  At December 31, 2001, no
amounts have been issued.

In August 2001, $25 million of First Mortgage Bonds due in 2031 were
redeemed early.

In April 2000, at our request, the American Falls Reservoir District
issued its American Falls Refunding Replacement Dam Bonds, Series
2000.  Proceeds from issuance of these bonds, in the aggregate
amount of $20 million, were used to refund the same amount of bonds
dated May 1, 1990.  IPC has guaranteed repayment of these bonds.

In May 2000 $4 million of tax-exempt Pollution Control Revenue
Refunding Bonds were issued by Port of Morrow, Oregon.  Proceeds
were used to refund in August 2000 the same amount of Pollution
Control Revenue Bonds, Series 1978.

CURRENT ISSUES
In this section we address a number of other issues that affect or
could affect our operations.

Regulatory Issues

Idaho Jurisdiction
Power Cost Adjustment (PCA):  IPC has a PCA mechanism that provides
for annual adjustments to the rates charged to its Idaho retail
electric customers.  Approved in 1992, the PCA was designed to pass
through approximately 90 percent of the variance from forecasted net
power supply costs.  These adjustments, which take effect annually in
May, are based on forecasts of net power supply expenses and the true-
up of the prior year's forecast.  During the year, the difference
between the actual and forecasted costs is deferred with interest.
The balance of this deferral, called a true-up, is then included in
the calculation of the next year's PCA adjustment.

In the 2001 PCA filing, IPC requested recovery of $227 million of
power supply costs.  In May, the IPUC authorized recovery of $168
million, but deferred recovery of $59 million pending further
review.  The approved amount resulted in an average rate increase of
31.6 percent.  After conducting hearings on the remaining $59
million the IPUC authorized recovery of $48 million plus $1 million
of accrued interest, beginning in October 2001.  The remaining $11
million not recovered in rates from the PCA filing was written off
in September 2001.

Of the $227 million requested by IPC, $185 million related to the
true-up of power supply costs incurred in the 2000-2001 PCA year and
$42 million was for recovery of excess power supply costs forecasted
in the 2001-2002 PCA year.  The forecast amount, however,
underestimated expected power supply costs due to reservoir water
levels coming in below forecast, necessitating the use of higher
cost alternatives to hydro generation.  Also market prices for
purchased power were higher than forecast earlier in the PCA year.

As part of the May 2001 PCA, the IPUC required us to implement a
three-tiered rate structure for Idaho residential customers.  The
IPUC determined that the approved rates for residential customers
should increase as customer's electricity consumption increases.
The residential rate increases are 14.4 percent for the first 800
kWh of usage, 28.8 percent for the next 1,200 kWh, and 62 percent
for the usage over 2,000 kWh.

On October 18, 2001 IPC filed an application with the IPUC for an
order approving the costs to be included in the 2002-2003 PCA for
the Irrigation Load Reduction Program and the Astaris Load Reduction
Agreement.  These two programs were implemented in 2001 to reduce
demand and were approved by the IPUC and the OPUC.  The costs
incurred in 2001 for these two programs were $70 million for the
Irrigation Load Reduction Program and $62 million for the Astaris
Load Reduction Agreement.

On August 31, 2001 IPC filed a request with the IPUC to implement a
rate credit to qualifying residential and small farm customers.  The
credit is the result of a settlement agreement between IPC and the
Bonneville Power Administration (BPA), which will pass on the
benefits of the Federal Columbia River Power System.  IPC estimates
the credit could be as much as $3.60 per month for residential
customers who use 1,200 kWh per month and $300 per month for farm
customers that use 100,000 kWh.  The IPUC, by Order No. 28868,
approved the credit to be passed to the qualified customers
effective October 1, 2001.

In its May 2001 rate authorization the IPUC also directed IPC to
reinstate a comprehensive conservation program given the current
volatility of market prices and the opportunity to incorporate long-
term conservation.  In response to that directive, IPC filed a
report of present energy efficiency activities, a list of
conservation measures, an examination of funding options and a
detailed program structure that could
be implemented should the Commission determine that additional
conservation programs, including the funding of these programs, is
in the public interest.  The Commission has delayed further
deliberations until the spring of 2002.

So far in the 2001-2002 rate year actual power supply costs included
in the PCA have been significantly greater than forecast due to
purchased power volumes and prices being greater than originally
forecasted and the implementation of the voluntary load reduction
programs with Astaris and the irrigation customers.  To account for
these higher-than-forecasted costs and the unamortized portion of
the 2000-2001 PCA balance, IPC has recorded a regulatory asset of
$290 million as of December 31, 2001.

The May 2000 rate adjustment increased Idaho general business
customer rates by 9.5 percent, and resulted from forecasted below-
average hydroelectric generating conditions.  Overall, the PCA
adjustment increased general business revenue by approximately $38
million during the 2000-2001 rate period, partially offsetting the
forecasted increase in power supply costs.

The May 1999 rate adjustment reduced rates by 9.2 percent.  The
decrease was the result of both forecasted above-average
hydroelectric generating conditions for the 1999-2000 rate period
and a true-up from the 1998-1999 rate period.  Overall, the May 1999
rate adjustment decreased annual general business revenue by
approximately $40 million during the 1999-2000 rate period.

Regulatory Settlement:  IPC had a settlement agreement with IPUC
that expired at the end of 1999.  Under the terms of the settlement,
when earnings in IPC's Idaho jurisdiction exceeded an 11.75 percent
return on the year-end common equity, IPC set aside 50 percent of
the excess for the benefit of the Idaho retail customers.

In March 2000 IPC submitted its 1999 annual earnings sharing
compliance filing to the IPUC.  This filing indicated that there was
almost $10 million in 1999 earnings and $3 million in unused 1998
reserve balances available for the benefit of our Idaho customers.

In April 2000 the IPUC issued Order 28333, which ordered that $7
million of the revenue sharing balance be refunded to Idaho customers
through rate reductions effective May 16, 2000.  The Order also
approved IPC's continued participation in the Northwest Energy
Efficiency Alliance for the years 2000-2004, ordering IPC to set aside
the remaining $6 million of revenue sharing dollars to fund that
participation.

Demand-Side Management (Conservation) Expenses (DSM):  IPC requested
that the IPUC allow for the recovery of post-1993 DSM expenses and
acceleration of the recovery of DSM expenditures authorized in the
last general rate case.  In its Order No. 27660 issued on July 31,
1998, the IPUC set a new amortization period of 12 years instead of
the 24-year period previously adopted.  On April 17, 2000, the Idaho
Supreme Court affirmed the IPUC order, after hearing an appeal by a
group of industrial customers.

On February 23, 2001 the IPUC approved IPC's Green Energy Purchase
Program.  The Green Program is an optional program available to all
IPC customers in Idaho, allowing them to pay a premium to purchase
energy generated by alternative sources such as solar and wind.
Creating the Green Program will provide additional means for
customers to stimulate demand for new green resources and their
development.

Oregon Jurisdiction
IPC filed an application with the OPUC to begin recovering
extraordinary 2001 power supply costs in its Oregon jurisdiction.
On June 18, 2001, the OPUC approved new rates that would recover $1
million over the next year.  Under the provisions of the deferred
accounting statute, annual rate recovery amounts were limited to
three percent of IPC's 2000 gross revenues in Oregon.  During the
2001 session, the Oregon Legislature amended the statute giving the
OPUC authority to increase the maximum annual rate of recovery of
deferred amounts to six percent for electric utilities.  IPC
subsequently filed on October 5, 2001 to recover an additional three
percent extraordinary deferred power supply costs.  As a result of
this filing, the OPUC issued Order No. 01-994 allowing IPC to
increase its rate of recovery to six percent effective November 28,
2001.  The Oregon deferral balance is $15 million as of December 31,
2001, net of the June 18, 2001 and November 28, 2001 recovery.

IPC filed with the OPUC a request to implement the same BPA program
as in Idaho.  The OPUC held a public meeting on October 22, 2001 and
subsequently approved IPC's request to implement the BPA Residential
and Small Farm Energy Credit for the benefits derived during the
period October 1, 2001 through September 30, 2006.

In 1998, IPC received authority from the OPUC to reduce the
amortization period for the regulatory assets associated with DSM
programs from 24 years to 5 years.  The OPUC also approved
additional Oregon allocated DSM expenditures for recovery through
rates.  The Oregon costs will be recovered by extending an existing
surcharge until the amounts are collected.

Nevada Jurisdiction
The IPUC and PUCN approved IPC's sale of its Nevada service
territory to Raft River Electric Co-Op (Raft River).  This sale
transferred the distribution facilities and rights-of-way that serve
about 1,250 customers in northern Nevada and about 90 customers in
southern Idaho.  The FERC approved a power supply agreement between
IPC and Raft River.  This sale will allow IDACORP to participate in
a deregulated electric utility market in Nevada should that state
resume deregulation activities.

New Idaho Legislation
Idaho Senate Bill No. 1255, chapter 15, title 61, Idaho Code (the
Act), was signed into law on April 10, 2001.  It authorizes the IPUC
to allow public utilities or their assignees to issue energy cost
recovery bonds to finance, among other things, significant increases
in the cost of electricity resulting from shortfalls in available
hydroelectric power for which higher-cost replacement power must be
substituted.  The legislative intent of the Act is to provide
utilities with a mechanism for recovery of these increased costs
while leveling the rate impact of such increases on the utilities'
customers.  Energy cost recovery bonds must have an expected
maturity date no later than five years after issuance and a legal
maturity date no later than seven years after issuance.

Under the Act, the IPUC may issue an energy cost financing order in
favor of the utility, pursuant to which a charge, known as an energy
cost bond charge, would be included on the bills of the utility's
Idaho customers.  The Act requires the energy cost bond charge to
remain in effect until the energy cost recovery bonds are paid in
full.  In addition, the charge is subject to periodic adjustment to
ensure the timely payment of principal and interest on the energy
cost recovery bonds and the recovery of certain related expenses.

An energy cost financing order creates energy cost property, which
includes the right to receive revenues arising from the energy cost
bond charge.  Energy cost property may be sold or otherwise
transferred to, among others, the assignee of the public utility
that issues energy cost recovery bonds, and it may be pledged as
security for such bonds.

The Act requires that, before it issues an energy cost financing
order, the IPUC must find that the public interest would be better
served if increased costs reflected in a fuel or power cost
adjustment and related expenses were recovered through the issuance
of energy cost recovery bonds than if these amounts were recovered
over a one-year period assuming a conventional financing.

