IDACORP INC - 10-Q Quarterly Report

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

X	QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15 (d) OF THE SECURITIES

EXCHANGE ACT OF 1934

For the quarterly period ended June 30, 2002

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

For the transition period from

	Exact name of registrant as specified
	in its charter, state of	I.R.S. Employer
Commission File	incorporation, address of principal executive	Identification
Number	offices, and telephone number	Number

1-14465	IDACORP, Inc.	82-0505802
	1221 W. Idaho Street
	Boise, ID 83702-5627

	Telephone: (208) 388-2200
	State of Incorporation: Idaho

None

Former name, former address and former fiscal year, if changed since last report.

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 ___

Number of shares of Common Stock outstanding as of June 30, 2002: 37,698,844

GLOSSARY

AFDC	-	Allowance for Funds used During Construction
APB	-	Accounting Principles Board
APC	-	Applied Power Company
BPA	-	Bonneville Power Administration
Cal ISO	-	California Independent System Operator
CalPX	-	California Power Exchange
CSPP	-	Cogeneration and Small Power Production
DIG	-	Derivatives Implementation Group
DSM	-	Demand-Side Management
EITF	-	Emerging Issues Task Force
EPA	-	Environmental Protection Agency
EPS	-	Earning per share
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
LTICP	-	Long-Term Incentive and Compensation Plan
MD&A	-	Management's Discussion and Analysis
MMbtu	-	Million British Thermal Units
MW	-	Megawatt
MWh	-	Megawatt-hour
OPUC	-	Oregon Public Utility Commission
Overton	-	Overton Power District No. 5
PCA	-	Power Cost Adjustment
PG&E	-	Pacific Gas and Electric Company
PURPA	-	Public Utilities Regulatory Policy Act
REA	-	Rural Electrification Administration
RFP	-	Request for proposals
RMC	-	Risk Management Committee
RTOs	-	Regional Transmission Organizations
SCE	-	Southern California Edison
SFAS	-	Statement of Financial Accounting Standards
SPPCo	-	Sierra Pacific Power Company
Valmy	-	North Valmy Steam Electric Generating Plant
WSCC	-	Western Systems Coordinating Council

INDEX

Page

Part I. Financial Information:
	Item 1. Financial Statements (unaudited)
		Consolidated Statements of Income		4-5
		Consolidated Balance Sheets		6-7
		Consolidated Statements of Cash Flows		8
		Consolidated Statements of Comprehensive Income		9
		Notes to Consolidated Financial Statements		10-21
		Independent Accountants' Report		22

	Item 2. Management's Discussion and Analysis of Financial
			Condition and Results of Operations	23-40

	Item 3. Quantitative and Qualitative Disclosures about Market Risk			40

Part II. Other Information:

	Item 1. Legal Proceedings			41

	Item 2. Change in Securities and Use of Proceeds			41

	Item 4. Submission of Matters to a Vote of Security Holders			42

	Item 6. Exhibits and Reports on Form 8-K			43-44

Signatures				45

FORWARD LOOKING INFORMATION
This Form 10-Q contains "forward-looking statements" intended to qualify for the 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-Q at Part I, Item 2. 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 - FINANCIAL INFORMATION
Item 1. Financial Statements
IDACORP, Inc.
Consolidated Statements of Income
(unaudited)

				Three months ended
				June 30,
				2002		2001
				(millions of dollars except for per share amounts)
OPERATING REVENUES:
	Electric utility:
		General business		$	188	$	156
		Off system sales			11		59
		Other revenues			10		13
			Total electric utility revenues		209		228
	Energy marketing commodities and services				408		1,347
	Other				4		3
		Total operating revenues			621		1,578

OPERATING EXPENSES:
	Electric utility:
		Purchased power			31		169
		Fuel expense			22		22
		Power cost adjustment			42		(68)
		Other operations and maintenance			54		50
		Depreciation			23		22
		Taxes other than income taxes			5		5
			Total electric utility expenses		177		200
	Energy marketing:
		Cost of energy commodities and services			423		1,286
		Selling, general and administrative			5		10
	Other				8		9
			Total operating expenses		613		1,505

OPERATING INCOME:
	Electric utility				32		28
	Energy marketing				(20)		51
	Other				(4)		(6)
		Total operating income			8		73

OTHER INCOME					2		4

INTEREST EXPENSE AND OTHER:
	Interest on long-term debt				12		15
	Other interest				3		3
	Preferred dividends of Idaho Power Company				1		1
		Total interest expense and other			16		19

INCOME (LOSS) BEFORE INCOME TAXES					(6)		58

INCOME TAXES					(9)		22

NET INCOME				$	3	$	36

AVERAGE COMMON SHARES
	OUTSTANDING (000'S)				37,665		37,412

EARNINGS PER SHARE OF COMMON
	STOCK (basic and diluted)			$	0.08	$	0.96

The accompanying notes are an integral part of these statements.

IDACORP, Inc.
Consolidated Statements of Income
(unaudited)

				Six months ended
				June 30,
				2002		2001
				(millions of dollars except for per share amounts)
OPERATING REVENUES:
	Electric utility:
		General business		$	373	$	289
		Off system sales			31		114
		Other revenues			19		25
			Total electric utility revenues		423		428
	Energy marketing commodities and services				843		2,277
	Other				8		6
		Total operating revenues			1,274		2,711

OPERATING EXPENSES:
	Electric utility:
		Purchased power			61		295
		Fuel expense			50		47
		Power cost adjustment			76		(126)
		Other operations and maintenance			103		99
		Depreciation			46		42
		Taxes other than income taxes			10		11
			Total electric utility expenses		346		368
	Energy marketing:
		Cost of energy commodities and services			849		2,143
		Selling, general and administrative			8		44
	Other				16		17
			Total operating expenses		1,219		2,572

OPERATING INCOME:
	Electric utility				77		60
	Energy marketing				(14)		90
	Other				(8)		(11)
		Total operating income			55		139

OTHER INCOME					8		8

INTEREST EXPENSE AND OTHER:
	Interest on long-term debt				26		28
	Other interest				6		6
	Preferred dividends of Idaho Power Company				3		3
		Total interest expense and other			35		37

INCOME BEFORE INCOME TAXES					28		110

INCOME TAXES					-		39

NET INCOME				$	28	$	71

AVERAGE COMMON SHARES
	OUTSTANDING (000'S)				37,613		37,414

EARNINGS PER SHARE OF COMMON
	STOCK (basic and diluted)			$	0.74	$	1.89

The accompanying notes are an integral part of these statements.

IDACORP, Inc.
Consolidated Balance Sheets
(unaudited)
Assets

			June 30,		December 31,
			2002		2001
			(millions of dollars)

CURRENT ASSETS:
	Cash and cash equivalents		$	47	$	67
	Receivables:
		Customer		178		207
		Allowance for uncollectible accounts		(43)		(43)
		Employee notes		7		6
		Other		14		11
	Energy marketing assets			106		194
	Taxes receivable			-		51
	Accrued unbilled revenues			42		37
	Materials and supplies (at average cost)			25		26
	Fuel stock (at average cost)			9		9
	Prepayments			35		32
	Regulatory assets			15		56
		Total current assets		435		653

INVESTMENTS				212		159

PROPERTY, PLANT AND EQUIPMENT:
	Utility plant in service			3,020		2,990
	Accumulated provision for depreciation			(1,261)		(1,220)
		Utility plant in service - net		1,759		1,770
	Construction work in progress			112		96
	Utility plant held for future use			2		2
	Other property, net of accumulated depreciation			21		18
		Property, plant and equipment - net		1,894		1,886

OTHER ASSETS:
	American Falls and Milner water rights			31		31
	Company-owned life insurance			39		40
	Energy marketing assets - long-term			181		204
	Regulatory assets			461		544
	Long-term receivables			74		74
	Other			52		51
		Total other assets		838		944

		TOTAL	$	3,379	$	3,642

The accompanying notes are an integral part of these statements.

IDACORP, Inc.
Consolidated Balance Sheets
(unaudited)
Liabilities and Capitalization

				June 30,		December 31,
				2002		2001
				(millions of dollars)

CURRENT LIABILITIES:
	Current maturities of long-term debt			$	115	$	36
	Notes payable				410		363
	Accounts payable				126		248
	Energy marketing liabilities				105		125
	Derivative liabilities				-		41
	Taxes accrued				17		-
	Interest accrued				14		15
	Deferred income taxes				8		24
	Other				39		55
		Total current liabilities			834		907

OTHER LIABILITIES:
	Deferred income taxes				557		590
	Energy marketing liabilities - long-term				111		135
	Regulatory liabilities				117		114
	Derivative liabilities - long-term				-		7
	Other				80		71
		Total other liabilities			865		917

LONG-TERM DEBT					706		843

COMMITMENTS AND CONTINGENT LIABILITIES					-		-

PREFERRED STOCK OF IDAHO POWER COMPANY					104		104

SHAREHOLDERS' EQUITY:
	Common stock, no par value (shares authorized 120,000,000;
		37,837,252 and 37,628,919 shares issued, respectively)			462		454
	Retained earnings				417		424
	Accumulated other comprehensive income (loss)				(5)		(4)
	Treasury stock (138,408 and 66,188 shares at cost, respectively)				(4)		(3)
		Total shareholders' equity			870		871

			TOTAL	$	3,379	$	3,642

The accompanying notes are an integral part of these statements.

