Idaho Power 10Q 2002 Q2 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


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

1-3198	Idaho Power Company	82-0130980
	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:	37,612,351 shares, all of which
	are held by IDACORP, Inc.

GLOSSARY

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

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 Capitalization		8
		Consolidated Statements of Cash Flows		9
		Consolidated Statements of Comprehensive Income		10
		Notes to Consolidated Financial Statements		11-17
		Independent Accountants' Report		18

	Item 2. Management's Discussion and Analysis of Financial
			Condition and Results of Operations	19-29

	Item 3. Quantitative and Qualitative Disclosures about Market Risk			29



Part II. Other Information:

	Item 4. Submission of Matters to a Vote of Security Holders			30

	Item 6. Exhibits and Reports on Form 8-K			31-34

Signatures				35

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
Idaho Power Company
Consolidated Statements of Income
(unaudited)

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

REVENUES:
	General business		$	187,564	$	156,207
	Off-system sales			10,976		58,650
	Other revenues			10,528		13,073
		Total revenues		209,068		227,930
EXPENSES:
	Operation:
		Purchased power		31,184		169,419
		Fuel expense		21,708		22,351
		Power cost adjustment		42,165		(68,086)
		Other		36,839		34,074
	Maintenance			16,141		15,535
	Depreciation			23,184		21,448
	Taxes other than income taxes			5,160		5,409
		Total expenses		176,381		200,150

INCOME FROM OPERATIONS				32,687		27,780

OTHER INCOME:
	Allowance for equity funds used during construction			54		361
	Other - net			3,835		2,518
		Total other income		3,889		2,879

INTEREST CHARGES:
	Interest on long-term debt			12,237		14,750
	Other interest			2,483		2,603
	Allowance for borrowed funds used during construction			(1,127)		(1,251)
		Total interest charges		13,593		16,102

INCOME BEFORE INCOME TAXES				22,983		14,557

INCOME TAXES				9,149		6,838

INCOME FROM CONTINUING OPERATIONS				13,834		7,719

DISCONTINUED OPERATIONS:
	Income from operations of energy marketing transferred to
		parent (net of tax of $18,195)		-		27,066

NET INCOME				13,834		34,785

	Dividends on preferred stock			1,298		1,292

EARNINGS ON COMMON STOCK			$	12,536	$	33,493

The accompanying notes are an integral part of these statements.

Idaho Power Company
Consolidated Statements of Income
(unaudited)

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

REVENUES:
	General business		$	373,684	$	289,328
	Off-system sales			31,135		113,898
	Other revenues			18,835		25,019
		Total revenues		423,654		428,245
EXPENSES:
	Operation:
		Purchased power		61,374		294,706
		Fuel expense		49,636		47,597
		Power cost adjustment		76,225		(126,332)
		Other		73,683		71,541
	Maintenance			28,161		27,216
	Depreciation			46,355		42,399
	Taxes other than income taxes			10,346		10,644
		Total expenses		345,780		367,771

INCOME FROM OPERATIONS				77,874		60,474

OTHER INCOME:
	Allowance for equity funds used during construction			43		586
	Other - net			10,964		7,178
		Total other income		11,007		7,764

INTEREST CHARGES:
	Interest on long-term debt			25,554		28,173
	Other interest			4,974		4,820
	Allowance for borrowed funds used during construction			(1,320)		(2,416)
		Total interest charges		29,208		30,577

INCOME BEFORE INCOME TAXES				59,673		37,661

INCOME TAXES				22,954		14,592

INCOME FROM CONTINUING OPERATIONS				36,719		23,069

DISCONTINUED OPERATIONS:
	Income from operations of energy marketing transferred to
		parent (net of tax of $33,573)		-		49,943

NET INCOME				36,719		73,012

	Dividends on preferred stock			2,660		2,753

EARNINGS ON COMMON STOCK			$	34,059	$	70,259

The accompanying notes are an integral part of these statements.