Before seeking to recover costs through the issuance of energy
bonds, IPC must file with the IPUC a proposal to establish a
threshold energy cost amount, or trigger.  In June 2001, the IPUC
approved IPC's application, establishing a one cent per kWh trigger
amount.

Electric Industry Restructuring
In 1997, the Idaho Legislature appointed a committee to study
restructuring of the electric utility industry.  Although the
committee will continue studying a variety of restructuring ideas,
it has not recommended any restructuring legislation and is not
expected to in the foreseeable future.

In 1999, the Oregon legislature passed legislation restructuring the
electric utility industry, but exempted IPC's service territory.

Integrated Resource Plan (IRP)
Every two years, IPC is required to file with the IPUC and OPUC an
IRP, a comprehensive look at IPC's present and future demands for
electricity and plan for meeting that demand.  The 2000 IRP
identified a potential electricity shortfall within our utility
service territory by mid-2004.  The plan projected a 250-MW resource
need in 2004 to satisfy energy demand during IPC's peak periods.
The IRP calls for IPC to use purchases from the Northwest energy
markets to meet short-term energy needs.  The 2000 IRP anticipates
that after 2004, transmission constraints will not allow IPC to
continue to cover increasing demand using wholesale purchases from
the Pacific Northwest.

As a result of the 2000 IRP, IPC issued a request for proposals
(RFP), seeking bids for 250 MW of additional generation to support
the growing demand in IPC's utility service territory.  A proposal
by Garnet Energy LLC, a subsidiary of Ida-West, was selected by IPC.
In December 2001 IPC signed an agreement with Garnet to define the
conditions under which the utility will purchase energy to be
produced by Garnet's 273-MW natural gas-fired combined cycle
combustion turbine facility in Canyon County, Idaho, located in the
southwest part of the state.  In December 2001, IPC filed an
application with the IPUC requesting authorization to include Garnet
related expenses in IPC's PCA.

Regional Transmission Organizations
IPC has a long history of providing wholesale transmission services.
IPC provides various firm and non-firm wheeling services for several
surrounding utilities.  In December 1999 the FERC, in its landmark
Order 2000, said that all companies with transmission assets must
file to form regional transmission organizations (RTOs) or explain
why they cannot. Order 2000 is a follow up to orders 888 and 889
issued in 1996, which required transmission owners to provide non-
discriminatory transmission service to third parties. By encouraging
the formation of RTOs, FERC seeks to further facilitate the
formation of efficient, competitive wholesale electricity markets.

In response to FERC Order 2000, IPC and other regional transmission
owners filed in October 2000 a plan to form RTO West, an entity that
will operate the transmission grid in seven western states.  RTO
West will have its own independent governing board. The
participating transmission owners will retain ownership of the
lines, but will not have a role in operating the grid.

The previous FERC filing represents a portion of the filing
necessary to form RTO West.  However, substantial additional filings
will be necessary to include the tariff and integration agreements
associated with the new entity.  There will also need to be filings
for state approvals.  We expect the "Stage 2" FERC filings to be
completed by March 2002.  State filings may be initiated in 2002.

Relicensing of Hydroelectric Projects
IPC, like other utilities that operate nonfederal hydroelectric
projects, has obtained licenses for its hydroelectric projects from
the FERC. These licenses generally last for 30 to 50 years depending
on the size of the project. By 2010, the licenses for eight of our
hydro projects will have expired.  We are actively pursuing the
relicensing of these 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 filed applications
seeking renewal of licenses for our Bliss, Upper Salmon Falls, Lower
Salmon Falls, CJ Strike, and Shoshone Falls Hydroelectric Projects.
The licenses for the Upper and Lower Malad Project expires in 2004,
the Hells Canyon Complex (Brownlee, Oxbow and Hells Canyon dams) in
2005, and the Swan Falls Project in 2010. We are currently engaged
in procedures necessary to file timely license applications for each
of these projects. Although various federal and state requirements
and issues must be resolved through the license renewal process, we
anticipate that we will relicense each of the 10 facilities. At this
point, however, we cannot predict what type of environmental or
operational requirements we may face, nor can we estimate the cost
of license renewal. At December 31, 2001, $39 million of relicensing
costs were included in Construction Work in Progress.

Market Risk
The following discussion summarizes the financial instruments,
derivative instruments and derivative commodity instruments
sensitive to changes in interest rates and commodity prices that we
held at December 31, 2001.

We buy and sell electricity as part of our ongoing utility
operations.  These operations are subject to commodity price risk.
We are exposed to this risk to the extent that a portion of the
electric energy we are required to sell to our customers at fixed
rates may be purchased at wholesale electric market prices, which
can be higher than the fixed sales rate we receive.  Our exposure to
this risk is largely offset by the PCA mechanism in place in Idaho,
which we discussed previously.  The objective of our market price
risk management program is to mitigate the risk associated with the
purchase and sale of electricity, while balancing this risk against
system reliability and cost considerations.

Our Risk Management Committee (RMC), comprised of IPC officers,
oversees the risk management program.  On a regular basis, our RMC
reviews multiple system resource and load projections and evaluates
the potential impacts of changes in three key variables, wholesale
prices, system loads and system resources.  The RMC controls the
risk by assessing the impact of changes in the variables on PCA
deferral balances and projected volumetric surplus and deficit data,
and by reviewing forward price curves for electricity. The RMC then
takes an appropriate risk mitigating action.

We have no foreign exchange exposure, and, except for the
transferred energy-marketing operations, have not transacted in
interest rate futures and swaps.

With the June 2001 transfer of our non-utility energy marketing
operations to IE, IPC no longer holds for trading purposes any
derivative or derivative commodity instruments.

     Interest Rate Risk
The majority of our debt is held in fixed rate securities with
embedded call options.  We owe $72 million in variable-rate tax-
exempt debt, and 25 percent of our total debt is variable in the
form of commercial paper or short-term notes.  By nature, the value
of our variable-rate debt is not sensitive to changes in interest
rates, and the value of our commercial paper borrowings does not
give rise to significant interest rate risk because these borrowings
generally have maturities of less than three months.  The following
table presents the principal cash flows by maturity date and the
related average interest rate for our fixed-rate debt at December
31, 2001.  The table also presents the fair value of these fixed
rate instruments, based on market rates for similar instruments as
of that date.

					     Average
       Expected                              interest
       Maturity Date   Amount due             rate
		      (millions of dollars)
       2002              $  27                 6.8%
       2003                 80                 6.4%
       2004                 50                 8.0%
       2005                 60                 5.8%
       2006                  -                   -
       Thereafter          540                 7.3%
	Total            $ 757                 7.1%
       Fair Value        $ 795



Environmental

Salmon Recovery Plan
We are continuing to monitor regional efforts to develop a
comprehensive and scientifically credible plan to ensure the long-
term survival of anadromous fish runs on the Columbia and lower
Snake Rivers.

In November of 1991, the National Marine Fisheries Service (NMFS)
listed the Snake River Sockeye Salmon as endangered under the
Endangered Species Act (ESA).  Subsequently, in April 1992, NMFS
listed the Snake River Fall Chinook and the Snake River
Spring/Summer Chinook as threatened under the ESA.  Only the Snake
River Fall Chinook inhabit the Snake River in the vicinity of our
three-dam Hells Canyon Complex (HCC).  These listings have not had
any major effects on our operations.  In 1991, IPC voluntarily
initiated a Fall Chinook Interim Recovery Plan and Study intended to
address concerns relative to Fall Chinook spawning immediately below
Hells Canyon Dam.  Since the inception of that plan, IPC has been
managing releases from the HCC during the Fall Chinook spawning
season to provide stable conditions for spawning Fall Chinook below
Hells Canyon Dam.  These conditions are maintained through fry
emergence in the spring.  In connection with the relicensing of the
HCC, IPC is engaged in ongoing discussions with the FERC and NMFS
relative to ESA issues associated with the HCC.

In December 2000, NMFS issued a final Biological Opinion (BiOp) on
the operation of the Federal Columbia River Power System (FCRPS).
This BiOp resulted from ESA Section 7 consultation on the operations
of the federal projects operated by the U.S. Army Corps of Engineers
and U.S. Bureau of Reclamation on the lower Snake and Columbia
Rivers.  It did not relate to the operations of our HCC and did not
call for any changes in the operations of the HCC.

In May of 2001, NMFS issued a final BiOp on the operations of the
U.S. Bureau of Reclamation (BOR) projects in the Snake River basin
above the HCC.  This BiOp was interim in nature, expiring in March
2002.  NMFS and the BOR are currently negotiating an extension of
this BiOp for subsequent years operations.

Portions of the 2000 FCRPS BiOp and the 2001 BOR BiOp provide for
the acquisition of water from Idaho by the BOR in order to provide
augmentation flows to assist with the downstream migration of ESA
listed anadromous fish through the lower Snake River FCRPS projects.
For the past several years, the BOR has been leasing water from
willing lessors in Idaho in an effort to provide the augmentation
flows.  In connection with these flow augmentation efforts, IPC has
been cooperating with the federal agencies by moving and shaping
water acquired by the BOR through the HCC.  In the past, IPC has
been reimbursed for any energy losses incurred as a result of this
cooperation through an agreement with the BPA.  While this agreement
expired in April of 2001, IPC has advised federal interests of its
willingness to continue to assist with the movement and shaping of
federal flow augmentation water provided any adverse impact to its
customers is satisfactorily addressed.

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 listing as an issue
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.

During relicensing, the FERC is required by the Endangered Species
Act (Section 7) to consult with the USFWS.  This consultation has
been requested by the FERC.

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.  IPC has sufficient  SO2  allowances to provide
compliance for all three coal-fired facilities and the Danskin
natural gas-fired facility.  Therefore, we foresee no adverse
effects on our operations with regard to SO2 emissions.

New Accounting Pronouncements
In July 2001 the Financial Accounting Standards Board (FASB) issued
Statement of Financial Accounting Standards (SFAS) 141, "Business
Combinations," which addresses accounting and reporting for business
combinations.  SFAS 141 requires that all business combinations
initiated after June 30, 2001 be accounted for using one method, the
purchase method.  The adoption of SFAS 141 did not have a
significant effect on our financial statements.