IDACORP, Inc.
Consolidated Statements of Cash Flows
(unaudited)

				Six Months Ended
				June 30,
				2002		2001
				(millions of dollars)

OPERATING ACTIVITIES:
	Net income			$	28	$	71
	Adjustments to reconcile net income to net cash provided by
		(used in) operating activities:
		Allowance for uncollectible accounts			-		20
		Unrealized (gains) losses from energy marketing activities			58		(101)
		Gain on sale of assets			-		(1)
		Depreciation and amortization			56		54
		Deferred taxes and investment tax credits			(44)		87
		Accrued PCA costs			72		(127)
		Change in:
			Receivables and prepayments		23		105
			Accrued unbilled revenues		(5)		(3)
			Materials and supplies and fuel stock		1		(4)
			Accounts payable		(122)		(84)
			Taxes receivable/accrued		68		(27)
			Other current assets and liabilities		(8)		1
		Other - net			(2)		-
			Net cash provided by (used in) operating activities		125		(9)

INVESTING ACTIVITIES:
	Additions to property, plant and equipment				(56)		(101)
	Investments in affordable housing projects				(44)		-
	Proceeds from sales of assets				-		10
	Other - net				(4)		(3)
		Net cash used in investing activities			(104)		(94)

FINANCING ACTIVITIES:
	Proceeds from issuance of:
		First mortgage bonds			-		120
	Retirement of:
		First mortgage bonds			(50)		(75)
		Other long-term debt			(8)		(10)
	Dividends on common stock				(35)		(35)
	Increase in short-term borrowings				47		34
	Common stock issued				8		-
	Acquisition of treasury stock				(1)		(6)
	Other - net				(2)		(6)
		Net cash provided by (used in) financing activities			(41)		22

Net increase (decrease) in cash and cash equivalents					(20)		(81)

Cash and cash equivalents beginning of period					67		107

Cash and cash equivalents at end of period				$	47	$	26

SUPPLEMENTAL DISCLOSURE OF CASH FLOW
	INFORMATION:
	Cash paid (received) during the period for:
		Income taxes		$	(27)	$	(17)
		Interest (net of amount capitalized)		$	32	$	34

The accompanying notes are an integral part of these statements

IDACORP, Inc.
Consolidated Statements of Comprehensive Income
(unaudited)

		Three Months Ended
			June 30,
			2002		2001
			(millions of dollars)

NET INCOME			$	3	$	36

OTHER COMPREHENSIVE INCOME (LOSS):
	Unrealized gains (losses) on securities (net of tax of ($1))			(1)		-

TOTAL COMPREHENSIVE INCOME			$	2	$	36

		Six Months Ended
			June 30,
			2002		2001
			(millions of dollars)

NET INCOME			$	28	$	71

OTHER COMPREHENSIVE INCOME (LOSS):
	Unrealized gains (losses) on securities (net of tax of ($1) and ($1))			(1)		(2)

TOTAL COMPREHENSIVE INCOME			$	27	$	69

The accompanying notes are an integral part of these statements

Notes to Consolidated Financial Statements
(unaudited)

1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES:

Nature of Business
IDACORP, Inc. (IDACORP) is a holding company whose principal operating subsidiaries are Idaho Power Company (IPC) and IDACORP Energy (IE). IPC is regulated by the Federal Energy Regulatory Commission (FERC) and the state regulatory commissions of Idaho, Oregon 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. IE markets electricity and natural gas and offers risk management and asset optimization services to wholesale customers in 31 states and two Canadian provinces.

IDACORP announced, on June 21, 2002, that IE plans to wind down its power marketing operations. IE will not seek new customers and will limit its maximum value at risk limits to less than $3 million. In addition to minimizing its risk tolerance, IE anticipates staff reductions of approximately 50 percent over the next 18 months and has already given notice of layoffs to approximately 50 employees as of June 30, 2002. During this same time period, IE has targeted a reduction of working capital requirements for this business to less than $100 million. The changes in the business strategy are being driven by a number of factors that include changing liquidity requirements brought on by rating agencies, continued uncertainty in the regulatory and political environment and the reduction of credit worthy counterparties.

Beginning August 1, 2002, IPC resumed the function of buying and selling wholesale electricity to support its utility operations. IPC conducted electricity marketing until June 2001 when those operations were transferred to IE.

IDACORP, Inc.'s other subsidiaries include:

Ida-West Energy (Ida-West) - independent power projects development and management;
IdaTech - developer of integrated fuel cell systems;
IDACORP Financial Services (IFS) - affordable housing and other real estate investments;
Velocitus - commercial and residential Internet service provider;
IDACOMM - provider of telecommunications services.

References in this report to "we" and "our" are to IDACORP, Inc. and its subsidiaries.

Financial Statements
In our opinion, the accompanying unaudited consolidated financial statements contain all adjustments necessary to present fairly our consolidated financial position as of June 30, 2002, and our consolidated results of operations for the three and six months ended June 30, 2002 and 2001 and consolidated cash flows for the six months ended June 30, 2002 and 2001. These financial statements do not contain the complete detail or footnote disclosure concerning accounting policies and other matters that would be included in full year financial statements and therefore they should be read in conjunction with our audited consolidated financial statements included in our Annual Report on Form 10-K for the year ended December 31, 2001. The results of operations for the interim periods are not necessarily indicative of the results to be expected for the full year.

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

Adopted Accounting Standards
On January 1, 2002, we adopted Statement of Financial Accounting Standards (SFAS) 142, "Goodwill and Other Intangible Assets." SFAS 142 requires that goodwill and certain intangible assets no longer be amortized, but instead be tested for impairment at least annually.

As required by the statement, we have completed transitional impairment tests on our January 1, 2002 goodwill balance of $13 million which is related to the acquisitions of IdaTech and Velocitus. There was no impairment of goodwill based on these tests. We will be required to perform goodwill impairment tests at least annually, and more frequently if circumstances indicate a possible impairment.

The following table presents net income and earnings per share, adjusted to exclude goodwill amortization expense, for the three and six months ended June 30:

	Three months ended				Six months ended
	June 30,				June 30,
	2002		2001		2002		2001
	(millions of dollars)

Reported net income	$	3	$	36	$	28	$	71
Add back goodwill amortization		-		1		-		1
Adjusted net income	$	3	$	37	$	28	$	72

Basic and diluted earnings per share:

Reported net income	$	0.08	$	0.96	$	0.74	$	1.89
Add back goodwill amortization		0.00		0.01		0.00		0.03
Adjusted net income	$	0.08	$	0.97	$	0.74	$	1.92

SFAS 142 also includes provisions related to reclassification of intangible assets and reassessment of useful lives of intangible assets. We had no intangible assets affected by these provisions.

In January 2002, we adopted SFAS 144 "Accounting for the Impairment or Disposal of Long-Lived Assets." 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 Long-Lived Assets to be Disposed of." The adoption of SFAS 144 did not have a significant effect on our financial statements.

In June 2001, the Derivative Implementation Group of the Financial Accounting Standards Board (FASB) issued Interpretation C-15, "Scope Exceptions: Normal Purchases and Normal Sales Exception for Option-Type Contracts and Forward Contracts in Electricity," concluding that contracts subject to book-out were not eligible for the normal purchase and sales exception in SFAS 133, "Accounting for Derivative Instruments and Hedging Activities." Therefore, certain contracts were recorded as derivatives in prior periods. However, this Interpretation was revised in October 2001 and December 2001, and now allows these contracts to qualify for the exception. This revision applies only to electric utilities due to the unique nature of the industry. IPC has completed an evaluation of the effect of this revised Interpretation on its treatment of booked-out contracts and has determined that contracts previously classified as derivatives are exempt. The effect of the change does not have a material effect on IPC's financial statements.

New Accounting Pronouncements
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. We are currently assessing, but have not yet determined, the impact of SFAS 143 on our financial statements.

In June 2002, the FASB issued SFAS 146, "Accounting for Costs Associated with Exit or Disposal Activities." The standard requires companies to recognize costs associated with exit or disposal activities when they are incurred rather than at the date of a commitment to an exit or disposal plan. Examples of costs covered by the standard include lease termination costs and certain employee severance costs that are associated with a restructuring, discontinued operation, plant closing or other exit or disposal activity. This standard supersedes Emerging Issues Task Force Issue No. 94-3, "Liability Recognition for Certain Employee Termination Benefits and Other Costs to Exit an Activity (including Certain Costs Incurred in a Restructuring)." SFAS 146 is to be applied prospectively to exit or disposal activities initiated after December 31, 2002. We are currently assessing but have not yet determined the impact of SFAS 146 on our financial statements.

Emerging Issues Task Force (EITF) Issue No. 98-10, "Accounting for Contracts Involved in Energy Trading and Risk Management Activities," allowed gains and losses related to energy trading contracts to be shown either gross or net on the income statement. EITF Issue No. 02-3, "Accounting for Contracts Involved in Energy Trading and Risk Management Activities," requires that all energy trading activities within the scope of Issue 98-10 be presented on a net basis for periods ended after July 15, 2002. We are currently assessing, but have not yet determined, the impact of this Issue on our financial statements.

Reclassifications
Certain items previously reported for periods prior to June 30, 2002 have been reclassified to conform with the current period's presentation. Net income and shareholders' equity were not affected by these reclassifications.

2. INCOME TAXES:

Our effective tax rate for the first six months decreased from 35.6 percent in 2001 to 0.0 percent in 2002. An adjustment has been recorded to income tax expense to reflect an expected full year effective tax rate of zero. Reconciliations between the statutory income tax rate and the effective rates are as follows (in millions of dollars):

		Six Months Ended June 30,
		2002				2001
		Amount		Rate	Amount			Rate
Computed income taxes based on statutory
	federal income tax rate	$	10	35.0%	$		38		35.0%
Changes in taxes resulting from:
	Investment tax credits		(2)	(7.7)			(2)		(1.4)
	Repair allowance		(2)	(6.8)			(1)		(1.3)
	Pension expense		-	-			(1)		(0.8)
	State income taxes		1	5.0			5		4.7
	Depreciation		4	13.6			4		3.5
	Affordable housing tax credits		(12)	(43.0)			(6)		(5.5)
	Preferred dividends of IPC		1	3.9			1		0.9
	Other		-	-			1		0.5
Total provision for federal and state income taxes		$	-	0.0%	$		39		35.6%

3.PREFERRED STOCK OF IDAHO POWER COMPANY:

The number of shares of IPC preferred stock outstanding were as follows:

			June 30,	December 31,
			2002	2001
Cumulative, $100 par value:
	4% preferred stock (authorized 215,000 shares)		142,661	143,872
	Serial preferred stock, 7.68% Series (authorized
		150,000 shares)	150,000	150,000

Serial preferred stock, cumulative, without par
	value; total of 3,000,000 shares authorized:
	7.07% Series, $100 stated value, (authorized
		250,000 shares)	250,000	250,000
	Auction rate preferred stock, $100,000 stated
		value, (authorized 500 shares)	500	500

IPC is planning to redeem its auction rate preferred stock on August 15, 2002 for $50 million. This redemption will be financed with internally generated funds or short-term borrowings.