Idaho Power Company
Consolidated Balance Sheets

(unaudited)

Assets

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

ELECTRIC PLANT:
	In service (at original cost)			$	3,020,057	$	2,989,630
	Accumulated provision for depreciation				(1,260,763)		(1,220,002)
		In service - Net			1,759,294		1,769,628
	Construction work in progress				100,271		86,010
	Held for future use				2,232		2,232

			Electric plant - Net		1,861,797		1,857,870

INVESTMENTS AND OTHER PROPERTY					37,969		37,432

CURRENT ASSETS:
	Cash and cash equivalents				8,045		43,040
	Receivables:
		Customer			80,735		58,702
		Allowance for uncollectible accounts			(1,500)		(1,500)
		Notes			5,449		3,488
		Employee notes			7,255		6,274
		Related parties			25,491		37,517
		Other			3,715		2,280
	Taxes receivable				-		8,244
	Accrued unbilled revenues				41,715		37,400
	Materials and supplies (at average cost)				22,796		23,280
	Fuel stock (at average cost)				9,491		8,726
	Prepayments				32,762		31,897
	Regulatory assets				14,204		55,107

	Total current assets				250,158		314,455

DEFERRED DEBITS:
	American Falls and Milner water rights				31,585		31,585
	Company-owned life insurance				38,758		39,602
	Regulatory assets				461,412		544,134
	Other				35,131		34,626

	Total deferred debits				566,886		649,947

	TOTAL			$	2,716,810	$	2,859,704

The accompanying notes are an integral part of these statements.

Idaho Power Company
Consolidated Balance Sheets
(unaudited)

Capitalization and Liabilities

				June 30,		December 31,
				2002		2001
					(thousands of dollars)
CAPITALIZATION:
	Common stock equity:
		Common stock, $2.50 par value (50,000,000 shares
			authorized; 37,612,351 shares outstanding)	$	94,031	$	94,031
		Premium on capital stock			362,631		362,602
		Capital stock expense			(4,209)		(4,144)
		Retained earnings			315,935		316,856
		Accumulated other comprehensive income (loss)			(4,966)		(3,719)

			Total common stock equity		763,422		765,626

	Preferred stock				104,266		104,387

	Long-term debt				672,330		802,201

			Total capitalization		1,540,018		1,672,214

CURRENT LIABILITIES:
	Long-term debt due within one year				107,079		27,078
	Notes payable				240,350		282,000
	Accounts payable				31,927		68,806
	Notes and accounts payable to related parties				2,545		6,931
	Taxes accrued				43,112		-
	Derivative liabilities				-		40,528
	Interest accrued				11,966		13,115
	Deferred income taxes				14,204		14,578
	Other				33,369		16,118

			Total current liabilities		484,552		469,154

DEFERRED CREDITS:
	Deferred income taxes				518,565		541,482
	Derivative liabilities - long-term				-		7,253
	Regulatory liabilities				116,777		113,957
	Other				56,898		55,644

			Total deferred credits		692,240		718,336


COMMITMENTS AND CONTINGENT LIABILITIES

			TOTAL	$	2,716,810	$	2,859,704

The accompanying notes are an integral part of these statements.

Idaho Power Company
Consolidated Statements of Capitalization

(unaudited)

				June 30,				December 31,
				2002			%	2001		%
				(thousands of dollars)
COMMON STOCK EQUITY:
	Common stock			$	94,031			$	94,031
	Premium on capital stock				362,631				362,602
	Capital stock expense				(4,209)				(4,144)
	Retained earnings				315,935				316,856
	Accumulated other comprehensive income (loss)				(4,966)				(3,719)
		Total common stock equity			763,422	50			765,626		46

PREFERRED STOCK:
	4% preferred stock				14,266				14,387
	7.68% Series, serial preferred stock				15,000				15,000
	7.07% Series, serial preferred stock				25,000				25,000
	Auction rate preferred stock				50,000				50,000
		Total preferred stock			104,266	7			104,387		6

LONG-TERM DEBT:
	First mortgage bonds:
		6.85% Series due 2002			27,000				27,000
		6.40% Series due 2003			80,000				80,000
		8 % Series due 2004			50,000				50,000
		5.83% Series due 2005			60,000				60,000
		7.38% Series due 2007			80,000				80,000
		7.20% Series due 2009			80,000				80,000
		6.60% Series due 2011			120,000				120,000
		7.50% Series due 2023			80,000				80,000
		8.75% Series due 2027			-				50,000
			Total first mortgage bonds		577,000				627,000
		Amount due within one year			(107,000)				(27,000)
			Net first mortgage bonds		470,000				600,000
	Pollution control revenue bonds:
		8.30% Series 1984 due 2014			49,800				49,800
		6.05% Series 1996A due 2026			68,100				68,100
		Variable Rate Series 1996B due 2026			24,200				24,200
		Variable Rate Series 1996C due 2026			24,000				24,000
		Variable Rate Series 2000 due 2007			4,360				4,360
			Total pollution control revenue bonds		170,460				170,460
	REA notes				1,224				1,263
		Amount due within one year			(79)				(78)
			Net REA notes		1,145				1,185
	American Falls bond guarantee				19,885				19,885
	Milner Dam note guarantee				11,700				11,700
	Unamortized premium/discount - Net				(860)				(1,029)

			Total long-term debt		672,330	43			802,201		48

TOTAL CAPITALIZATION				$	1,540,018	100		$	1,672,214		100

The accompanying notes are an integral part of these statements.