Also in July 2001 the FASB issued SFAS 142, "Goodwill and Other
Intangible Assets," which is effective January 1, 2002.  SFAS 142
changes the accounting for goodwill from an amortization method to
an impairment-only method.  Thus, amortization of goodwill,
including goodwill recorded in past transactions, will cease.  IPC
will be required to complete transitional goodwill impairment tests
within six months of the date of adoption, and at least annually
thereafter.  The standard also includes provisions for the
reclassification of certain existing recognized intangibles to
goodwill, reassessment of the useful lives of existing recognized
intangibles and reclassification of certain intangibles out of
goodwill.  The adoption of SFAS 142 did not have a significant
effect on our financial statements.

In August 2001 the FASB issued SFAS 143, "Accounting for Asset
Retirement Obligations," which is effective for fiscal years
beginning after June 15, 2002.  This Statement addresses financial
accounting and reporting for obligations associated with the
retirement of tangible long-lived assets and the associated asset
retirement costs.  An obligation may result from the acquisition,
construction, development and the normal operation of a long-lived
asset.  IPC is currently assessing but has not yet determined the
impact of SFAS 143 on our financial position and results of
operations.

Also in August 2001 the FASB issued SFAS 144, "Accounting for the
Impairment or Disposal of Long-Lived Assets," which is effective for
fiscal years beginning after December 15, 2001.  SFAS 144 addresses
financial accounting and reporting for the impairment or disposal of
long-lived assets, superseding SFAS 121, "Accounting for the
Impairment of Long-Lived Assets and for Long-Lived Assets to be
Disposed of."  IPC is currently assessing but has not yet determined
the impact of SFAS 144 on its financial position and results of
operations.

Critical Accounting Policies
IPC follows SFAS 71, "Accounting for the Effects of Certain Types of
Regulation," and our financial statements reflect the effects of the
different rate making principles followed by the various
jurisdictions regulating IPC.  The primary result of this policy is
that IPC has deferred $600 million of regulatory assets at December
31, 2001.  Of this amount, $305 million relates to current year
power supply expenditures.  While we expect to fully recover this
amount, such recovery is subject to final review by the regulatory
entities.


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 Risk."


ITEM 8.  FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

     INDEX TO FINANCIAL STATEMENTS AND FINANCIAL STATEMENT
     SCHEDULE



							       PAGE

Management's Responsibility for Financial Statements            31

Consolidated Financial Statements:
Consolidated Statements of Income for the Years Ended
   December 31, 2001, 2000 and 1999                             33
Consolidated Balance Sheets as of December 31, 2001 and
   2000                                                      34-35
Consolidated Statements of Capitalization as of December
   31, 2001 and 2000                                            36
Consolidated Statements of Cash Flows for the Years Ended
   December 31, 2001, 2000 and 1999                             37
Consolidated Statements of Retained Earnings and Consolidated
   Statements of Comprehensive Income for the Years Ended
   December 31, 2001, 2000 and 1999                             38
Notes to Consolidated Financial Statements                      39
Independent Auditors' Report                                    54

Supplemental Financial Information and Financial Statement
  Schedule
Supplemental Financial Information (Unaudited)                  55

Financial Statement Schedule for the Years Ended December 31,
  2001, 2000 and 1999:
Schedule II-Consolidated Valuation and Qualifying Accounts      60




     MANAGEMENT'S RESPONSIBILITY FOR FINANCIAL STATEMENTS
The management of Idaho Power Company is responsible for the
preparation and presentation of the information and
representations contained in the accompanying financial
statements.  The financial statements have been prepared in
conformance with generally accepted accounting principles. 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.

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

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

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



	  J. LaMont Keen           Darrel T. Anderson
	  President and Chief      Vice President, Chief Financial
	  Operating Officer        Officer and Treasurer






Idaho Power Company
Consolidated Statements of Income

				     Year Ended December 31,
				     2001       2000      1999
				      (thousands of dollars)

REVENUES:
  General business             $ 650,608    $ 565,357    $ 516,148
  Off-system sales               219,966      229,986      119,785
  Other revenues                  41,738       40,319       22,403
    Total revenues               912,312      835,662      658,336

EXPENSES:
  Operation:
    Purchased power              584,209      398,649      106,344
    Fuel expense                  98,318       94,215       86,617
    Power cost adjustment       (175,925)    (120,688)        (502)
    Other                        153,079      146,424      151,800
  Maintenance                     55,877       46,973       42,067
  Depreciation                    87,041       80,287       77,833
  Taxes other than income
    taxes                         19,693       20,166       21,719
    Total expenses               822,292      666,026      485,878

INCOME FROM OPERATIONS            90,020      169,636      172,458

OTHER INCOME:
  Allowance for equity
    funds used during
    construction                     752        2,565        1,667
  Other - net                     19,847       11,389        6,369
    Total other income            20,599       13,954        8,036

INTEREST CHARGES:
  Interest on long-term
    debt                          55,704       53,253       54,150
  Other interest                  10,402        4,544        7,864
  Allowance for borrowed
    funds used during
    construction                  (3,737)      (2,346)      (1,392)
    Total interest charges        62,369       55,451       60,622

INCOME BEFORE INCOME TAXES        48,250      128,139      119,872

INCOME TAXES                      19,955       48,171       36,407

INCOME FROM CONTINUING
  OPERATIONS                      28,295       79,968       83,465

DISCONTINUED OPERATIONS:
  Income from operations
    of energy marketing
    transferred to
    parent (net of tax of
    $33,574, $37,397 and
    $9,143)                       49,943      57,520        14,063

NET INCOME                        78,238     137,488        97,528

  Dividends on preferred
      stock                        5,400       5,929         5,572

EARNINGS ON COMMON STOCK       $  72,838    $131,559     $  91,956

  The accompanying notes are an integral part of these statements.




Idaho Power Company
Consolidated Balance Sheets

Assets

					      December 31,
					   2001        2000
				       (thousands of dollars)

ELECTRIC PLANT:
   In service (at original cost)       $2,989,630   $2,799,590
   Accumulated provision for
     depreciation                      (1,220,002)  (1,142,572)
     In service - Net                   1,769,628    1,657,018
   Construction work in progress           86,010      130,477
   Held for future use                      2,232        2,167

      Electric plant - Net              1,857,870    1,789,662

INVESTMENTS AND OTHER PROPERTY             37,432       21,502

CURRENT ASSETS:
   Cash and cash equivalents               43,040       83,494
   Receivables:
     Customer                              58,702       74,225
     Allowance for uncollectible
       accounts                            (1,500)      (1,397)
     Notes                                  3,488        2,945
     Employee notes                         6,274        4,742
     Related parties                       37,517          311
     Other                                  2,280        4,943
   Taxes receivable                         8,244            -
   Accrued unbilled revenues               37,400       44,825
   Materials and supplies (at average
     cost)                                 23,280       24,685
   Fuel stock (at average cost)             8,726        5,105
   Prepayments                             31,897       24,145
   Regulatory assets                       55,107        8,672
   Net assets of discontinued
     operations                                 -       37,702

      Total current assets                314,455      314,397

DEFERRED DEBITS:
   American Falls and Milner water
     rights                                31,585       31,585
   Company-owned life insurance            39,602       39,554
   Regulatory assets                      544,134      370,535
   Other                                   34,626       49,857

      Total deferred debits               649,947      491,531

      TOTAL                            $2,859,704   $2,617,092

  The accompanying notes are an integral part of these statements.


Idaho Power Company
Consolidated Balance Sheets

Capitalization and Liabilities

					    December 31,
					  2001          2000
					(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
    Premium on capital stock              362,602      362,430
    Capital stock expense                  (4,144)      (4,024)
    Retained earnings                     316,856      313,800
    Accumulated other comprehensive
      income (loss)                        (3,719)        (921)

      Total common stock equity           765,626      765,316

  Preferred stock                         104,387      105,066

  Long-term debt                          802,201      808,977

      Total capitalization              1,672,214    1,679,359

CURRENT LIABILITIES:
   Long-term debt due within one year      27,078       30,077
   Notes payable                          282,000       59,700
   Accounts payable                        68,806      164,237
   Notes and accounts payable to
     related parties                        6,931        4,212
   Taxes accrued                                -       12,983
   Derivative liabilities                  40,528            -
   Interest accrued                        13,115       15,002
   Deferred income taxes                   14,578        8,672
   Other                                   16,118       18,460

      Total current liabilities           469,154      313,343

DEFERRED CREDITS:
   Deferred income taxes                  541,482      452,404
   Derivative liabilities - long-term       7,253            -
   Regulatory liabilities                 113,957      110,901
   Other                                   55,644       61,085

      Total deferred credits              718,336      624,390

COMMITMENTS AND CONTINGENT LIABILITIES

      TOTAL                            $2,859,704   $2,617,092

  The accompanying notes are an integral part of these statements.





Idaho Power Company
Consolidated Statements of Capitalization
					 December 31,
					  2001     %          2000     %
				    (thousands of dollars)
COMMON STOCK EQUITY:
  Common stock                         $   94,031         $   94,031
  Premium on capital stock                362,602            362,430
  Capital stock expense                    (4,144)            (4,024)
  Retained earnings                       316,856            313,800
  Accumulated other
    comprehensive income (loss)            (3,719)              (921)
    Total common stock equity             765,626   46       765,316   46

PREFERRED STOCK:
  4% preferred stock                       14,387             15,066
  7.68% Series, serial preferred
    stock                                  15,000             15,000
  7.07% Series, serial preferred
    stock                                  25,000             25,000
  Auction rate preferred stock             50,000             50,000
    Total preferred stock                 104,387    6       105,066    6

LONG-TERM DEBT:
  First mortgage bonds:
    6.93% Series due 2001                       -             30,000
    6.85% Series due 2002                  27,000             27,000
    6.40% Series due 2003                  80,000             80,000
    8   % Series due 2004                  50,000             50,000
    5.83% Series due 2005                  60,000             60,000
    7.38% Series due 2007                  80,000             80,000
    7.20% Series due 2009                  80,000             80,000
    6.60% Series due 2011                 120,000                  -
    Maturing 2021 through
      2031 with rates ranging
      from 7.5% to 9.52%                  130,000            230,000
      Total first mortgage bonds          627,000            637,000
  Amount due within one year              (27,000)           (30,000)
    Net first mortgage bonds              600,000            607,000
  Pollution control revenue
    bonds:
    8.30% Series 1984 due 2014             49,800            49,800
    6.05% Series 1996A due 2026            68,100            68,100
    Variable Rate Series 1996B
      due 2026                             24,200            24,200
    Variable Rate Series 1996C
      due 2026                             24,000            24,000
    Variable Rate Series 2000 due
      2007                                  4,360             4,360
      Total pollution control
	revenue bonds                     170,460           170,460
  REA notes                                 1,263             1,339
    Amount due within one year                (78)              (77)
      Net REA notes                         1,185             1,262
  American Falls bond guarantee            19,885            19,885
  Milner Dam note guarantee                11,700            11,700
  Unamortized premium/discount -
    Net                                    (1,029)           (1,330)

     Total long-term debt                 802,201   48      808,977    48

TOTAL CAPITALIZATION                   $1,672,214  100    $1,679,359  100

  The accompanying notes are an integral part of these statements.