4. FINANCING:

The following table summarizes long-term debt at:

			June 30,		December 31,
			2002		2001
			(millions of dollars)
First mortgage bonds:
	6.85% Series due 2002		$	27	$	27
	6.40% Series due 2003			80		80
	8 % Series due 2004			50		50
	5.83% Series due 2005			60		60
	7.38% Series due 2007			80		80
	7.20% Series due 2009			80		80
	6.60% Series due 2011			120		120
	7.50% Series due 2023			80		80
	8.75% Series due 2027			-		50
		Total first mortgage bonds		577		627
Pollution control revenue bonds:
	8.30% Series 1984 due 2014			50		50
	6.05% Series 1996A due 2026			68		68
	Variable Rate Series 1996B due 2026			24		24
	Variable Rate Series 1996C due 2026			24		24
	Variable Rate Series 2000 due 2027			4		4
		Total pollution control revenue bonds		170		170
REA notes				1		1
American Falls bond guarantee				20		20
Milner Dam note guarantee				12		12
Unamortized premium/discount - net				(1)		(1)
Debt related to investments in affordable housing				42		50
	Total			821		879
Current maturities of long-term debt				(115)		(36)

		Total long-term debt	$	706	$	843

In March 2002, $50 million First Mortgage Bonds 8.75% Series due 2027 were redeemed early using short-term borrowings.

Credit facilities have been established at both IPC and IDACORP. IDACORP has a $140 million three-year credit facility that expires in March 2005, and a $350 million 364-day credit facility that expires in March 2003. Under these facilities, IDACORP pays a facility fee on the commitment, quarterly in arrears, based on its corporate credit rating. Commercial paper may be issued up to the amounts supported by the credit facilities. At June 30, 2002, short-term borrowing on these facilities totaled $170 million.

IPC has regulatory authority to incur up to $350 million of short-term indebtedness. This amount will increase to $400 million from September 1, 2002 to October 15, 2002. IPC has a $200 million 364-day revolving credit facility that expires in March 2003, under which it pays a facility fee on the commitment quarterly in arrears, based on its corporate credit rating. Commercial paper may be issued subject to the regulatory maximum up to amounts supported by the credit facilities. At June 30, 2002, IPC's short-term borrowing under this facility totaled $140 million. IPC also has $100 million of floating rate notes outstanding, payable on September 1, 2002.

IDACORP currently has shelf registration statements totaling $800 million that can be used for the issuance of unsecured debt securities, including medium-term notes, and preferred or common stock. At June 30, 2002 none had been issued.

IPC currently has a $200 million shelf registration that can be used for first mortgage bonds, including medium-term notes, unsecured debt or preferred stock. At June 30, 2002 none had been issued.

5. COMMITMENTS AND CONTINGENT LIABILITIES:

Commitments under contracts and purchase orders relating to IPC's and Ida-West's programs for construction and operation of facilities amounted to approximately $4 million and $30 million, respectively, at June 30, 2002. The commitments are generally revocable by the companies subject to reimbursement of manufacturers' expenditures incurred and/or other termination charges.

From time to time we are a party to various legal claims, actions and complaints, certain of which may involve material amounts. Although we are unable to predict with certainty whether or not we 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 our financial statements.

Overton Power District No. 5
IE filed a lawsuit on November 30, 2001 in Idaho State District Court in and for the County of Ada against Overton Power District No. 5, a Nevada electric improvement district, for failure to meet payment obligations under a power contract. The contract provided for Overton to purchase 40 megawatts (MW) of electrical energy per hour from IE at $88.50 per megawatt hour (MWH), from July 1, 2001 through June 30, 2011. In the contract, Overton agreed to raise its rates to its customers to the extent necessary to make its payment obligations to IE under the contract.

IE has asked the Idaho District Court for damages pursuant to the contract, for a declaration that Overton is not entitled to renegotiate or terminate the contract and for injunctive relief requiring Overton to raise rates as stipulated in the contract. Overton filed an Answer and Counterclaim on April 23, 2002 claiming IE breached the agreement by failing to perform in accordance with its contractual obligation and asking for damages in the amount to be proved at trial. Overton also asserts that the contract is unenforceable or subject to rescission. IE believes Overton's assertions are without merit and has filed a motion for partial summary judgment. Trial is scheduled to commence on May 5, 2003.

IE believes that Overton's actions constitute a breach of the contract and intends to vigorously prosecute this lawsuit. While the outcome of litigation is never certain, IE believes it should prevail on the merits. At June 30, 2002, IE had a $74 million long-term asset related to the Overton claim. IE will review the recoverability of the asset on an ongoing basis.

Truckee-Donner Public Utility District
IE has received notice from Truckee-Donner Public Utility District (Truckee), located in the State of California, asserting that IE was in purported breach of, and that Truckee has the right to renegotiate certain terms of, the Agreement for the Sale and Purchase of Firm Capacity and Energy in place between the two entities. Generally, the terms of the contract provide for IE to sell to Truckee 10 MW light load energy and 20 MW heavy load energy for the term January 1, 2002 through December 31, 2002 at $72 per MWH and 25 MW flat energy for the term January 1, 2003 through December 31, 2009 at $72 per MWH. While IE believes there are no grounds for dispute under the contract, IE has agreed to informally negotiate with Truckee on the issues in an effort to resolve the matter.

On May 30, 2002, IE filed a lawsuit against Truckee in the Idaho State District Court in and for the County of Ada. IE seeks a declaration that it is not in breach of the contract, injunctive relief requiring Truckee to make payments pursuant to the terms of the contract and to raise its rates as stipulated in the contract. The lawsuit has been removed to the United States District Court for the District of Idaho. Truckee has not answered the Complaint, but has moved to dismiss the claims for injunctive relief.

On July 23, 2002, Truckee filed a complaint against IPC, IE and IDACORP with the FERC seeking relief under its long-term power contract for the purchase of wholesale electric power from IPC and IE.

The Complaint requests that FERC, among other matters, (1) reform or terminate the contract under Section 206 of the Federal Power Act, (2) order refunds, (3) assert exclusive jurisdiction over the rate issues and exercise primary jurisdiction to consider state-law claims arising out of the contract provisions and underlying facts, and (4) assess the market power of IE and IPC with the Sierra Pacific and IPC control areas under the FERC's Supply Margin Assessment test and impose appropriate remedies if the test is not passed.

California Energy Situation
As a component of IPC's non-utility energy trading in the state of California, IPC, in January 1999, entered into a participation agreement with the California Power Exchange (CalPX), a California non-profit public benefit corporation. The CalPX, at that time, operated a wholesale electricity market in California by acting as a clearinghouse through which electricity was bought and sold. Pursuant to the participation agreement, IPC could sell power to the CalPX under the terms and conditions of the CalPX Tariff. Under the participation agreement, if a participant in the CalPX exchange defaults on a payment to the exchange, the other participants are required to pay their allocated share of the default amount to the exchange. The allocated shares are based upon the level of trading activity, which includes both power sales and purchases, of each participant during the preceding three-month period.

On January 18, 2001, the CalPX sent IPC an invoice for $2.2 million - a "default share invoice" - as a result of an alleged Southern California Edison (SCE) payment default of $214.5 million for power purchases. IPC made this payment. On January 24, 2001, IPC terminated the participation agreement. On February 8, 2001, the CalPX sent a further invoice for $5.2 million, due February 20, 2001, as a result of alleged payment defaults by SCE, Pacific Gas and Electric Company (PG&E) and others. However, because the CalPX owed IPC $11.3 million for power sold to the CalPX in November and December 2000, IPC did not pay the February 8th invoice. IPC essentially discontinued energy trading with California entities in December 2000.

IPC believes that the default invoices were not proper and that IPC owes no further amounts to the CalPX. IPC has pursued all available remedies in its efforts to collect amounts owed to it by the CalPX. On February 20, 2001, IPC filed a petition with FERC to intervene in a proceeding which requested the FERC to suspend the use of the CalPX charge back methodology and provides for further oversight in the CalPX's implementation of its default mitigation procedures.

A preliminary injunction was granted by a Federal Judge in the Federal District Court for the Central District of California enjoining the CalPX from declaring any CalPX participant in default under the terms of the CalPX Tariff. On March 9, 2001, the CalPX filed for Chapter 11 protection with the U.S. Bankruptcy Court, Central District of California.

In April 2001, PG&E filed for bankruptcy. The CalPX and the California Independent System Operator (Cal ISO) were among the creditors of PG&E. To the extent that PG&E's bankruptcy filing affects the collectibility of the receivables from the CalPX and Cal ISO, the receivables from these entities are at greater risk.

Also in April 2001, the FERC issued an order stating that it was establishing price mitigation for sales in the California wholesale electricity market. Subsequently, in its June 19, 2001 Order, the FERC expanded that price mitigation plan to the entire western United States electrically interconnected system. That plan included the potential for orders directing electricity sellers into California since October 2, 2000 to refund portions of their sales prices if the FERC determined that those prices were not just and reasonable, and therefore not in compliance with the Federal Power Act. The June 19^thOrder also required all buyers and sellers in the Cal ISO market during the subject time-frame to participate in settlement discussions to explore the potential for resolution of these issues without further FERC action. The settlement discussions failed to bring resolution of the refund issue and as a result, the FERC Chief Judge submitted a Report and Recommendation to the FERC recommending that the FERC adopt the methodology set forth in the report and set for evidentiary hearing an analysis of the Cal ISO's and the CalPX's spot markets to determine what refunds may be due upon application of that methodology. The Judge recommended that the methodology should be applied to all sellers except those who at the evidentiary hearing are able to demonstrate that their costs exceed the results of the recommended methodology.

On July 25, 2001, the FERC issued an order establishing evidentiary hearing procedures related to the scope and methodology for calculating refunds related to transactions in the spot markets operated by the Cal ISO and the CalPX during the period October 2, 2000 through June 20, 2001. As to potential refunds, if any, we believe our exposure will be more than offset by amounts due from California entities.