Idaho Power Company
Consolidated Statements of Cash Flows

(unaudited)

				Six Months Ended
				June 30,
				2002		2001
				(thousands of dollars)
OPERATING ACTIVITIES:
	Net income			$	36,719		$	73,012
	Adjustments to reconcile net income to net cash provided by
		(used in) operating activities:
		Allowance for uncollectible accounts			-			20,174
		Unrealized gains from energy marketing activities			-			(101,317)
		Depreciation and amortization			52,801			48,297
		Deferred taxes and investment tax credits			(19,502)			86,503
		Undistributed earnings of affiliates			-			(52)
		Accrued PCA costs			71,562			(127,031)
		Change in:
			Accounts receivable and prepayments		(27,411)			9,703
			Accrued unbilled revenue		(4,315)			(2,714)
			Materials and supplies and fuel stock		(281)			(2,374)
			Accounts payable		(41,265)			20,911
			Taxes receivable/accrued		51,356			(22,226)
			Other current assets and liabilities		16,103			2,174
		Other - net			963			(6,355)
	Net cash provided by (used in) operating activities				136,730			(1,295)

INVESTING ACTIVITIES:
	Additions to utility plant				(52,102)			(87,718)
	Note receivable payment from parent				12,162			-
	Other - net				(205)			(2,443)
		Net cash used in investing activities			(40,145)			(90,161)

FINANCING ACTIVITIES:
	Issuance of first mortgage bonds				-			120,000
	Retirement of first mortgage bonds				(50,000)			(75,000)
	Dividends on common stock				(34,980)			(34,914)
	Dividends on preferred stock				(2,660)			(2,753)
	Increase in short-term borrowings				(41,650)			15,800
	Other - net				(2,290)			(3,749)
		Net cash provided by (used in) financing activities			(131,580)			19,384

Net increase (decrease) in cash and cash equivalents					(34,995)			(72,072)

Cash and cash equivalents at beginning of period					43,040			83,494

Cash and cash equivalents at end of period				$	8,045		$	11,422

SUPPLEMENTAL DISCLOSURE OF CASH FLOW
	INFORMATION:
	Cash paid (received) during the period for:
		Income taxes		$	(8,459)		$	-
		Interest (net of amount capitalized)			29,184			29,703
		Net assets transferred to parent for notes receivable			-			76,250

The accompanying notes are an integral part of these statements.

Idaho Power Company
Consolidated Statements of Comprehensive Income
(unaudited)

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

NET INCOME			$	13,834		$	34,785

OTHER COMPREHENSIVE INCOME (LOSS):
	Unrealized gains (losses) on securities (net of tax of ($618)
		and $156)		(951)			239

TOTAL COMPREHENSIVE INCOME			$	12,883		$	35,024

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

NET INCOME			$	36,719	$	73,012

OTHER COMPREHENSIVE INCOME (LOSS):
	Unrealized gains (losses) on securities (net of tax of ($771)
		and ($925))		(1,247)		(1,608)

TOTAL COMPREHENSIVE INCOME			$	35,472	$	71,404

The accompanying notes are an integral part of these statements

Notes to the Consolidated Financial Statements
(unaudited)

1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES:

Nature of Business
Idaho Power Company is an electric utility regulated by the Federal Energy Regulatory Commission and the state regulatory commissions of Idaho, Oregon, and Wyoming, and is engaged in the generation, transmission, distribution, sale and purchase of electric energy. We are the parent of Idaho Energy Resources Co., a joint venturer in Bridger Coal Company, which supplies coal to our Jim Bridger generating plant.

References in this report to "we," "us" and "our" are to Idaho Power Company and its subsidiary.

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

Effective June 11, 2001 we transferred our wholesale electricity marketing operations (Energy Marketing) to IDACORP Energy (IE). After the transfer of Energy Marketing, we consist of one operating segment, Utility Operations. The Utility Operations segment has two primary sources of income, our regulated operations and income from our joint venture in Bridger Coal Company.