Idaho Power Company
Consolidated Statements of Cash Flows
				      Year Ended December 31,
				     2001      2000       1999
				      (thousands of dollars)

OPERATING ACTIVITIES:
  Net income                          $  78,238  $ 137,488  $  97,528
  Adjustments to reconcile net
    income to net cash provided
    by (used in) operating
    activities:
    Allowance for uncollectible
      accounts                           20,277     21,682          -
    Unrealized (gains) losses          (100,653)    21,847     (3,502)
    Depreciation and amortization        99,565     92,677     95,154
    Deferred taxes and investment
      tax credits                       103,425     44,911     (1,747)
    Accrued PCA costs                  (184,584)  (122,353)      (891)
    Change in:
      Receivables and prepayments       (20,837)  (165,759)      (489)
      Accrued unbilled revenue            7,425    (12,831)     2,616
      Materials and supplies and
	fuel stock                       (2,216)     5,544     (1,050)
      Accounts payable                  (26,142)   156,932     28,397
      Taxes (receivable) accrued        (21,227)    (8,326)    (3,391)
      Other current assets and
	liabilities                      (2,081)    (3,572)     4,710
    Other - net                         (10,788)    (6,843)    (3,490)
  Net cash provided by (used in)
    operating activities                (59,598)   161,397    213,845

INVESTING ACTIVITIES:
  Additions to utility plant           (156,787)  (131,711)  (108,498)
  Investments in affordable
    housing projects                          -          -    (19,554)
  Investments in company - owned
    life insurance                            -          -     (5,862)
  Note receivable payment from
    parent                               42,743          -          -
  Net cash of affiliates
    transferred to parent                     -     (4,737)         -
  Other - net                               149        838     (3,066)

    Net cash used in investing
      activities                       (113,895)  (135,610)  (136,980)

FINANCING ACTIVITIES:
  Proceeds from issuance of:
    First mortgage bonds                120,000     80,000     80,000
    Pollution control revenue
      bonds                                   -      4,360          -
    Long-term debt related to
      affordable housing projects             -          -     18,730
  Retirement of:
    First mortgage bonds               (130,000)   (80,000)         -
    Pollution control revenue
      bonds                                   -     (4,360)         -
    Long-term debt related to
      affordable housing projects             -          -     (9,650)
    Subsidiary debt                           -          -       (165)
  Dividends on common stock             (69,782)   (69,850)   (69,912)
  Dividends on preferred stock           (5,400)    (5,929)    (5,572)
  Increase (decrease) in short-         222,300     39,943    (14,607)
    term borrowings
  Other - net                            (4,079)    (1,495)      (680)
    Net cash provided by (used in)
      financing activities              133,039    (37,331)    (1,856)

Net increase (decrease) in cash and
  cash equivalents                      (40,454)   (11,544)    75,009

Cash and cash equivalents at
  beginning of period                    83,494     95,038     20,029

Cash and cash equivalents at end of
  period                              $  43,040  $  83,494  $  95,038

SUPPLEMENTAL DISCLOSURE OF CASH FLOW
  INFORMATION:
  Cash paid (received) during the
    period for:
    Income taxes                      $ (28,510) $  47,732  $  50,532
    Interest (net of amount
      capitalized)                    $  61,600  $  58,090  $  55,186
  Net non-cash assets of
    affiliates transferred to parent  $       -  $  17,353  $       -
  Net assets transferred to parent
    for notes receivable              $  76,250  $       -  $       -


  The accompanying notes are an integral part of these statements.



Idaho Power Company
Consolidated Statements of Retained Earnings

					 Year Ended December 31,
					2001      2000      1999
					  (thousands of dollars)

RETAINED EARNINGS, BEGINNING OF
  YEAR                                $313,800   $274,181   $252,137

NET INCOME                              78,238    137,488     97,528

   Total                               392,038    411,669    349,665

DIVIDENDS:
   Common stock ($1.86 per share)      (69,782)   (69,850)   (69,912)
   Preferred stock                      (5,400)    (5,929)    (5,572)

TRANSFER TO IDACORP, INC.                    -    (22,090)         -

RETAINED EARNINGS, END OF YEAR        $316,856   $313,800   $274,181

  The accompanying notes are an integral part of these statements.



Consolidated Statements of Comprehensive Income

				     Year Ended December 31,
				    2001      2000      1999
				     (thousands of dollars)

NET INCOME                            $ 78,238   $137,488   $ 97,528

OTHER COMPREHENSIVE INCOME (LOSS):
  Unrealized gains on securities
    (net of tax of ($1,044),
    ($1,713) and  $677)                 (1,770)    (2,335)     1,017
  Minimum pension liability
    adjustment (net of tax of ($649),
    ($78) and $189)                     (1,028)      (119)       291

TOTAL COMPREHENSIVE INCOME            $ 75,440   $135,034   $ 98,836

  The accompanying notes are an integral part of these statements.





NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

1.  SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES:
Nature of Business
Idaho Power Company (IPC) is an electric utility regulated by the
Federal Energy Regulatory Commission (FERC) and the state regulatory
commissions of Idaho, Oregon, Nevada and Wyoming, and is engaged in
the generation, transmission, distribution, sale and purchase of
electric energy.  IPC is the parent of Idaho Energy Resources Co., a
joint venturer in Bridger Coal Company, which supplies coal to IPC's
Jim Bridger generating plant.

The outstanding shares of IPC's common stock were exchanged on a
share-for-share basis into common stock of IDACORP, Inc. (IDACORP)
on October 1, 1998 and are no longer actively traded.  IPC's
preferred stock and debt securities were unaffected and remain
outstanding with IPC.

Effective June 11, 2001 IPC transferred its wholesale electricity
marketing operations (Energy Marketing) to IDACORP Energy (IE), see
Note 11 "Discontinued Operations."  After the transfer of Energy
Marketing, all of IPC consists of one operating segment, Utility
Operations.  The Utility Operations segment has two primary sources
of income, the regulated operation of IPC and income from its joint
venture in Bridger Coal Company.

Principles of Consolidation
The consolidated financial statements include the accounts of IPC
and its wholly-owned subsidiary.  All significant intercompany
transactions and balances have been eliminated in consolidation.
Investments in business entities in which IPC and its subsidiary 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.

Property, Plant and Equipment
The cost of additions to utility 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 expensed to
operations.  IPC records repair and maintenance costs associated
with planned major maintenance as these costs are incurred.  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
property, plant and equipment.

Allowance for Funds Used During Construction (AFDC)
AFDC, a non-cash item, represents the composite interest costs of
debt, and a return on equity funds, used to finance utility
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 2001, 2000 and 1999 were 5.4 percent,
8.3 percent, and 7.8 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.

Derivative Financial Instruments
Prior to the June 11 transfer of Energy Marketing to IE (Note 11),
IPC used financial instruments such as commodity futures, forwards,
options and swaps to manage exposure to commodity price risk in the
electricity markets.  The objective of IPC's risk management program
was to mitigate the risk associated with the purchase and sale of
electricity as well as to optimize its energy marketing portfolio.
The accounting for derivative financial instruments used to manage
risk were in accordance with the concepts established in EITF 98-10,
"Accounting for Contracts Involved in Energy Trading Activities,"
and SFAS 133, "Accounting for Derivative Instruments and Hedging
Activities" as amended by SFAS 138 "Accounting for Certain
Derivative Instruments and Certain Hedging Activities."

Power Cost Adjustment  (PCA)
IPC has a PCA mechanism that provides for annual adjustments to the
rates charged to its Idaho retail electric customers.  These
adjustments, which take effect annually in May, are based on
forecasts of net power supply expenses and the true-up of the prior
year's forecast.  During the year, the difference between the actual
and forecasted costs is deferred with interest.  The balance of this
deferral, called a true-up, is then included in the calculation of
the next year's PCA adjustment.

Depreciation
All utility plant in service is depreciated using the straight-line
method at rates approved by regulatory authorities.  Annual
depreciation provisions as a percent of average depreciable utility
plant in service approximated 2.98 percent in 2001 and 2.94 percent
in 2000 and 1999.

Income Taxes
IPC 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 Idaho Public Utility Commission (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 computed using book lives 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).

IPC's operations are included in IDACORP's consolidated federal and
state income tax returns.  The income tax expense and deferred
income taxes payable included in the accompanying consolidated
financial statements for 2001 and 2000 are determined after
considering all income and expense items and tax credits generated
by the consolidated group.  The tax receivable is classified based
upon the time period in which cash settlement to IDACORP is expected
to occur.

The State of Idaho allows a three-percent investment tax credit
(ITC) upon certain qualifying plant additions.  ITC's 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.

Stock Based Compensation
SFAS 123, "Accounting for Stock-Based Compensation" encourages a
fair-value based method of accounting for stock-based compensation.
As permitted by SFAS 123, IPC adopted disclosure-only requirements
and continues to account for stock-based compensation in accordance
with the provisions of Accounting Principles Board Opinion 25,
"Accounting for Stock Issued to Employees" (APB 25), as interpreted
by Financial Accounting Standards Board (FASB) Interpretation 44
"Accounting for Certain Transactions Involving Stock Compensation,"
and various EITF issues.

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.

Management Estimates
The preparation of financial statements in conformity with
accounting principles generally accepted in the United States of
America, 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
IPC follows SFAS 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.  The economic effects of regulation
can result in regulated companies recording costs that have been or
are expected to be allowed in the ratemaking process in a period
different from the period in which the costs would be charged to
expense by an unregulated enterprise.  When this occurs, costs are
deferred as assets in the balance sheet (regulatory assets) and
recorded as expenses in the periods when those same amounts are
reflected in rates.  Additionally, regulators can impose liabilities
upon a regulated company for amounts previously collected from
customers and for amounts that are expected to be refunded to
customers (regulatory liabilities).

Comprehensive Income
Components of IPC's comprehensive income include net income,
unrealized holding gains (losses) on marketable securities, IPC's
proportionate share of unrealized holding gains (losses) 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 July 2001 the FASB issued SFAS 141, "Business Combinations,"
which addresses accounting and reporting for business combinations.
SFAS 141 requires that all business combinations initiated after
June 30, 2001 be accounted for using one method, the purchase
method.  The adoption of SFAS 141 did not have a significant effect
on IPC's financial statements.