In addition, the July 25, 2001 FERC order established another proceeding to explore whether there may have been unjust and unreasonable charges for spot market sales in the Pacific Northwest during the period December 25, 2000 through June 20, 2001. The FERC Administrative Law Judge (ALJ) submitted recommendations and findings to the FERC on September 24, 2001. The ALJ found that the prices were just and reasonable and therefore no refunds should be allowed. Procedurally, the ALJ's decision is a recommendation to the commissioners of the FERC. Multiple parties have filed requests for rehearing and petitions for review. The ALJ has re-established a procedural schedule which would result in findings of fact and recommended conclusions during August 2002; such schedule is subject to Commission review.

On May 8, 2002 the FERC issued a data request to all Sellers of Wholesale Electricity and/or Ancillary Services to the Cal ISO and/or the CalPX during the years 2000-2001. The request required IPC and IE to respond in the form of an affidavit to various trading practices that the FERC identified in its fact-finding investigation of Potential Manipulation of Electric and Natural Gas Prices in Docket No. PA02-2-000. IPC and IE filed a response on May 22, 2002. This response indicated that although they did export energy from the CalPX outside of California during the period 2000-2001, they did not engage in any trading strategy described in the Enron memoranda. The energy was resold to supply preexisting load obligations, to supply preexisting term transactions or to supply a contemporaneous sales transaction. The companies denied all other ten activities identified by the FERC. IPC and IE filed additional responses to the FERC on May 31 and June 5, 2002. In the May 31 response, the companies denied engaging in the activity referred to as "wash," "round trip" or "sell/buyback" trading involving the sale of an electricity product to another company together with a simultaneous purchase of the same product at the same price. In the June 5 response, where the data request was directed to all sellers of natural gas in the Western Systems Coordinating Council and/or Texas during the years 2000-2001, the companies denied engaging in the activity referred to as "wash," "round trip" or "sell/buyback" trading involving the sale of natural gas together with a simultaneous purchase of the same product at the same price.

IPC transferred its non-utility wholesale electricity marketing operations to IE on June 11, 2001. Effective with this transfer, the outstanding receivables and payables with the CalPX and Cal ISO were assigned from IPC to IE. At June 30, 2002, the CalPX and Cal ISO owed $13 million and $31 million, respectively, for energy sales made to them by IPC in November and December 2000. IE has accrued a reserve of $41 million against these receivables.

These reserves were calculated taking into account the uncertainty of collection, given the current California energy situation. Based on the reserves recorded as of June 30, 2002, IE believes that the future collectibility of these receivables or any potential refunds ordered by the FERC would not have a significant impact on its financial statements.

Nevada Power Company
In February and April of 2001 IE entered into several transactions under the Western Systems Power Pool (WSPP) Agreement whereby IE agreed to deliver to Nevada Power Company (NPC) 25 MW's during the third quarter of 2002. NPC agreed to pay IE $250 per MWH for heavy load deliveries and $155 per MWH for light load deliveries. Based upon the uncertain financial condition of NPC, IE asked for further assurances of NPC's ability to pay for the power if IE made the deliveries. NPC failed to provide appropriate credit assurances; therefore, in accordance with the WSPP Agreement procedures, IE terminated the transactions effective July 8, 2002.

Pursuant to the WSPP Agreement IE notified NPC of the liquidated damages amount and NPC responded with a letter which describes their view of rights under the WSPP Agreement and suggests a negotiated resolution. IE will continue to pursue its rights under the WSPP Agreement. At June 30, 2002, IE had a $5 million receivable related to the NPC claim. IE will review the recoverability of the asset on an ongoing basis.

6. REGULATORY ISSUES:

Deferred Power Supply Costs
Idaho: IPC has a Power Cost Adjustment (PCA) mechanism that provides for annual adjustments to the rates charged to Idaho retail customers. These adjustments, which typically take effect annually in May, are based on forecasts of net power supply expenses. During the year, the difference between 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.

On May 13, 2002, the Idaho Public Utility Commission (IPUC) issued Order No. 29026 related to the 2002-2003 PCA rate filing. The order granted recovery of $255 million of excess power supply costs, consisting of:

$209 million of voluntary load reduction and power supply costs incurred between March 1, 2001 and March 31, 2002.
$28 million of excess power supply costs forecasted for the period April 2002- March 2003.
$18 million of unamortized costs previously approved for recovery beginningOctober 1, 2001. The amount authorized in October 2001 totaled $49 million. This order spreads the October rate increase, which would have ended in September 2002, through May 2003.

The order also:

Denied recovery of $12 million of lost revenues resulting from the irrigation load reduction program, and $2 million of other costs IPC sought to recover.
Authorized recovery over a one-year period for all but $11.5 million of the $255 million of deferred costs. In June 2002, the IPUC issued Order No. 29065 deferring a portion of the May 16, 2002 PCA rate increase applied to certain industrial customers, deferring recovery of approximately $4 million. The remaining amounts will be recovered during the 2003-2004 PCA rate year, and IPC will earn a six percent carrying charge on the balance.
Denied IPC's request to issue $172 million in Energy Cost Recovery Bonds, which would have spread the recovery of that amount over three years.
Discontinued the Commission-required three-tiered rate structure for residential customers.
Authorized a separate annual surcharge to collect approximately $2.6 million annually to fund future conservation programs.

The IPUC had previously issued an order disallowing the lost revenue portion of the irrigation load reduction program. IPC believes that the Commission's order is inconsistent with an earlier order that allowed recovery of such costs and IPC filed a Petition for Reconsideration on May 2, 2002. The process IPC has embarked upon has a number of steps involved and could extend into the early fall. If IPC is unsuccessful in its efforts before the IPUC to overturn the denial, this amount will be written off in accordance with accounting principles generally accepted in the United States of America. If denied by the IPUC, the matter would then be appealed to the Idaho Supreme Court.

Oregon: IPC filed an application with the Oregon Public Utility Commission (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 less than $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.

IPC's deferred power supply costs consist of the following (in millions of dollars):

			June 30,		December 31,
			2002		2001

Oregon deferral			$	15	$	15

Idaho PCA current deferral:
	Deferral for 2001-2002 rate year			-		78
	Deferral for 2002-2003 rate year			(1)		-
	Irrigation load reduction program			12		70
	Astaris load reduction agreement			6		62
	Irrigation and small general service deferral for
		recovery in the 2003-2004 rate year		12		-

Idaho PCA true-up:
	Remaining true-up authorized October 2001			-		37
	Remaining true-up authorized May 2001			-		43
	Remaining true-up authorized May 2002			188		-

	Total deferral		$	232	$	305

FMC/Astaris Settlement Agreement
On January 8, 2002, the IPUC initiated an investigation to examine the load-reduction rates contained in the Voluntary Load Reduction (VLR) Agreement between IPC and FMC/Astaris. This VLR Agreement amended the Electric Service Agreement (ESA) that governs the delivery of electric service to FMC/Astaris' Pocatello plant. On June 6, 2002, IPC and FMC/Astaris signed and filed a proposed Stipulation and Settlement Agreement (Agreement) with the IPUC and on June 10, 2002, the IPUC approved the Agreement in Order No. 29050 which included the following provisions:

The VLR payments that IPC will make to FMC/Astaris through May 2003 were decreased $5 million, reducing IPC's overall payments to $37 million. Approximately 90 percent of this reduction will flow through the PCA mechanism as a reduction in costs to Idaho retail customers.
FMC/Astaris agreed to dismiss, with prejudice, a declaratory judgment action concerning the FMC/Astaris contract that it had previously filed against IPC in the Fourth Judicial District for the State of Idaho.
FMC/Astaris will pay IPC approximately $31 million through March 2003 to settle the ESA.

Garnet Power Purchase Agreement
IPC and Garnet Energy, LLC (Garnet), a subsidiary of Ida-West, had entered into a power purchase agreement (PPA) for IPC to purchase energy produced by Garnet's to-be-built natural gas generation facility. A hearing was scheduled for July 23, 2002 on IPC's application for an order approving the PPA and an accounting order authorizing the inclusion of power supply expenses associated with the purchase of capacity and energy from Garnet in the PCA.

Garnet informed IPC that there was a substantial likelihood that it would be unable to obtain the financing at acceptable terms necessary to construct the facility. Garnet has further advised IPC that there may be alternative financing arrangements that could allow Garnet to obtain financing within the constraints of the PPA. However, pursuing alternative financing arrangements will require additional time. As a result IPC sought a continuance in the hearing scheduled for July 23, 2002.

On July 24, 2002, the IPUC issued their ruling effectively closing the proceeding involving IPC's petition to enter into a PPA with Garnet. IPC was directed to return in 90 days with a report on (1) the status of Garnet's progress in obtaining financing for the project and (2) how IPC proposes to meet future power requirements if Garnet is not built.

Application to Defer Extraordinary Costs Associated With Security Measures
In November 2001, IPC filed an application requesting the IPUC to issue an accounting order authorizing IPC to defer its extraordinary costs associated with increased security measures subsequent to the events of September 11, 2001. The additional or extraordinary security measures are needed to help ensure the safety of IPC employees and to protect company facilities. At June 30, 2002, IPC had deferred $1 million of extraordinary security costs. In March 2002 the IPUC issued Order No. 28975 directing the following related to these costs:

Costs in excess of $11,000 per month are to be deferred in a regulatory asset account.
Such costs incurred in 2001 are to be amortized over a five-year period beginning in January 2003. Costs deferred in each subsequent year are to be amortized beginning in January of the next calendar year.
Deferred costs are to receive the appropriate carrying charge.
Costs are to be allocated among IPC's various jurisdictions and affiliates.
The IPUC defers making a final decision regarding final allocation of deferred security expenses to other affiliates and sharing with shareholders until such time as the IPUC conducts its prudence review of the expenses.

IDACORP Energy and Idaho Power Company Agreement
IPC entered into an Electricity Supply Management Services Agreement (Agreement) with IE in June 2001. The IPUC is currently assessing issues associated with this Agreement. While some of the issues likely became moot with the decision to wind down IE's trading operation, the IPUC staff has indicated its desire to continue to review whether adequate compensation has been provided to IPC customers as a result of transactions between IE and IPC after February 2001. Similar issues arising prior to February 2001 were resolved by IPUC Order No. 28852.