Beginning August 1, 2002, we resumed the function of buying and selling wholesale electricity to support our utility operations.

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 subsidiary. 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
In January 2002, we adopted Statement of Financial Accounting Standard (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 for 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. We have completed an evaluation of the effect of this revised Interpretation on the treatment of booked out contracts and have determined that contracts previously classified as derivatives are exempt. The effect of the change does not have a material effect on our 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.

2. INCOME TAXES:

Our effective tax rate for the first six months decreased from 39.7 percent in 2001 to 38.5 percent in 2002. Reconciliations between the statutory income tax rate and the effective rates are as follows (in thousands of dollars):

		Six Months Ended June 30,
		2002				2001
		Amount		Rate		Amount		Rate
Computed income taxes based on statutory
	federal income tax rate	$	20,886	35.0%	$		42,412	35.0%
Changes in taxes resulting from:
	Investment tax credits		(1,600)	(2.7)			(1,552)	(1.3)
	Repair allowance		(1,400)	(2.3)			(1,400)	(1.2)
	Pension expense		(26)	-			(912)	(0.8)
	State income taxes		2,942	4.9			5,667	4.7
	Depreciation		2,821	4.7			3,799	3.1
	Other		(669)	(1.1)			151	0.2
Total provision for federal and state income taxes		$	22,954	38.5%	$		48,165	39.7%

3. PREFERRED STOCK:

The number of shares of 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

We are planning to redeem our action 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:

We have 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. We also have a $200 million 364-day revolving credit facility that expires in March 2003, under which we pay a facility fee on the commitment quarterly in arrears, based on our 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, our short-term borrowing under this facility totaled $140 million. We also have $100 million of floating rate notes outstanding, payable on September 1, 2002.

We currently have 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 of First Mortgage Bonds 8.75% Series due 2027 were redeemed early using short-term borrowings.

5. COMMITMENTS AND CONTINGENT LIABILITIES:

Commitments under contracts and purchase orders relating to our program for construction and operation of facilities amounted to approximately $4 million at June 30, 2002. The commitments are generally revocable by us 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.

6. REGULATORY ISSUES:

Deferred Power Supply Costs

Idaho: Our Power Cost Adjustment (PCA) mechanism 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 beginning October 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 we 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 we will earn a six percent carrying charge on the balance.
Denied our 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 surcharge to collect approximately $2.6 million to fund future conservation programs.

The IPUC had previously issued an order disallowing the lost revenue portion of the irrigationload reduction program. We believe that the Commission's order is inconsistent with an earlier order that allowed recovery of such costs and we filed a Petition for Reconsideration on May 2, 2002. The process we have embarked upon has a number of steps involved and could extend into the early fall. If we are unsuccessful in our 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: We filed an application with the Oregon Public Utility Commission (OPUC) to begin recovering extraordinary 2001 power supply costs in our 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 our 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. We 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 us to increase our rate of recovery to six percent effective November 28, 2001.

Deferred power supply costs consist of the following (in thousands of dollars):

			June 30,		December 31,
			2002		2001

Oregon deferral			$	14,742	$	14,866

Idaho PCA current deferral:
	Deferral for 2001-2002 rate year			-		78,395
	Deferral for 2002-2003 rate year			(685)		-
	Irrigation load reduction program			12,345		69,586
	Astaris load reduction agreement			6,016		62,247
	Irrigation and small general service deferral for
		recovery in the 2003-2004 rate year		11,703		-

Idaho PCA true-up:
	Remaining true-up authorized October 2001			-		36,500
	Remaining true-up authorized May 2001			-		42,895
	Remaining true-up authorized May 2002			188,806		-
		Total deferral	$	232,927	$	304,489

FMC/Astaris Settlement Agreement
On January 8, 2002, the IPUC initiated an investigation to examine the load reduction rates contained in our Voluntary Load Reduction (VLR) Agreement with 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, we, along with 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 we make to FMC/Astaris through May 2003 were decreased $5 million, reducing 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 us in the Fourth Judicial District for the State of Idaho.
FMC/Astaris will pay us approximately $31 million through March 2003 to settle the ESA.

Garnet Power Purchase Agreement
We had entered into a power purchase agreement (PPA) with Garnet Energy, LLC (Garnet), a subsidiary of Ida-West, to purchase energy produced by Garnet's to-be-built natural gas generation facility. A hearing was scheduled for July 23, 2002 on our 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 us 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 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 we 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 our petition to enter into a PPA with Garnet. We were 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 we propose to meet future power requirements if Garnet is not built.