Also in July 2001 the FASB issued SFAS 142, "Goodwill and Other
Intangible Assets," which is effective January 1, 2002.  SFAS 142
changes the accounting for goodwill from an amortization method to
an impairment-only method.  Thus, amortization of goodwill,
including goodwill recorded in past transactions will cease.  IPC
will be required to complete transitional goodwill impairment tests
within six months of the date of adoption, and at least annually
thereafter.  The standard also includes provisions for the
reclassification of certain existing recognized intangibles to
goodwill, reassessment of the useful lives of existing recognized
intangibles and reclassification of certain intangibles out of
goodwill.  The adoption of SFAS 142 did not have a significant
effect on IPC's financial statements.

In August 2001 the FASB issued SFAS 143, "Accounting for Asset
Retirement Obligations," which is effective for fiscal years
beginning after June 15, 2002.  This Statement addresses financial
accounting and reporting for obligations associated with the
retirement of tangible long-lived assets and the associated asset
retirement costs.  An obligation may result from the acquisition,
construction, development and the normal operation of a long-lived
asset.  IPC is currently assessing but has not yet determined the
impact of SFAS 143 on its financial position and results of
operations.

Also in August 2001 the FASB issued SFAS 144, "Accounting for the
Impairment or Disposal of Long-Lived Assets," which is effective for
fiscal years beginning after December 15, 2001.  SFAS 144 addresses
financial accounting and reporting for the impairment or disposal of
long-lived assets, superseding SFAS 121,
"Accounting for the Impairment of Long-Lived Assets and for Long-
Lived Assets to be Disposed of."  IPC is currently assessing but has
not yet determined the impact of SFAS 144 on its financial position
and results of operations.

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 2001 have been
reclassified to conform to the current year's presentation.  Net
income and common stock equity were not affected by these
reclassifications.


2.  INCOME TAXES:
IPC has settled Federal and Idaho tax liabilities on all open years
through the 1997 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:

				    2001       2000        1999
				       (thousands of dollars)

Computed income taxes based on
  statutory federal income tax
  rate                             $ 46,118    $ 78,070    $ 50,077
Change in taxes resulting from:
  AFDC                               (1,571)     (1,719)     (1,071)
  Investment tax credits             (3,169)     (3,083)     (3,032)
  Repair allowance                   (2,800)     (4,550)     (2,800)
  Settlement of prior years tax           -           2        (478)
    returns
  State income taxes (net of          4,313       9,465       5,475
    Federal reduction)
  Depreciation                        9,790       8,243       7,292
  Affordable housing tax                  -           -      (8,934)
    credits
  Other                                 848        (860)       (979)
Total provision for federal
  and state income taxes           $ 53,529    $ 85,568    $ 45,550
Effective tax rate                     40.6%       38.4%       31.8%



The provision for income taxes consists of the following:

				    2001      2000       1999
				     (Thousand of Dollars)
Income taxes currently
  (receivable) payable:
   Federal                       $(37,352)  $ 35,259  $ 38,169
   State                          (12,544)     5,398     9,128
    Total                         (49,896)    40,657    47,297
Income taxes deferred - Net of
   amortization:
   Federal                         84,372     38,887     2,246
   State                           17,087      7,407    (2,030)
    Total                         101,459     46,294       216
Investment tax credits:
   Deferred                         5,135      1,700     1,069
   Restored                        (3,169)    (3,083)   (3,032)
    Total                           1,966     (1,383)   (1,963)
Total provision for income
   taxes                         $ 53,529   $ 85,568  $ 45,550



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

				     2001         2000
				   (thousands of dollars)

  Deferred tax assets:
   Regulatory liabilities         $ 41,290      $ 40,230

   Advances for construction         3,941         9,224
   Other                            16,825        23,586
    Total                           62,056        73,040
  Deferred tax liabilities:
   Electric plant                  250,180       249,546
   Regulatory assets               209,832       213,552
   Conservation programs            11,138        13,561
   PCA                             119,436        47,189
   Other                            27,530        10,268
    Total                          618,116      $534,116

  Net deferred tax liabilities    $556,060      $461,076



3.  PREFERRED STOCK:
The number of shares of preferred stock outstanding at December 31,
2001 and 2000 were as follows:

				     Shares
				  Outstanding at      Call Price
				    December 31,       Per Share
				  2001      2000
Preferred stock:
 Cumulative, $100 par value:
   4% preferred stock
     (authorized 215,000
     shares)                     143,872  150,656     $104.00
   Serial preferred stock,
     7.68% Series (authorized
     150,000 shares)             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     $103.535 to
						      $100.354
     Auction rate preferred
       stock, $100,000 stated
       value (authorized 500
       shares)(b)                    500      500     $100,000.00

       Total                     544,372  551,156


(a)  The preferred stock is not redeemable prior to July 1, 2003.
(b)  Dividend rate at December 31, 2001 was 3.65% and ranged between
     3.12% and 4.95% during the year.

During 2001 and 2000 IPC reacquired and retired 6,784 and 7,456
shares of 4% preferred stock.  As of December 31, 2001, the
overall effective cost of all outstanding preferred stock was
5.13 percent.


4.  LONG-TERM DEBT:
At December 31, 2001, the maturities for the aggregate amount of
long-term debt outstanding were (in thousands of dollars):

2002                           $ 27,078
2003                             80,083
2004                             50,077
2005                             60,080
2006                                 82
Thereafter                      611,879

   Total                       $829,279


On March 23, 2000, IPC filed a $200 million shelf registration
statement that could be used for First Mortgage Bonds (including
medium term notes), unsecured debt, or preferred stock.  On December
1, 2000, IPC issued $80 million principal amount of Secured Medium
Term Notes, Series C, 7.38% Series due 2007.  Proceeds were used for
the early redemption in January 2001 of the $75 million First
Mortgage Bonds 9.50% Series due 2021.  On March 2, 2001, IPC issued
$120 million principal amount of Secured Medium Term Notes, Series
C, 6.60% Series due 2011 with the proceeds used to reduce short-term
borrowing incurred in support of ongoing long-term construction
requirements.   At December 31, 2001, no amount remained to be
issued on this shelf registration statement.

On August 16, 2001, IPC filed a $200 million shelf registration
statement that can be used for First Mortgage Bonds (including
medium-term notes), unsecured debt or preferred stock.  At December
31, 2001, no amounts had been issued.

In August 2001, $25 million First Mortgage Bonds 9.52% Series due
2031 were redeemed early.

The amount of first mortgage bonds issuable by IPC is limited to a
maximum of $900 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.

On April 26, 2000, at the request of IPC, the American Falls
Reservoir District issued its American Falls Refunding Replacement
Dam Bonds, Series 2000, in the aggregate principal amount of $20
million for the purpose of refunding on April 26, 2000 a like amount
of its bonds dated May 1, 1990.  IPC has guaranteed repayment of
these bonds.

On May 17, 2000, tax exempt Pollution Control Revenue Refunding
Bonds Series 2000 in the aggregate principal amount of $4 million
were issued by Port of Morrow, Oregon for the purpose of refunding
on August 1, 2000, a like amount of its Pollution Control Revenue
Bonds, Series 1978.

At December 31, 2001 and 2000 the overall effective cost of all
outstanding first mortgage bonds and pollution control revenue bonds
was 7.0 percent and 7.52 percent, respectively.


5.  FAIR VALUE OF FINANCIAL INSTRUMENTS:
The estimated fair value of IPC's financial instruments has been
determined by IPC 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 notes receivable,
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 $868
million in 2001 and $866 million in 2000.  Included in receivables
were notes totaling $12 million in 2001 and $8 million in 2000.
Estimated fair value of these instruments was $11 million in 2001
and $8 million in 2000.  Included in investments and other property
were financial instruments totaling $24 million in 2001 and $19
million in 2000.  Estimated fair value of these instruments was $23
million in 2001 and  $19 million in 2000.


6.  NOTES PAYABLE:
At December 31, 2001, IPC had regulatory authority to incur up to
$500 million of short-term indebtedness.  IPC has a $165 million
facility that expires April 26, 2002 and a $120 million facility
that expires April 18, 2002.  Under these facilities IPC 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 amounts supported by the bank credit facilities.

Also at December 31, 2001, IPC had $100 million of floating rate
notes outstanding, payable on September 1, 2002.

Balances and interest rates of short-term borrowings were as follows
at December 31 (in thousands of dollars):

				      2001      2000

Balance at end of year              $282,000    $ 59,700
Effective annual interest rate
  at end of year                        2.1%        6.8%


7.  COMMITMENTS AND CONTINGENT LIABILITIES:
Commitments under contracts and purchase orders relating to IPC's
program for construction and operation of facilities amounted to
approximately $9 million at December 31, 2001.  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
30 years.  Under these contracts IPC is required to purchase all of
the output from these facilities.  During the fiscal year ended
December 31, 2001, IPC purchased 728,155 MWh at a cost of $45
million.

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


8. STOCK-BASED COMPENSATION:
IPC participates in two stock-based compensation plans of IDACORP
that are intended to align employee and shareholder objectives
related to the long-term growth of IPC.

IDACORP adopted the 2000 Long-Term Incentive and Compensation Plan
(LTICP) for officers, key employees and directors.   The LTICP
permits the grant of nonqualified stock options, incentive stock
options, stock appreciation rights, restricted stock, restricted
stock units, performance units, performance shares, and other
awards.

In  2001 and 2000, IPC's employees were issued IDACORP stock options
with an exercise price equal to the market price of the IDACORP
stock on the date of grant.  The maximum term of the options is ten
years, and they vest over a five-year period.  In accordance with
APB 25, no compensation costs have been recognized for these awards.

Stock option transactions are summarized as follows.

			     2001                   2000
				Weighted                Weighted
				average                  average
		      Number    exercise     Number     exercise
		     of shares   price      of shares     price
Outstanding
  beginning of
  year                220,000    $  35.81          -    $     -
  Granted             174,000       40.31    220,000      35.81
  Exercised                 -           -          -          -
  Cancelled                 -           -          -          -
Outstanding end
  of year             394,000    $  37.80    220,000    $ 35.81

Exercisable:           44,000    $  35.81          -    $     -

The outstanding options had a range of exercise prices from $35.81
to $40.31.  As of December 31, 2001 the weighted average remaining
contractual life is 8.8 years.