7. DERIVATIVE FINANCIAL INSTRUMENTS:

Energy Trading Contracts
The following table details the gross margin for the energy marketing operations for the three and six months ended June 30 (in millions of dollars):

			Three months ended				Six months ended
			June 30,				June 30,
			2002		2001		2002		2001
Gross Margin:
	Realized or otherwise settled		$	22	$	35	$	52	$	33
	Unrealized (loss) gain			(37)		26		(58)		101
		Total	$	(15)	$	61	$	(6)	$	134

8. INDUSTRY SEGMENT INFORMATION:

We have identified two reportable operating segments, Utility Operations and Energy Marketing.

The following table summarizes the segment information for our utility and energy marketing segments and the total of all other segments, and reconciles this information to total enterprise amounts.

		Utility		Energy									Consolidated
		Operations		Marketing		Other				Eliminations			Total
		(millions of dollars)
Three months ended June 30, 2002
	Revenues	$	203	$	408		$	4	$		-	$		615
	Intersegment revenues		6		7			-			(7)			6
	Net income (loss)		13		(12)			2			-			3

Total assets at June 30, 2002		$	2,717	$	539		$	233	$		(110)	$		3,379

Three months ended June 30, 2001
	Revenues	$	175	$	1,347		$	3	$		-	$		1,525
	Intersegment revenues		53		36			-			(36)			53
	Net income (loss)		6		31			(1)			-			36

Total assets at December 31, 2001		$	2,860	$	718		$	205	$		(141)	$		3,642

Six months ended June 30, 2002
	Revenues	$	405	$	843		$	8	$		-	$		1,256
	Intersegment revenues		19		9			-			(10)			18
	Net income (loss)		34		(8)			2			-			28

Six months ended June 30, 2001
	Revenues	$	352	$	2,277		$	6	$		-	$		2,635
	Intersegment revenues		76		145			-			(145)			76
	Net income (loss)		20		54			(3)			-			71

Certain intersegment revenues from Utility Operations to Energy Marketing are not eliminated because they are included in the regulatory cost mechanism for IPC.

INDEPENDENT ACCOUNTANTS' REPORT

IDACORP, Inc.
Boise, Idaho

We have reviewed the accompanying consolidated balance sheet of IDACORP, Inc. and subsidiaries as of June 30, 2002, and the related consolidated statements of income and comprehensive income for the three and six month periods ended June 30, 2002 and 2001 and consolidated statements of cash flows for the six month periods ended June 30, 2002 and 2001. These financial statements are the responsibility of the Company's management.

We conducted our review in accordance with standards established by the American Institute of Certified Public Accountants. A review of interim financial information consists principally of applying analytical procedures to financial data and of making inquiries of persons responsible for financial and accounting matters. It is substantially less in scope than an audit conducted in accordance with auditing standards generally accepted in the United States of America, the objective of which is the expression of an opinion regarding the financial statements taken as a whole. Accordingly, we do not express such an opinion.

Based on our review, we are not aware of any material modifications that should be made to such consolidated financial statements for them to be in conformity with accounting principles generally accepted in the United States of America.

We have previously audited, in accordance with auditing standards generally accepted in the United States of America, the consolidated balance sheet of IDACORP, Inc. and subsidiaries as of December 31, 2001, and the related consolidated statements of income, comprehensive income, shareholders' equity, and cash flows for the year then ended (not presented herein); and in our report dated January 31, 2002, we expressed an unqualified opinion on those consolidated financial statements. In our opinion, the information set forth in the accompanying consolidated balance sheet as of December 31, 2001 is fairly stated, in all material respects, in relation to the consolidated balance sheet from which it has been derived.

DELOITTE & TOUCHE LLP
Boise, Idaho
July 29, 2002

Item 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

(Dollars in millions, except per share amounts. Megawatt hours (MWH) in thousands.)

INTRODUCTION:

In Management's Discussion and Analysis (MD&A) we explain the general financial condition and results of operations for IDACORP, Inc. (IDACORP) and subsidiaries. IDACORP is a holding company formed in 1998 as the parent of Idaho Power Company (IPC), IDACORP Energy (IE), and several other entities.

IPC is an electric utility with a service territory covering over 20,000 square miles 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.

IE markets electricity and natural gas and offers risk management and asset optimization services to wholesale customers in 31 states and two Canadian provinces.

IDACORP's other significant operating subsidiaries are:

Ida-West Energy (Ida-West) - independent power projects development and management;
IdaTech - developer of integrated fuel cell systems;
IDACORP Financial Services (IFS) - affordable housing and other real estate investments;
Velocitus - commercial and residential Internet service provider;
IDACOMM - provider of telecommunications services.

References in this report to "we" and "our" are to IDACORP, Inc. and its subsidiaries.

This MD&A should be read in conjunction with the accompanying consolidated financial statements. This discussion updates our MD&A included in our Annual Report on Form 10-K for the year ended December 31, 2001, and should be read in conjunction with the discussion in the annual report.

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 us or on our behalf in this 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 Utility Commission (IPUC) and the Oregon Public Utility Commission (OPUC), with respect to allowed rates of return, industry and rate structure, acquisition and disposal of assets and facilities, operations and construction of plant facilities, recovery of purchased power and other capital investments, present or prospective wholesale and retail competition (including but not limited to retail wheeling and transmission costs) and other refund proceedings;
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 interest rates or in rates of inflation;
exposure to market and credit risk in our energy trading and marketing operations;
changes in project costs;
unanticipated changes in operating expenses and capital expenditures;
capital market conditions;
rating actions by Moody's, Standard & Poor's (S&P) and Fitch IBCA (Fitch);
competition for new energy development opportunities; and
legal and administrative proceedings (whether civil or criminal) and settlements that influence our business and profitability;
new accounting or Securities and Exchange Commission requirements, or new interpretation or application of existing requirements.

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 the factors that affected our earnings, beginning with a general overview, then discussing results for each of our operating segments for the three and six months ended June 30:

			Three Months Ended				Six Months Ended
			June 30,				June 30,
			2002		2001		2002		2001
Earnings per share of common stock
	Electric utility		$	0.33	$	0.16	$	0.91	$	0.53
	Energy marketing			(0.32)		0.83		(0.21)		1.44
	Other			0.07		(0.03)		0.04		(0.08)
		Total	$	0.08	$	0.96	$	0.74	$	1.89

Earnings per share (EPS) from utility operations increased $0.17 and $0.38 for the three and six months ended June 30, 2002 compared to 2001.

The three months increase in utility operations is due to a $23 million decrease in operation expenses offset by a $19 million decrease in revenue. The decrease in utility revenues is due to decreased off-system sales of $48 million offset by increased general business revenues of $32 million. The decrease in operating expenses is attributed to decreased purchased power of $138 million offset by increased Power Cost Adjustment (PCA) expense component of $110 million.

The six months increase in utility operations is due to a decrease of $22 million in operating expenses offset by a $5 million decrease in revenues. The decrease in operating expenses is attributed to decreased purchased power of $234 million offset by the increased PCA expense component of $202 million. The decreased revenue is due to a $6 million decrease in other transmission revenues and decreased off-system sales of $83 million offset by an $84 million increase in general business revenues.

EPS from energy marketing activities decreased $1.15 and $1.65 for the three and six months ended June 30, 2002. Last year's results were driven by high prices, extreme volatility and wide regional price spreads. The decline in regional price spreads and volatility, combined with the decreasing number of creditworthy counterparties, has limited our ability to match the results of past quarters.

EPS from our other businesses improved for the three and six months ended June 30, 2002 due primarily to increases at IFS of $0.03 and $0.04 and at our growth subsidiaries, IDACOMM and IdaTech, of $0.02 and $0.04. These increases were offset by a decline at Ida-West of $0.03 and $0.05 for the three and six months ended June 30, 2002. The remaining change represents an adjustment to income tax expense at IDACORP to reflect an expected full year effective tax rate of zero.

On July 12, 2002 IPC customers set a record for power use-2,963 megawatts (MW). The previous record, 2,919 MW, was set on July 12, 2000.

Utility Operations
This section discusses IPC's utility operations, which are subject to regulation by, among others, the state regulatory commissions of Idaho and Oregon, and the FERC.

General Business Revenue
The following table presents IPC's general business revenue and MWH sales for the three and six months ended June 30:

		Three Months Ended June 30,						Six Months Ended June 30,
		Revenue				MWH		Revenue				MWH
		2002		2001		2002	2001	2002		2001		2002	2001

Residential		$	61	$	50	887	834	$	155	$	120	2,244	2,184
Commercial			48		39	838	809		96		72	1,714	1,643
Industrial			44		38	790	998		87		68	1,564	2,062
Irrigation			35		29	666	571		35		29	669	573
	Total	$	188	$	156	3,181	3,212	$	373	$	289	6,191	6,462

IPC's general business revenue is dependent on many factors, including the number of customers served, the rates charged and economic and weather conditions. The change in revenues in 2002 is due primarily to the following:

The annual PCA resulted in increased revenues of approximately $30 million and $90 million for the three and six months ended June 30, 2002. The PCA is discussed in more detail below in "Regulatory Issues."
Population growth in IPC's service territory increased approximately two percent, resulting in a $2 million increase in revenues for the three and six months ended June 30, 2002.
FMC/Astaris, previously IPC's largest volume customer, closed its manufacturing plants late in 2001. However, based on a take or pay contract with FMC/Astaris which requires payment for power regardless of delivery, IPC has continued to receive payments from FMC/Astaris since their plant closures. Accordingly, IPC shows a significant decrease in usage of $9 million and $17 million offset by increased price variances of $9 million and $19 million. The net effect is an increase of less than $1 million for the three months ended June 30, 2002 and a net increase of $2 million for the six months ended June 30,2002.
Usage and weather factors decreased revenues $1 million and $8 million for the three and six months ended June 30, 2002. As discussed above, FMC/Astaris usage decreased revenues $9 million and $17 million for the three and six months ended June 30, 2002. This decrease was offset by increased usage in our other customer classes due to an increase in cooling degree days of approximately 15 percent. Cooling degree days are a common measure used in the utility industry to analyze demand.

Off-system sales
Off-system sales consist primarily of sales of surplus system energy when available, and long-term sales contracts. Revenues decreased for the three and six months ended June 30, 2002 due primarily to lower wholesale electricity prices. The following table presents IPC's off-system sales for the three and six months ended June 30:

	Three Months Ended				Six Months Ended
	June 30,				June 30,
	2002		2001		2002		2001

Off-system sales	$	11	$	59	$	31	$	114
MWHs		431		535		1,253		1,030
Revenue per MWH	$	25.47	$	109.63	$	24.85	$	110.59

Purchased power
The decrease in purchased power is due to the reduced wholesale electricity prices and IPC's decreased need for wholesale electricity. Load reduction program costs are also included in purchased power for the three and six months ended June 30, 2002 and 2001. The following table presents IPC's purchased power expenses for the three and six months ended June 30:

		Three Months Ended				Six Months Ended
		June 30,				June 30,
		2002		2001		2002		2001
Purchased Power:
	Purchases	$	23	$	131	$	36	$	257
	Program costs		8		38		25		38

MWHs			821		869		1,301		1,442
Cost per MWH		$	28.44	$	151.69	$	28.06	$	178.27

Fuel expense
Fuel expense for the three months ended June 30, 2002 was substantially unchanged as decreased generation was offset by increased coal prices. Fuel expenses increased $3 million for the six months ended June 30, 2002 due to increased coal prices and the use of the new Danskin natural gas-fired plant, offset by decreased generation at the coal-fired plants. The following table presents IPC's fuel expense for the three and six months ended June 30:

	Three Months Ended				Six Months Ended
	June 30,				June 30,
	2002		2001		2002		2001

Fuel expense	$	22	$	22	$	50	$	47
Thermal MWHs generated		1,492		1,697		3,413		3,648

PCA
The PCA expense component is related to IPC's PCA regulatory mechanism. In 2001, actual power supply costs were significantly greater than forecasted, resulting in a large PCA credit, which is now being recovered in rates (as revenues) and the deferred balance is being amortized as PCA expense. FMC/Astaris and irrigation program cost deferrals also affect the PCA. The PCA is discussed in more detail below in "Regulatory Issues."

The following table presents the components of PCA expense for the three and six months ended June 30:

		Three Months Ended				Six Months Ended
		June 30,				June 30,
		2002		2001		2002		2001

Current year power supply costs accrual (deferral)		$	1	$	(54)	$	5	$	(111)
Astaris and irrigation program costs (deferral)			(6)		(33)		(19)		(33)
Amortization of prior year authorized balances			46		19		89		18
Write-off of disallowed costs			1		-		1		-
	Total power cost adjustment	$	42	$	(68)	$	76	$	(126)

Energy Marketing
The following table presents our energy marketing operations (including intersegment transactions) for the three and six months ended June 30:

			Three Months Ended				Six Months Ended
			June 30,				June 30,
			2002		2001		2002		2001

Operating revenues:
	Electricity		$	377	$	1,250	$	778	$	2,178
	Gas			38		133		74		243
		Total	$	415	$	1,383	$	852	$	2,421

Settled volumes:
	Electricity (MWH's)			13,523		6,888		26,521		13,197
	Gas (mmbtu's in thousands)			11,707		31,344		23,881		48,727

Operating expenses:
	Electricity		$	397	$	1,199	$	794	$	2,091
	Gas			39		132		72		240
		Total	$	436	$	1,331	$	866	$	2,331

The decreases in operating revenues, operating expenses and earnings are due to the dramatic decline in regional price per MWH, pricing spreads and volatility. Additionally, unrealized revenues have declined as a result of a reduction in the valuation of certain forward positions due to the continued deterioration of credit quality in the industry. Despite this decrease in revenue, our settled physical power sales have increased 101 percent over the first six months of 2001 and 96 percent over the second quarter of 2001. Our average price per settled MWH sold decreased from $159 in the first six months of 2001 to $31 in the first six months of 2002 and from $181 in the three months ended June 30, 2001 to $30 in the three months ended June 30, 2002. Basis spreads between regions continue to be much lower than last year with volatility of prices being nearly half what it was a year ago. Our trading and marketing portfolio is impacted primarily by regional price spreads and volatility and, with the reduction in both, we have seen a corresponding drop in earnings.

We measure our sensitivity to commodity price risk using a value-at-risk (VaR) measure. This methodology computes VaR based upon market prices for futures and option-implied volatilities as of June 30, 2002. Our average VaR for the quarter was $1.5 million, peaking at $2.5 million. As of June 30, 2002 it was $1.1 million. Our VaR measure is calculated by application of a variance/covariance methodology - assuming a 95 percent confidence level and a one-day holding period. Daily backtesting ensures that VaR measures produced by the model are in line with actual historical results.

The VaR is understood to be a statistical calculation of potential loss and not a forecast of expected loss and, as such, is not guaranteed to occur. The confidence level and holding period imply that, at June 30, 2002, there is a five percent chance that the daily loss could exceed $1.1 million.

Contracts Accounted for at Fair Value
When determining the fair value of our marketing and trading contracts, we use actively quoted prices for contracts with similar terms as the quoted price, including specific delivery points and maturities. To determine fair value of contracts with terms that are not consistent with actively quoted prices, we use (when available) prices provided by other external sources. When prices from external sources are not available, we determine prices by using internal pricing models that incorporate available current and historical pricing information. Finally, we adjust the fair market value of our contracts for the impact of market depth and liquidity, potential model error, and expected credit losses at the counterparty level.

The following table details the gross margin for the energy marketing operations for the three and six months ended June 30:

			Three Months Ended				Six Months Ended
			June 30,				June 30,
			2002		2001		2002		2001
Gross Margin:
	Realized or otherwise settled		$	22	$	35	$	52	$	33
	Unrealized (loss) gain			(37)		26		(58)		101
		Total	$	(15)	$	61	$	(6)	$	134

At June 30, 2002, 53 percent of the credit exposure related to our unrealized position is with investment grade counterparties. Less than five percent is with non-investment grade counterparties. The remaining 42 percent of credit exposure is with non-rated counterparties. The majority of the non-rated entities are municipalities, public utility districts and electric cooperatives.

The change in net fair value (energy marketing assets less energy marketing liabilities) between year-end 2001 and June 30, 2002 is explained as follows:

Net fair value of contracts outstanding as of 12/31/2001		$	138
Contracts realized or otherwise settled during the period			(52)
Net fair value of new contracts when entered into during the period			3
Changes in net fair value attributable to market prices and other market changes			(18)
	Net fair value of contracts outstanding as of 6/30/2002	$	71

Changes in net fair value attributable to market prices and other market changes include:

Changes in value due to changes in actively quoted prices;
Changes in value due to changes in prices provided by other external sources;
Changes in value due to changes in prices derived by models or other methods;
Changes in price basis between liquid and illiquid points. Some price bases between points are easily determined in the market, some are derived by analyzing other market data;
Changes in implied volatility and price correlations;
Changes in liquidity at various delivery points that are driven by changes in market conditions;
Changes in discounts related to counterparty creditworthiness.

Net fair value at June 30, 2002 disaggregated by source of fair value and maturity of contracts:

			Maturity						Maturity
			less than		Maturity		Maturity		in excess of
Source of Fair Value			1 year		1-3 years		4-5 years		5 years		Total

Prices actively quoted			$	4	$	51	$	3	$	-	$	58
Prices provided by other
	external sources			(17)		22		2		13		20
Prices based on models
	and other valuation
	methods			(1)		(7)		1		-		(7)
		Total	$	(14)	$	66	$	6	$	13	$	71

Prices actively quoted are quoted daily by brokers and trading exchanges such as NYMEX, TFS, Intercontinental, and Bloomberg. The time horizon is July 2002 through June 2007. Products include physical, financial, swap, interest rate, index and basis for both natural gas and heavy load power.

Prices provided by other external sources are quoted periodically by brokers and trading exchanges such as TFS, APB, Prebon, Intercontinental, and Bloomberg. The time horizon is July 2002 through December 2010. Products include physical, financial, swap, index and basis for both natural gas and heavy and light load power.

Prices derived from models and other valuation methods incorporate available current and historical pricing information. The time horizon is July 2002 through December 2009. Products include transmission, options and ancillary services related to heavy and light load power.

Other Segment Operations
Our other operations include the results of operations of IDACORP's diversified subsidiaries, including Ida-West, IdaTech, IFS, Velocitus and IDACOMM. Other operating revenues and expenses did not differ materially from the three and six months ended June 30, 2001.

Income Taxes
Income taxes decreased for the three and six months ended June 30, 2002 due primarily to the decreases in net income before taxes and tax credits from affordable housing projects. An adjustment has been recorded to income tax expense to reflect an expected full year effective tax rate of zero.

LIQUIDITY AND CAPITAL RESOURCES:

Cash Flow
Our net cash provided by operations totaled $125 million for the six months ended June 30, 2002. Significant factors affecting cash flows in 2002 include:

the receipt of a $54 million income tax refund related to net operating loss carrybacks associated with 2001 power supply costs, offset by tax payments of $27 million;
the recovery through the PCA of power supply costs incurred in 2000 and 2001;
reduction in accounts payable of $122 million.

We anticipate that our cash flows from operations will continue to be positively affected as we recover the remaining balance of the 2002 PCA. We discuss the PCA in the section "Regulatory Issues" below.

Working Capital
The changes in customer receivables and accounts payable are attributed primarily to lower prices on settled energy trading contracts. Accounts payable also decreased due to timing and normal business activity.

Energy marketing assets and liabilities represent the fair value of energy marketing contracts. The fair value of these contracts is unrealized and therefore does not necessarily indicate a current source or use of funds. The decreases in energy marketing assets and liabilities from December 31, 2001 to June 30, 2002 is primarily a reflection of lower market prices at June 30, 2002.

The remaining changes in working capital are attributed to timing and normal business activity.

Cash Expenditures
We forecast that internal cash generation after dividends will provide approximately 80 percent of total capital requirements in 2002 and 100 percent during the two-year period 2003-2004. We expect to finance our utility construction programs and other capital requirements with both internally generated funds and, to the extent necessary, externally financed capital.