IDACORP also has a restricted stock plan for certain key employees.
Each grant made under this plan has a three-year restricted period,
and the final award amounts depend on the attainment of cumulative
earnings per share performance goals.  At December 31, 2001 there
were 265,766 IDACORP shares remaining available under this 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 2001, 2000 and
1999, total compensation accrued under the plan was less than $1
million for each year.

The following table summarizes restricted stock activity for the
years 2001, 2000 and 1999:

				    2001      2000     1999
Shares outstanding - beginning
  of year                          49,290    41,277    41,934
Shares granted                     22,118    32,268    22,288
Shares forfeited                     (474)        -    (9,585)
Shares issued                     (18,678)  (24,255)  (13,360)
Shares outstanding - end of
  year                             52,256    49,290    41,277
Weighted average fair
  value of current year
  stock grants on grant date      $ 40.56   $ 34.44   $ 32.88

Had compensation cost for the stock-based compensation plans been
determined on the basis of fair value pursuant to the provisions of
SFAS 123, net income would have been as follows (in thousands of
dollars):

			      2001     2000        1999
Net income:
  As reported              $ 78,238  $137,488   $ 97,528
  Pro forma                $ 77,398  $137,620   $ 97,327

For purposes of the pro forma calculations above, the estimated fair
value of the options and restricted stock are amortized to expense
over the vesting period.  The fair value of the restricted stock is
the market price of the stock on the date of grant.  The fair value
of each option granted was estimated at the date of grant using the
Binomial option-pricing model with the following assumptions:

			   2001         2000
Stock dividend yield       4.60%        5.19%
Expected stock price
  volatility                 29%          27%
Risk-free interest rate    5.11%        6.15%
Expected option lives    7 years      7 years
Fair value of options
  granted                 $ 9.93       $ 8.42


9.  BENEFIT PLANS:
Pension Plans
IPC has a noncontributory defined benefit pension plan covering most
employees.  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 in 2001,
2000 and 1999.  The trustee invests the plan 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.  IPC financed this plan
by purchasing life insurance policies and investments in marketable
securities, all of which are 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 benefit
cost for these plans (in thousands of dollars):

			 Pension Plan           Deferred Compensation
						     Plan
		     2001      2000     1999      2001    2000     1999
Service cost         $ 7,978  $ 7,442  $  8,389  $  624   $  574  $  744
Interest cost         17,634   16,718    16,402   2,039    1,965   1,797
Expected return on
  assets             (30,117) (30,095)  (25,240)      -        -       -
Recognized net
  actuarial (gain)
  loss                (3,179)  (4,503)     (344)    281      242     279
Amortization of
  prior service cost     708      708       708    (345)    (353)   (325)
Amortization of
  transition asset      (263)    (263)     (263)    613      613     613
Net periodic
  pension cost       $(7,239) $(9,993) $   (348) $3,212   $3,041  $3,108

The following table summarizes the changes in benefit obligation and
plan assets of these plans (in thousands of dollars):

						     Deferred
						   Compensation
			     Pension Plan              Plan
			   2001       2000       2001      2000
Change in projected
  benefit obligation:
  Benefit obligation at
    January 1            $241,281   $229,042    $ 27,876  $ 26,925
  Service cost              7,978      7,442         624       574
  Interest cost            17,634     16,718       2,039     1,965
  Actuarial loss (gain)    18,560        455       2,352       840
  Benefits paid           (12,586)   (12,376)     (2,420)   (2,516)
  Plan amendments             341          -         (66)       88
  Benefit obligation at
    December 31           273,208    241,281      30,405    27,876
Change in plan assets:
  Fair value at January
    1                     340,789    340,521           -         -
  Actual return on plan
    assets                 (1,936)    12,644           -         -
  Employer contributions        -          -           -         -
  Benefit payments        (12,586)   (12,376)          -         -
  Fair value at December
    31                    326,267    340,789           -         -

Funded status              53,059     99,508     (30,405)  (27,876)
Unrecognized actuarial
  loss (gain)             (31,857)   (85,648)      8,513     6,442
Unrecognized prior
  service cost              7,589      7,954         (75)     (355)
Unrecognized net
  transition liability       (916)    (1,178)      2,149     2,762
Net amount recognized    $ 27,875   $ 20,636    $(19,818) $(19,027)



Amounts recognized in the
  statement of financial
  position consist of:
Prepaid (accrued) pension
  cost                   $ 27,875   $ 20,636    $(28,500) $(26,365)
Intangible asset                -          -       2,074     2,407
Accumulated other
  comprehensive income          -          -       6,608     4,931
Net amount recognized    $ 27,875   $ 20,636    $(19,818) $(19,027)


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

					Postretirement
			     Pension       Benefits
			     Benefits
			   2001   2000   2001   2000
Discount rate              7.0%   7.5%   7.0%   7.5%
Expected long-term rate    9.0    9.0    9.0    9.0
  of return on assets
Annual salary increases    4.5    4.5      -      -

Employee Savings Plan
IPC has an Employee Savings Plan, which complies with Section 401(k)
of the Internal Revenue Code and covers substantially all employees.
IPC matches specified percentages of employee contributions to the
plan.  Matching contributions amounted to $4 million in 2001 and $3
million in 2000 and 1999.

Postretirement Benefits
IPC maintains a defined benefit postretirement plan (consisting of
health care and death benefits) that covers all employees who were
enrolled in the active group plan at the time of retirement, their
spouses and qualifying dependents.

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

				    2001      2000      1999
  Service cost                     $  831    $  851    $  896
  Interest cost                     3,589     3,374     2,867
  Expected return on plan assets   (2,343)   (2,522)   (2,230)
  Amortization of unrecognized
    transition obligation           2,040     2,040     2,040
  Amortization of prior service
    cost                             (563)     (691)     (691)
  Amortization of unrecognized net
    gains                               -         -         -
  Net periodic post-retirement
    benefit cost                   $3,554    $3,052    $2,882

The following table summarizes the changes in benefit obligation and
plan assets (in thousands of dollars):

				    2001      2000
Change in accumulated benefit
  obligation:
    Benefit obligation at
      January 1                   $ 48,806   $ 41,139
    Service cost                       831        851
    Interest cost                    3,589      3,374
    Plan amendments                    600      1,200
    Actuarial loss                   3,296      5,635
    Benefits paid                   (3,472)    (3,393)
    Benefit obligation at
      December 31                   53,650     48,806
Change in plan assets:
    Fair value of plan assets at
      January 1                     26,071     26,805
    Actual (loss) return on plan
      assets                        (2,004)      (760)
    Employer contributions           4,413      3,108
    Benefits paid                   (3,296)    (3,082)
    Fair value of plan assets at
      December 31                   25,184     26,071

Funded status                      (28,466)   (22,735)
Unrecognized prior service cost     (6,173)    (7,336)

Unrecognized actuarial loss         10,828      3,361
  (gain)
Unrecognized transition             22,440     24,480
  obligation
Accrued benefit obligations
  included with other deferred
  credits                         $ (1,371)  $ (2,230)


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

					  1-          1-
				     Percentage-  Percentage-
					Point        Point
				       increase    decrease
Effect on total of service and
  interest cost components              $ 335      $  (275)
Effect on accumulated
  postretirement benefit obligation     $3,167     $(2,709)

Postemployment Benefits
IPC 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.  IPC 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 benefit amounts
included in IPC's consolidated balance sheet at December 31 (in
thousands of dollars):

				2001      2000      1999
  Included with regulatory
    assets - other             $ 1,032   $ 1,517   $ 1,889
  Included with other
    deferred credits           $(3,010)  $(3,040)  $(3,282)


10.  UTILITY PLANT IN SERVICE AND JOINTLY-OWNED PROJECTS:
The following table sets out the major classifications of IPC's
utility plant in service, accumulated provision for depreciation and
annual depreciation provisions as a percent of average depreciable
balance for the years 2001 and 2000 (in thousands of dollars):

			      2001                  2000
		      Balance       Avg     Balance       Avg
				   Rate                   Rate

Production           $1,424,777    2.58%    $1,360,409    2.60%
Transmission            460,149    2.30        410,315    2.30
Distribution            854,445    3.34        811,604    3.34
General and Other       250,259    6.12        217,262    5.42
    Total in service  2,989,630    2.98%     2,799,590    2.94%
Accumulated
  provision for
  depreciation       (1,220,002)            (1,142,572)
    In service -
      net            $1,769,628             $1,657,018

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's participation as of December 31, 2001 is as follows:

					Company Ownership
					      Accumulated
				    Utility    Provision
				    Plant In       for
Name of Plant      Location         Service    Depreciation  %   MW
					   (thousands of dollars)
Jim Bridger
  Units 1-4      Rock Springs, WY   $403,514  $ 222,302     33  707
Boardman         Boardman, OR         64,580     38,133     10   55
Valmy Units 1
  and 2          Winnemucca, NV      303,666    157,177     50  261

IPC's wholly owned subsidiary, Idaho Energy Resources Company, 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 $43 million in
2001, $44 million in 2000 and $42 million in 1999.

IPC has contracts to purchase the energy from four Public Utilities
Regulatory Policy Act Qualified Facilities that are 50 percent owned
by Ida-West Energy Company, a wholly owned subsidiary of IDACORP.
Power purchased from these facilities amounted to $6 million in
2001, $8 million in 2000 and $9 million in 1999.

11.  DISCONTINUED OPERATIONS

Effective June 11, 2001, IPC transferred its non-utility wholesale
electricity marketing operations ("Energy Marketing") to IE.

Energy Marketing net assets transferred consists primarily of energy
trading contracts and trading accounts receivable and accounts
payable.  The results of operations of Energy Marketing were
previously reported on IPC's Statements of Income as "Energy
marketing activities - net."   For all periods presented, Energy
Marketing is reported as a discontinued operation.

In exchange for the transfer of Energy Marketing to IE, IPC received
a partnership interest in IE, which was transferred to IDACORP in
exchange for notes receivable from IDACORP totaling approximately
$76 million of which $43 million had been paid at December 31, 2001.
The $76 million represents the historical book value of the
transferred Energy Marketing net assets on May 31, 2001 of $21
million and retained intercompany tax liabilities of $55 million.
The notes receivable are due over periods of one to ten years and
bear interest at IDACORP's overall variable short-term borrowing
rate, which was 2.2 percent at December 31, 2001.