We have targeted a reduction in our capital-spending program of between 10 percent and 20 percent of our overall $200 million capital budget. Emphasis will be in the areas of nonessential expenditures that will not negatively impact our customers or reliability of our systems.

Financing Program
Credit facilities have been established at both IPC and IDACORP. IDACORP has a $140 million three-year credit facility that expires in March 2005, and a $350 million 364-day credit facility that expires in March 2003. Under these facilities, IDACORP pays a facility fee on the commitment, quarterly in arrears, based on its corporate credit rating. Commercial paper may be issued up to the amounts supported by the credit facilities. At June 30, 2002, short-term borrowing on these facilities totaled $170 million.

IPC has regulatory authority to incur up to $350 million of short-term indebtedness. This amount will increase to $400 million from September 1, 2002 to October 15, 2002. IPC has a $200 million 364-day revolving credit facility that expires in March 2003, under which it pays a facility fee on the commitment quarterly in arrears, based on its corporate credit rating. Commercial paper may be issued subject to the regulatory maximum, up to the amount supported by the credit facilities. At June 30, 2002, IPC's short term borrowing under this facility totaled $140 million. IPC also has $100 million of floating rate notes outstanding, payable on September 1, 2002. IPC is in the process of replacing these notes with comparable financing with a due date of approximately September 2003.

IPC currently has a $200 million shelf registration that can be used for first mortgage bonds, including medium-term notes, unsecured debt or preferred stock. At June 30, 2002 none had been issued.

In March 2002, $50 million First Mortgage Bonds 8.75% Series due 2027 were redeemed using short-term borrowings.

IPC is planning to redeem its auction rate preferred stock on August 15, 2002 for $50 million. This redemption will be financed with internally generated funds or short-term borrowings.

We have been considering the issuance of equity or equity linked securities. We are currently reviewing this in light of the decision to wind down our wholesale power marketing function. We are reviewing options to balance our capital structure while minimizing the need for new equity.

Credit Rating
On March 25, 2002, S&P lowered its Corporate Credit Rating on IDACORP and IPC from "A+" (negative outlook) to "A-" (negative outlook). S&P cited increasing business risk combined with a financial profile that is weak for the rating. The increased business risk at IDACORP is the result of the rapid growth of non-regulated trading and marketing activities. The financial profile has been considerably weakened by the accumulation of deferred power costs incurred during 2001. S&P also stated that more stringent financial benchmarks are now expected at any given rating level to compensate for the increased business risk of the trading and marketing operation.

On May 16, 2002, Fitch lowered its ratings on IDACORP and IPC securities. Fitch stated that the new ratings better reflect the earnings and cash flow volatility experienced by IPC during the recent drought and the higher business risk associated with IDACORP's unregulated business strategy, especially the expansion of IE beyond its current western U.S. focus. Fitch stated that the new ratings reflect the May 13, 2002 PCA order of the IPUC. Fitch also initiated coverage of IPC commercial paper with an F1 rating. The rating outlook for both companies is stable.

These downgrades are expected to increase our future cost of debt and other securities.

On June 27, 2002, S&P revised its outlook to positive from negative to reflect our decision to wind down the power marketing business at IE. On August 1, 2002 S&P said that our decision to review financing options on the Garnet project will not affect our rating or outlook.

The following outlines the former and current S&P and Fitch rating of IDACORP's and IPC's securities:

		S & P
		From	To
IDACORP
	Corporate Credit Rating	A+	A-
	Senior Unsecured	A	BBB+
	Commercial Paper	A-1	A-2

Idaho Power Company
	Corporate Credit Rating	A+	A-
	Senior Unsecured	A	BBB+
	Senior Secured	AA-	A
	Preferred Stock	A-	BBB
	Commercial Paper	A-1	A-2

		Fitch
		From	To
IDACORP
	Senior Unsecured	A-	BBB+
	Trust Preferred Shelf	BBB+	BBB
	Commercial Paper	F-1	F-2

Idaho Power Company
	First Mortgage Bonds	A+	A
	Senior Unsecured	A	A-
	Preferred Stock	A	BBB+
	Commercial Paper	-	F1

Some collateral agreements in place between IE and its counterparties include provisions requiring additional margining in the event of a credit rating downgrade. IDACORP's downgrade did not impact the liquidity required at IE. In general, credit rating changes within the investment grade category should not materially impact the liquidity or financial condition of IDACORP. A credit downgrade below an investment grade rating could result in additional margin calls that could have a material negative impact on the liquidity of IDACORP. IDACORP believes its existing credit facilities are adequate to fund these potential liquidity requirements.

OTHER MATTERS:

Regulatory Issues

Deferred Power Supply Costs
Idaho: IPC has a PCA mechanism that provides for annual adjustments to the rates charged to Idaho retail customers. These adjustments, which typically take effect annually in May, are based on forecasts of net power supply expenses. During the year, the difference between 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.

On May 13, 2002, the IPUC issued Order No. 29026 related to the 2002-2003 PCA rate filing. The order granted recovery of $255 million of excess power supply costs, consisting of:

$209 million of voluntary load reduction and power supply costs incurred between March 1, 2001 and March 31, 2002.
$28 million of excess power supply costs forecasted for the period April 2002- March 2003.
$18 million of unamortized costs previously approved for recovery beginningOctober 1, 2001. The amount authorized in October 2001 totaled $49 million. This order spreads the October rate increase, which would have ended in September 2002, through May 2003.

The order also:

Denied recovery of $12 million of lost revenues resulting from the irrigation load reduction program, and $2 million of other costs IPC sought to recover.
Authorized recovery over a one-year period for all but $11.5 million of the $255 million of deferred costs. In June 2002, the IPUC issued Order No. 29065 deferring a portion of the May 16, 2002 PCA rate increase applied to certain industrial customers, deferring recovery of approximately $4 million. The remaining amounts will be recovered during the 2003-2004 PCA rate year, and IPC will earn a six percent carrying charge on the balance.
Denied IPC's request to issue $172 million in Energy Cost Recovery Bonds, which would have spread the recovery of that amount over three years.
Discontinued the Commission-required three-tiered rate structure for residential customers.
Authorized a separate annual surcharge to collect approximately $2.6 million annually to fund future conservation programs.

Oregon: 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 less than $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.

IPC's deferred power supply costs consist of the following:

			June 30,		December 31,
			2002		2001

Oregon deferral			$	15	$	15

Idaho PCA current deferral:
	Deferral for 2001-2002 rate year			-		78
	Deferral for 2002-2003 rate year			(1)		-
	Irrigation load reduction program			12		70
	Astaris load reduction agreement			6		62
	Irrigation and small general service deferral for
		recovery in the 2003-2004 rate year		12		-

Idaho PCA true-up:
	Remaining true-up authorized October 2001			-		37
	Remaining true-up authorized May 2001			-		43
	Remaining true-up authorized May 2002			188		-

	Total deferral		$	232	$	305

The VLR payments that IPC will make to FMC/Astaris through May 2003 were decreased $5 million, reducing IPC's overall payments to $37 million. Approximately 90 percent of this reduction will flow through the PCA mechanism as a reduction in costs to Idaho retail customers.
FMC/Astaris agreed to dismiss, with prejudice, a declaratory judgment action concerning the FMC/Astaris contract that it had previously filed against IPC in the Fourth Judicial District for the State of Idaho.
FMC/Astaris will pay IPC approximately $31 million through March 2003 to settle the ESA.

Garnet informed IPC that there was a substantial likelihood that it would be unable to obtain the financing at acceptable terms necessary to construct the facility. Garnet has further advised IPC that there may be alternative financing arrangements that could allow Garnet to obtain financing within the constraints of the PPA. However, pursuing alternative financing arrangements will require additional time. As a result, IPC sought a continuance in the hearing scheduled for July 23, 2002.

Costs in excess of $11,000 per month are to be deferred in a regulatory asset account.
Such costs incurred in 2001 are to be amortized over a five-year period beginning in January 2003. Costs deferred in each subsequent year are to be amortized beginning in January of the next calendar year.
Deferred costs are to receive the appropriate carrying charge.
Costs are to be allocated among IPC's various jurisdictions and affiliates.
The IPUC defers making a final decision regarding final allocation of deferred security expenses to other affiliates and sharing with shareholders until such time as the IPUC conducts its prudence review of the expenses.

Overton Power District No. 5
IE filed a lawsuit on November 30, 2001 in Idaho State District Court in and for the County of Ada against Overton Power District No. 5, a Nevada electric improvement district, for failure to meet payment obligations under a power contract. The contract provided for Overton to purchase 40 MW of electrical energy per hour from IE at $88.50 per MWH, from July 1, 2001 through June 30, 2011. In the contract, Overton agreed to raise its rates to its customers to the extent necessary to make its payment obligations to IE under the contract.

On July 23, 2002, Truckee filed a complaint against IPC, IE and IDACORP with the FERC seeking relief under its long-term power contract for the purchase of wholesale electric power from IPC and IE.

On May 8, 2002 the FERC issued a data request to all Sellers of Wholesale Electricity and/or Ancillary Services to the Cal ISO and/or the CalPX during the years 2000-2001. The request required IPC and IE to respond in the form of an affidavit to various trading practices that the FERC identified in its fact-finding investigation of Potential Manipulation of Electric and Natural Gas Prices in Docket No. PA02-2-000. IPC and IE filed a response on May 22, 2002. This response indicated that although they did export energy from the CalPX outside of California during the period 2000-2001, they did not engage in any trading strategy described in the Enron memoranda. The energy was resold to supply preexisting load obligations, to supply preexisting term transactions or to supply a contemporaneous sales transaction. The companies denied all other ten activities identified by the FERC. IPC and IE filed additional responses with the FERC on May 31 and June 5, 2002. In the May 31 response, the companies denied engaging in the activity referred to as "wash," "round trip" or "sell/buyback" trading involving the sale of an electricity product to another company together with a simultaneous purchase of the same product at the same price. In the June 5 response, where the data request was directed to all sellers of natural gas in the Western Systems Coordinating Council and/or Texas during the years 2000-2001, the companies denied engaging in the activity referred to as "wash," "round trip" or "sell/buyback" trading involving the sale of natural gas together with a simultaneous purchase of the same product at the same price.

Power supply
We monitor the effect of streamflow conditions on Brownlee Reservoir, the water source for our three Hells Canyon hydroelectric facilities and IPC's key water storage facility. In a typical year, these three projects combine to produce about half of our generated electricity. Inflows into Brownlee result from a combination of precipitation, storage and ground water conditions.

The National Weather Service River Forecast Center has reported that the April-July 2002 inflow into Brownlee Reservoir was 3.24 million acre-feet (maf). Average inflow into the reservoir is 6.3 maf. Inflow into Brownlee Reservoir impacts IPC's ability to produce low-cost hydropower.

Hydro generation on IPC's system increased eight percent for the three months ended and 21 percent for the six months ended June 30, 2002, but is still below normal.

We expect 2002 hydro generation to be improved over last year, but remain below normal. Below normal conditions necessitate the use of higher-cost power from coal-fired and natural gas-fired plants and wholesale purchases.

Integrated Resource Plan
Every two years, IPC is required to file with the IPUC and OPUC an Integrated Resource Plan (IRP), a comprehensive look at IPC's present and future demands for electricity and plans for meeting that demand. The 2002 IRP identified the need for additional resources to address potential electricity shortfalls within our utility service territory by mid-2005. The new resources to be in place at that time were the previously identified 273-MW power purchase agreement from the Garnet facility, an additional 100 MW generation resource to be determined, and a 100 MW transmission upgrade to increase import capability. These resources would all be necessary to satisfy energy demand during IPC's peak periods. Prior to 2005, IPC will continue to use purchases from the Northwest energy markets as necessary to meet short-term energy needs.

As discussed earlier in "Garnet Power Purchase Agreement," Garnet's ability to finance and construct its facility is in question, and IPC is preparing a report for the IPUC on how it proposes to meet future power requirements if Garnet is not constructed.

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 hydro projects will have expired. IPC is actively pursuing the relicensing of these projects, a process that will continue for the next 10 to 15 years. The first applications for license renewal were submitted to the FERC in December 1995. IPC has filed applications seeking renewal of licenses for the Bliss, Upper Salmon Falls, Lower Salmon Falls, CJ Strike, Shoshone Falls and Upper and Lower Malad Hydroelectric Projects. The licenses for the Hells Canyon Complex (Brownlee, Oxbow and Hells Canyon dams) expire in 2005, and the Swan Falls Project in 2010. IPC is 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, IPC anticipates that it will relicense each of the 10 facilities. At this point, however, it cannot be predicted what type of environmental or operational requirements may be faced, nor can it be estimated the cost of license renewal. At June 30, 2002, $45 million of relicensing costs were included in Construction Work in Progress.

The most significant relicensing effort is the Hells Canyon Complex, which provides 68 percent of IPC's hydro generation capacity and 41 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.

FERC Notice of Proposed Rulemaking
In July 2002 the FERC issued a Notice of Proposed Rulemaking (NOPR) on Standard Market Design. IPC is currently reviewing the NOPR, but at this time it is too early to assess what impact the NOPR, if implemented, would have on its operations.

Business Strategy
IE is focused on growing the natural gas side of its business and is exploring the possibility of buying natural gas processing, gathering, intra-state pipeline and storage facility assets initially in geographic areas stretching from North Dakota to west Texas. These assets would be under contract for IE to provide primarily fee-based services and other value-added commodity services to producers and users of natural gas.

Board of Directors
Roger L. Breezley has resigned from the Board of Directors effective June 30, 2002 for health reasons. Mr. Breezley has served as a Director of IPC since 1993 and IDACORP since 1998.

New Accounting Pronouncements
In August 2001, the Financial Accounting Standards Board (FASB) issued Statement of Financial Accounting Standards (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. We are currently assessing, but have not yet determined, the impact of SFAS 143 on our financial statements.

Item 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Our market risks related to commodity prices is included in Item 2 "Management's Discussion and Analysis of Financial Condition and Results of Operations" under "Energy Marketing".

Our market risks related to interest rates and foreign currency have not changed materially from those reported in our Annual Report on Form 10-K for the year ended December 31, 2001.

PART II - OTHER INFORMATION

Item 1. Legal Proceedings

Overton Power District No. 5
IE filed a lawsuit on November 30, 2001 in Idaho State District Court in and for the County of Ada against Overton Power District No. 5, a Nevada electric improvement district, for failure to meet payment obligations under a power contract. The contract provided for Overton to purchase 40 megawatts of electrical energy per hour from IE at $88.50 per megawatt hour, from July 1, 2001 through June 30, 2011. In the contract, Overton agreed to raise its rates to its customers to the extent necessary to make its payment obligations to IE under the contract.

IE believes that Overton's actions constitute a breach of the contract and intends to vigorously prosecute this lawsuit. While the outcome of litigation is never certain, IE believes it should prevail on the merits. At June 30, 2002, the Company had a $74 million long-term asset related to the Overton claim. IE will review the recoverability of the asset on an ongoing basis.

Truckee-Donner Public Utility District
IE has received notice from Truckee-Donner Public Utility District (Truckee) located in the State of California, asserting that IE was in purported breach of, and that Truckee has the right to renegotiate certain terms of, the Agreement for the Sale and Purchase of Firm Capacity and Energy in place between the two entities. Generally, the terms of the contract provide for IE to sell to Truckee 10 MW light load energy and 20 MW heavy load energy for the term January 1, 2002 through December 31, 2002 at $72 per MWh and 25 MW flat energy for the term January 1, 2003 through December 31, 2009 at $72 per MWh. While IE believes there are no grounds for dispute under the contract, IE has agreed to informally negotiate with Truckee on the issues in an effort to resolve the matter.

Item 2. Changes in Securities and Use of Proceeds

As part of their compensation, directors of IDACORP, Inc. who are not employees received a grant of common stock equal to $8,000 on July 17, 2002. The stock was issued without registration under the Securities Act of 1933 in reliance upon Section 4(2) of the Act.

Item 4. Submission of Matters to a Vote of Security Holders

(a) Regular annual meeting of IDACORP'S stockholders held May 16, 2002 in Boise, Idaho.

(b) Directors elected at the meeting for a three-year term:

Roger L. Breezley	Jack K. Lemley
John B. Carley	Evelyn Loveless

Continuing Directors:

Rotchford L. Barker	Peter S. O'Neill
Christopher L. Culp	Jan B. Packwood
Gary G. Michael	Robert A. Tintsman
Jon H. Miller

Name	For	Withheld	Total Voted
Roger L. Breezley	29,974,298	1,527,220	31,501,518
John B. Carley	30,967,006	534,512	31,501,518
Jack K. Lemley	30,941,698	559,820	31,501,518
Evelyn Loveless	30,859,588	641,930	31,501,518

2) To establish a written policy on the rights of indigenous people:

Class of Stock	For	Against	Abstain	Broker Non-Votes	Total Voted
Common	2,797,743	19,020,803	1,195,929	8,487,043	31,501,518

3) To provide a report reviewing the relicensing process for the Hells Canyon Complex:

Class of Stock	For	Against	Abstain	Broker Non-Votes	Total Voted
Common	7,883,102	14,313,267	818,106	8,487,043	31,501,518

4) To ratify the selection of Deloitte & Touche LLP as independent auditors for the fiscal year ending December 31, 2002.

Class of Stock	For	Against	Abstain	Total Voted
Common	29,962,254	1,362,188	177,076	31,501,518

Item 6. Exhibits and Reports on Form 8-K

(a) Exhibits:

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

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

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

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

*3(c)	1-14465 Form 10-Q for 6/30/99	3(c)	Amended Bylaws of IDACORP, Inc. as of July 8, 1999.

*4(a)	1-14465 Form 8-K dated September 15, 1998	4	Rights Agreement, dated as of September 10, 1998, between IDACORP, Inc. and Wells Fargo Bank Minnesota, N.A. as Successor Rights Agent.

*4(b)	1-14465 Form 8-K dated February 28, 2001	4.1	Indenture for Senior Debt Securities dated as of February 1, 2001, between IDACORP, Inc. and Bankers Trust Company (now Deutsche Bank Trust Company Americas), as Trustee.

*4(c)	1-14465 Form 8-K dated February 28, 2001	4.2	First Supplemental Indenture dated as of February 1, 2001, to Indenture for Senior Debt Securities dated as of February 1, 2001 between IDACORP, Inc. and Bankers Trust Company (now Deutsche Bank Trust Company Americas), as Trustee.

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

*10(b) 1	1-14465 Form 10-K for 2001	10(n)(ii)	The Executive Annual Incentive Plan for senior management employees of IPC effective January 1, 2001.

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

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

*10(e) 1	1-14465 Form 10-Q for 3/31/02	10(e)	IDACORP, Inc. Non-Employee Directors Stock Compensation Plan as of May 17, 1999, as amended.

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

[1] Compensatory Plan

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

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

*10(i)1	1-14465 Form 10-Q for 3/31/02	10(i)	IDACORP, Inc. 2000 Long-Term Incentive and Compensation Plan, as amended.

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.

15			Letter Re: Unaudited Interim Financial Information.

21			Subsidiaries of IDACORP, Inc.

99(a)			Certification of Chief Executive Officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

99(b)			Certification of Chief Financial Officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

[1] Compensatory Plan

Reports on Form 8-K. The following reports on Form 8-K were filed for the three months ended June 30, 2002.

Items Reported		Date of Report

Item 5 - Other events		April 25, 2002
Item 5 - Other events		May 16, 2002
Item 5 - Other events		May 31, 2002
Item 5 - Other events		June 21, 2002

* Previously filed and incorporated herein by reference.

SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

				IDACORP, Inc.
				(Registrant)

Date	August 13, 2002	By:	/s/	Jan B. Packwood
				Jan B. Packwood
				President and Chief Executive Officer


Date	August 13, 2002	By:	/s/	Darrel T. Anderson
				Darrel T. Anderson
				Vice President, Chief Financial
				Officer and Treasurer
				(Principal Financial Officer)
				(Principal Accounting Officer)

Maturity