The net assets identified as part of the disposition of Energy
Marketing are reported as "Net assets of discontinued operations" on
IPC's consolidated balance sheet and consisted of the following at:

				  May 31,      December 31,
				    2001         2000
				  (thousands of dollars)
Property, plant and equipment
  - net                           $    551      $    1,021
Investments and other
  property                             864             382
Current assets                     489,526       1,070,645
Current liabilities               (481,762)     (1,031,686)
Other net noncurrent assets
  and liabilities                   67,071          (2,660)
 Net assets of discontinued
   operations                     $ 76,250      $   37,702

Concurrent with this transfer, IE and IPC entered into an
Electricity Supply Management Services (Agreement).  IPC received
approval of the Agreement from the IPUC, the Oregon Public Utility
Commission (OPUC) and the FERC.  Under the agreement IPC will
continue to own, operate and maintain its electric generating
equipment and transmission facilities and be responsible for system
reliability. IE will manage and dispatch the system resources to
balance generation and load within IPC's operating area.  IPC paid
approximately $2 million in accordance with the Agreement as of
December 31, 2001.  After the transfer of Energy Marketing, IPC sold
$23 million in off-system sales to and purchased $35 million in
purchased power from IE.

12.  REGULATORY ASSETS AND LIABILITIES:
The following is a breakdown of IPC's regulatory assets and
liabilities for the years 2001 and 2000:

				   2001                   2000
			    Assets    Liabilities    Assets    Liabilities
				     (thousands of dollars)
Income taxes               $ 209,832  $ 41,290      $213,552  $40,230
Conservation                  28,324     3,524        32,308    4,419
Employee benefits              2,825         -         3,742        -
PCA deferral and
  amortization               289,623         -       119,905        -
Oregon deferral and
  amortization                14,866         -             -        -
Derivatives                   47,781         -             -        -
Other                          5,990     1,127         9,700      202
Deferred investment tax
  credits                          -    68,016             -    66,050
    Total                  $ 599,241  $113,957      $379,207  $110,901


At December 31, 2001, IPC had $4 million of regulatory assets, which
primarily includes SFAS 112 benefits and reorganizations costs, that
were not earning a return on investment excluding the $210 million
that relates to income taxes and $48 million that relates to
derivatives.  The amortization periods range from three to four
years, respectively.

In the event that recovery of costs through rates becomes unlikely
or uncertain, SFAS 71 would no longer apply.  If IPC were to
discontinue application of SFAS 71 for some or all of IPC's
operations, then these items may represent stranded investments.  If
IPC 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.

Idaho Jurisdiction
PCA:  In the 2001 PCA filing, IPC requested recovery of $227 million
of power supply costs.  In May, the IPUC authorized recovery of $168
million, but deferred recovery of $59 million pending further
review.  The approved amount resulted in an average rate increase of
31.6 percent.  After conducting hearings on the remaining $59
million the IPUC authorized recovery of $48 million plus $1 million
of accrued interest, beginning in October 2001.  The remaining $11
million not recovered in rates from the PCA filing was written off
in September 2001.

Of the $227 million requested by IPC, $185 million related to the
true-up of power supply costs incurred in the 2000-2001 PCA year and
$42 million was for recovery of excess power supply costs forecasted
in the 2001-2002 PCA year.  The forecast amount, however,
underestimated expected power supply costs due to reservoir water
levels being less than forecast, necessitating the use of higher
cost alternatives to hydro generation.  Also market prices for
purchased power were higher than forecast earlier in the PCA year.

As part of the May 2001 PCA, the IPUC required IPC to implement a
three-tiered rate structure for Idaho residential customers.  The
IPUC determined that the approved rates for residential customers
should increase as the customer's electricity consumption increases.
The residential rate increases are 14.4 percent for the first 800
kWh of usage, 28.8 percent for the next 1,200 kWh, and 62 percent
for the usage over 2,000 kWh.

On October 18, 2001 IPC filed an application with the IPUC for an
order approving the costs to be included in the 2002-2003 PCA for
the Irrigation Load Reduction Program and the Astaris Load Reduction
Agreement.  These two programs were implemented in 2001 to reduce
demand and were approved by the IPUC and the Oregon Public Utility
Commission (OPUC).  The costs incurred in 2001 for these two
programs were $70 million for the Irrigation Load Reduction Program
and $62 million for the Astaris Load Reduction Agreement through
December 2001.

On August 31, 2001 IPC filed a request with the IPUC to implement a
rate credit to qualifying residential and small farm customers.  The
credit is the result of a settlement agreement between IPC and the
Bonneville Power Administration (BPA), which will pass on the
benefits of the Federal Columbia River Power System.  IPC estimates
the credit could be as much as $3.60 per month for residential
customers who use 1,200 kWh per month and $300 per month for farm
customers that use 100,000 kWh.  The IPUC, by Order No. 28868,
approved the credit to be passed to the qualified customers
effective October 1, 2001.

In its May 2001 rate authorization the IPUC also directed IPC to
reinstate a comprehensive conservation program given the current
volatility of market prices and the opportunity to incorporate long-
term conservation.  In response to that directive, IPC filed a
report of present energy efficiency activities, a list of
conservation measures, an examination of funding options and a
detailed program structure that could be implemented should the
Commission determine that additional conservation programs,
including the funding of these programs, is in the public interest.
The Commission has delayed further deliberations until the spring of
2002.

So far in the 2001-2002 rate year actual power supply costs included
in the PCA have been significantly greater than forecast due to
purchased power volumes and prices being greater than originally
forecasted and the implementation of the voluntary load reduction
programs with Astaris and the irrigation customers.  To account for
these higher-than-forecasted costs and the unamortized portion of
the 2000-2001 PCA balances, IPC has recorded regulatory assets of
$290 million as of December 31, 2001.

The May 2000 rate adjustment increased Idaho general business
customer rates by 9.5 percent, and resulted from forecasted below-
average hydroelectric generating conditions.  Overall, the PCA
adjustment increased general business revenue by approximately $38
million during the 2000-2001 rate period, partially offsetting the
forecasted increase in power supply costs.

The May 1999 rate adjustment reduced rates by 9.2 percent.  The
decrease was the result of both forecasted above-average
hydroelectric generating conditions for the 1999-2000 rate period
and a true-up from the 1998-1999 rate period.  Overall, the May 1999
rate adjustment decreased annual general business revenue by
approximately $40 million during the 1999-2000 rate period.

Regulatory Settlement:  IPC had a settlement agreement with IPUC
that expired at the end of 1999.  Under the terms of the settlement,
when earnings in IPC's Idaho jurisdiction exceeded an 11.75 percent
return on the year-end common equity, IPC set aside 50 percent of
the excess for the benefit of the Idaho retail customers.

In March 2000 IPC submitted its 1999 annual earnings sharing
compliance filing to the IPUC.  This filing indicated that there was
almost $10 million in 1999 earnings and $3 million in unused 1998
reserve balances available for the benefit of the Idaho customers.

In April 2000 the IPUC issued Order 28333, which ordered that $7
million of the revenue sharing balance be refunded to Idaho
customers through rate reductions effective May 16, 2000.  The Order
also approved IPC's continued participation in the Northwest Energy
Efficiency Alliance for the years 2000-2004, ordering IPC to set
aside the remaining $6 million of revenue sharing dollars to fund
that participation.

Demand Side Management (DSM):  IPC requested that the IPUC allow for
the recovery of post-1993 DSM expenses and acceleration of the
recovery of DSM expenditures authorized in the last general rate
case.  In its Order No. 27660 issued on July 31, 1998, the IPUC set
a new amortization period of 12 years instead of the 24-year period
previously adopted.  On April 17, 2000, the Idaho Supreme Court
affirmed the IPUC order, after hearing an appeal by a group of
industrial customers.

On February 23, 2001 the IPUC approved IPC's Green Energy Purchase
Program.  The Green Program is an optional program available to all
IPC customers in Idaho, allowing them to pay a premium to purchase
energy generated by alternative sources such as solar and wind.
Creating the Green Program will provide additional means for
customers to stimulate demand for new green resources and their
development.

Other Jurisdictions
IPC filed an application with the OPUC to begin recovering
extraordinary 2001 power supply costs in its Oregon jurisdiction.
On June 18, 2001, the OPUC approved new rates that would recover $1
million over the next year.  Under the provisions of the deferred
accounting statute, annual rate recovery amounts were limited to
three percent of IPC's 2000 gross revenues in Oregon.  During the
2001 session, the Oregon Legislature amended the statute giving the
OPUC authority to increase the maximum annual rate of recovery of
deferred amounts to six percent for electric utilities.  IPC
subsequently filed on October 5, 2001 to recover an additional three
percent extraordinary deferred power supply costs.  As a result of
this filing, the OPUC issued Order No. 01-994 allowing IPC to
increase its rate of recovery to six percent effective November 28,
2001.  The Oregon deferral balance is $15 million as of December 31,
2001, net of the June 18, 2001 and November 28, 2001 recovery.

IPC filed with the OPUC a request to implement the same BPA program
as in Idaho.  The OPUC held a public meeting on October 22, 2001 and
subsequently approved IPC's request to implement the BPA Residential
and Small Farm Energy Credit for the benefits derived during the
period October 1, 2001 through September 30, 2006.

In 1998, IPC received authority from the OPUC to reduce the
amortization period for the regulatory assets associated with DSM
programs from 24 years to 5 years.  The OPUC also approved
additional Oregon allocated DSM expenditures for recovery through
rates.  The Oregon costs will be recovered by extending an existing
surcharge until the amounts are collected.

13. DERIVATIVE FINANCIAL INSTRUMENTS:

Derivative Assets and Liabilities
IPC adopted SFAS 133, as amended, effective January 1, 2001.
Contracts company-wide were evaluated based upon the SFAS 133
derivative definitions and requirements.  Most of IPC's contracts
that meet the derivative definition are the energy trading contracts
that were already recorded at fair value under EITF 98-10.  Most of
the remaining energy contracts meet the definition of a normal
purchase or sale and therefore are not considered derivatives.
However, IPC has certain electricity contracts that are periodically
net settled with the counterparty (booked out).  Booking out of
electricity contracts is a normal business transaction within the
electric utility industry; however the FASB and the Derivative
Implementation Group (DIG) of the FASB initially interpreted that
book outs did not qualify for the normal purchase and sales
exception.  IPC has recorded the fair market value of the booked out
system electricity contracts within the financial statements as
"Derivative liabilities."

Such assets and liabilities at January 1 and December 31, 2001 are
as follows:

			January 1, 2001        December 31, 2001
				(thousands of dollars)
Assets                   $ 108,909              $      -
Liabilities               (207,407)              (47,781)

Net                      $ (98,498)             $(47,781)


The electricity contracts identified above are subject to IPC's
regulatory processes.  Accordingly, SFAS 71, allows the net amount
of these derivative assets and liabilities to be offset by
regulatory assets or liabilities.  The IPUC granted approval of this
use of SFAS 71 regulatory assets or liabilities in its Order No.
28661 issued March 12, 2001.

In June 2001 the DIG issued Interpretation C-15, which was amended
in October 2001, that tentatively concludes that certain booked out
contracts now qualify for the normal purchase and sales exception.
IPC is evaluating the effect of this new conclusion on its treatment
of booked out contracts but expects that some contracts previously
classified as derivatives will be exempt when C-15 becomes effective
on January 1, 2002.  The effect of this change will not have a
material effect on IPC's financial position, results of operations,
or cash flows.

As a result of the items discussed above, IPC's adoption of SFAS
133, as amended, did not have a material effect on its financial
position, results of operations, or cash flows.




INDEPENDENT AUDITORS' REPORT


To The Board of Directors and Shareowner 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, 2001 and 2000, and the related
consolidated statements of income, cash flows, retained earnings,
and comprehensive income for each of the three years in the period
ended December 31, 2001.  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 auditing standards
generally accepted in the United States of America.  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, 2001 and 2000, and
the results of their operations and their cash flows for each of the
three years in the period ended December 31, 2001 in conformity with
accounting principles generally accepted in the United States of
America.  Also, in our opinion, such consolidated 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 31, 2002





SUPPLEMENTAL FINANCIAL INFORMATION, UNAUDITED

QUARTERLY FINANCIAL DATA:
The following unaudited information is presented for each quarter of
2001 and 2000 (in thousands of dollars).  In the opinion of IPC, all
adjustments necessary for a fair statement of such amounts for such
periods have been included.  The results of operations for the
interim periods are not necessarily indicative of the results to be
expected for the full year.  Accordingly, earnings information for
any three-month period should not be considered as a basis for
estimating operating results for a full fiscal year.  Amounts are
based upon quarterly statements and the sum of the quarters may not
equal the annual amount reported.

					 Quarter Ended
			   March 31   June 30   September 30  December
								 31
2001
 Revenues                 $200,316    $227,930   $286,292     $197,774
 Income from operations     32,694      27,780     12,470       17,075
 Income taxes*              23,132      25,033        958        4,406
 Net income                 38,225      34,785      1,274        3,952
 Dividends on preferred
   stock                     1,461       1,292      1,347        1,272
 Earnings on common stock   36,764      33,493       (100)       2,680

2000
 Revenues                 $166,333    $213,081   $231,539     $224,708
 Income from operations     55,966      36,139     39,959       37,572
 Income taxes*              21,024      19,341     28,429       16,774
 Net income                 33,725      32,154     43,095       28,514
 Dividends on preferred
   stock                     1,428       1,484      1,511        1,506
 Earnings on common stock   32,297      30,670     41,584       27,008



*The income taxes presented for 2001 and 2000 do not include the
effect of discontinued operations (see Note 11 to the Consolidated
Financial Statements).

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

     None


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


PART IV
ITEM 14.  EXHIBITS, FINANCIAL STATEMENT SCHEDULE AND REPORTS ON FORM
	  8-K
(a)  Please refer to Item 8, "Financial Statements and Supplementary
     Data" for a complete listing of all consolidated financial
     statements and financial statement schedules.
(b)  Reports on SEC Form 8-K.  The following Report on Form 8-K was
     filed for the three months ended December 31, 2001
	  Items Reported                Date of Report
	  Item 5 - Other Events         September 27, 2001
	  Item 7 - Financial Statements
		   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(a)(iii)    1-3198       3(a)(iii)  Articles  of  Amendment  to  Restated
	      Form 10-Q               Articles of Incorporation of  IPC  as
	      for 6/30/00             filed with the Secretary of State  of
				      Idaho on June 15, 2000.

*3(b)         1-3198       3(c)       By-laws  of IPC amended on  September
	      Form 10-Q               9, 1999, and presently in effect.
	      for 9/30/99

*3(c)         33-56071     3(d)       Articles of Share Exchange, as  filed
				      with  the Secretary of State of Idaho
				      on September 29, 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 1, 1993
	      1-3198       4          Thirty-fourth  December 1, 1993
	      Form 8-K
	      Dated
	      12/17/93
	      1-3198       4          Thirty-fifth   November 1, 2000
	      Form 8-K
	      Dated
	      11/21/00
	      1-3198       4(a)       Thirty-sixth   October 1, 2001
	      Form 8-K
	      Dated
	      9/27/01

 *4(b)        1-3198       4(b)       Instruments relating to IPC  American
	      Form 10-Q               Falls  bond  guarantee  (see  Exhibit
	      for 6/30/00             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.

 *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)       1-3198       10(c)      Guaranty  Agreement, dated April  11,
	      Form 10-Q               2000,  between IPC and Bank One Trust
	      for 6/30/00             Company,  N.A., as Trustee,  relating
				      to    $19,885,000   American    Falls
				      Replacement Dam Refinancing 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, 2001.

 *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  1-14465      10(h)(iv)  The  Revised Security Plan for  Board
	      1-3198                  of   Directors   -  a  non-qualified,
	      Form 10-K               deferred  compensation plan effective
	      for 1998                August  1,  1996,  revised  March  2,
				      1999.

 *10(h)(v)1   1-14465      10(e)      IDACORP,  Inc. Non-Employee Directors
	      Form 10-Q               Stock  Compensation Plan  as  of  May
	      for 6/30/99             17, 1999.

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

 *10(h)(vii)  1-3198       10(g)      Executive Employment Agreement  dated
	      Form 10-Q               April   12,  1999  between  IPC   and
	      for 6/30/99             Marlene Williams.

 *10(h)(viii) 1-14465      10(h)      Agreement between IDACORP,  Inc.  and
	      Form 10-Q               Jan  B.  Packwood,  J.  LaMont  Keen,
	      for 9/30/99             James   C.  Miller,  Richard  Riazzi,
				      Darrel  T.  Anderson, Bryan  Kearney,
				      Cliff  N.  Olson, Robert  W.  Stahman
				      and Marlene K. Williams.

 *10(h)(ix)1  1-14465      10(h)(ix)  IDACORP,    Inc.    2000    Long-Term
	      Form 10-K               Incentive and Compensation Plan.
	      for 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.

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

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

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

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

 21                                   Subsidiaries of IPC.

 23                                   Independent Auditors' Consent.


 ____________________________
 1 Compensatory plan




 IDAHO POWER COMPANY
  SCHEDULE II - CONSOLIDATED
 VALUATION AND QUALIFYING
 ACCOUNTS
 Years Ended December 31,
 2001, 2000 and 1999

	 Column A           Column B     Column C         Column D   Column E
					 Additions
			    Balance             Charged               Balance
			       At      Charged (Credited)             At End
			   Beginning     to     to Other  Deductions    Of
     Classification        Of Period   Income   Accounts      (1)     Period
					(thousands of dollars)

 2001:
 Reserves Deducted From
   Applicable Assets:
    Reserve for
      uncollectible
      accounts and assets  $ 23,079    $ 3,607  $(21,682)  $ 3,504   $ 1,500
   Other Reserves:
    Rate refunds           $      -    $     -  $      -   $     -   $     -
    Injuries and damages
      reserve              $  1,500    $     -  $      -   $     -   $ 1,500
    Miscellaneous
      operating reserves   $  4,656    $   107  $    (11)  $ 1,201   $ 3,551

 2000:
 Reserves Deducted From
   Applicable Assets:
    Reserve for
      uncollectible
      accounts             $ 1,397     $23,340  $      -   $ 1,658   $23,079
   Other Reserves:
    Rate refunds           $ 8,893     $ 3,505  $      -   $12,398   $     -
    Injuries and damages
      reserve              $ 1,500     $     -  $      -   $     -   $ 1,500
    Miscellaneous
      operating reserves   $ 8,473     $   306  $      -   $ 4,123   $ 4,656

 1999:
 Reserves Deducted From
   Applicable Assets:
    Reserve for
      uncollectible
       accounts            $ 1,397     $ 1,547  $      -   $ 1,547   $ 1,397
   Other Reserves:
    Rate refunds           $ 5,356     $10,543  $      -   $ 7,006   $ 8,893
    Injuries and damages
      reserve              $ 1,500     $     -  $      -   $     -   $ 1,500
    Miscellaneous
      operating reserves   $ 6,907     $ 3,242  $      -   $ 1,676   $ 8,473


 Notes:    (1) Represents deductions from the reserves for purposes for
	   which the reserves were created.



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

				 IDAHO POWER COMPANY
				 (Registrant)

 March 22, 2002                  By:/s/J. LaMont Keen
				       J. LaMont Keen
				       President and Chief
				       Operating Officer

 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/  Jon H. Miller                 Chairman of the Board   March 22, 2002
	 Jon H. Miller


 By:/s/  Jan B. Packwood               Chief Executive Officer      "
	 Jan B. Packwood                     and Director


 By:/s/  J. LaMont Keen                President and Chief          "
	 J. LaMont Keen                 Operating Officer


 By:/s/  Darrel T. Anderson            Vice President, Chief        "
	 Darrel T. Anderson            Financial Officer and
					    Treasurer
				       (Principal Financial
					    Officer)
				       (Principal Accounting
					    Officer)

 By:/s/  Rotchford L. Barker     By:/s/   Evelyn Loveless           "
	 Rotchford L. Barker              Evelyn Loveless
	 Director                              Director

 By:/s/  Roger L. Breezley       By:/s/   Gary G. Michael           "
	 Roger L. Breezley                Gary G. Michael
	 Director                         Director

 By:/s/  John B. Carley          By:/s/   Peter S. O'Neill          "
	 John B. Carley                   Peter S. O'Neill
	 Director                         Director

 By:                             By:/s/   Robert a. Tinstman        "
	 Christopher L. Culp              Robert A. Tinstman
	 Director                         Director

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




 EXHIBIT INDEX


 Exhibit                                                    Page
 Number                                                     Number

 10(n)(ii)      The Executive Annual
		Incentive Plan for senior
		management employees of IPC
		effective January 1, 2001.

 12             Statements Re: Computation of
		Ratio of Earnings to Fixed
		Charges.

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

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

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

 21             Subsidiaries of IPC

 23             Independent Auditors'
		Consent.