Application to Defer Extraordinary Costs Associated With Security Measures
In November 2001, we filed an application requesting the IPUC to issue an accounting order authorizing the deferral of 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 our employees and to protect company facilities. At June 30, 2002, $1 million of extraordinary security costs had been deferred. 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 our 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.

Truckee-Donner Public Utility District
On July 23, 2002, Truckee-Donner Public Utility District located in the State of California, 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 within 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
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 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.

IDACORP Energy and Idaho Power Company Agreement
We 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 our customers as a result of transactions with IE after February 2001. Similar issues arising prior to February 2001 were resolved by IPUC Order No. 28852.

7. RELATED PARTY:

For the six months ended June 30, 2002, we have paid IE approximately $2 million under the Electricity Supply Management Services Agreement.

Additionally, we sold $6 million and $18 million in off-system sales to IE for the three and six months ended June 30, 2002, and purchased $7 million and $9 million in purchased power from IE for the three and six months ended June 30, 2002.

INDEPENDENT ACCOUNTANTS' REPORT

Idaho Power Company
Boise, Idaho

We have reviewed the accompanying consolidated balance sheet and statement of capitalization of Idaho Power Company and its subsidiary 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 and statement of capitalization of Idaho Power Company and its subsidiary as of December 31, 2001, and the related consolidated statements of income, comprehensive income, retained earnings, 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 and statement of capitalization as of December 31, 2001 is fairly stated, in all material respects, in relation to the consolidated balance sheet and statement of capitalization 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 thousands, 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 Idaho Power Company (IPC) and subsidiary.

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.

References in this report to "we", "us" and "our" are to IPC and its subsidiary.

Beginning August 1, 2002, we resumed the function of buying and selling wholesale electricity to support our utility operations.

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;
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:

The three months increase in income from continuing operations is due to a $23 million decrease in operation expenses offset by a $19 million decrease in revenue. 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 decrease in revenues is due to decreased off-system sales of $48 million offset by increased general business revenues of $32 million.

The six months increase in income from continuing 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.

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

General Business Revenue
The following table presents 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		$	60,948	$	50,411	887	834	$	155,102	$	120,146	2,244	2,184
Commercial			47,863		39,002	838	809		96,449		71,707	1,714	1,643
Industrial			43,530		38,037	790	998		86,649		68,570	1,564	2,062
Irrigation			35,223		28,757	666	571		35,484		28,905	669	573
	Total	$	187,564	$	156,207	3,181	3,212	$	373,684	$	289,328	6,191	6,462

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 our service territory increased approximately 2 percent, resulting in a $2 million increase in revenues for the three and six months ended June 30, 2002.
FMC/Astaris, previously our 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, we have continued to receive payments from FMC/Astaris since their plant closures. Accordingly, we show 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 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	$	10,976	$	58,650	$	31,135	$	113,898
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 reduced wholesale electricity prices and our 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 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	$	23,349	$	131,838	$	36,513	$	257,124
	Program costs		7,835		37,581		24,861		37,582

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 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	$	21,708	$	22,351	$	49,636	$	47,597
Thermal MWHs generated		1,492		1,697		3,413		3,648

PCA
The PCA expense component is related to the 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)		$	1,049	$	(53,760)	$	4,570	$	(110,757)
Astaris and irrigation program costs (deferral)			(5,994)		(33,063)		(19,019)		(33,063)
Amortization of prior year authorized balances			45,650		18,737		89,214		17,488
Write-off of disallowed costs			1,460		-		1,460		-
	Total power cost adjustment	$	42,165	$	(68,086)	$	76,225	$	(126,332)

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.

LIQUIDITY AND CAPITAL RESOURCES:

Cash Flow
Our net cash provided by operations totaled $137 million for the six months ended June 30, 2002. Significant factors affecting cash flows in 2002 include:

the receipt of a $28 million income tax refund related to net operating loss carrybacks associated with 2001 power supply costs, offset by tax payments of $20 million;
the recovery through the PCA of power supply costs incurred in 2000 and 2001.

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.

Cash Expenditures
We forecast that internal cash generation after dividends will be sufficient to meet our total capital requirements for 2002-2004. 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.

Financing Program
We have 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. We have a $200 million 364-day revolving credit facility that expires in March 2003, under which we pay a facility fee on the commitment quarterly in arrears, based on our 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, short term borrowing under this facility totaled $140 million. We also have $100 million of floating rate notes outstanding, payable on September 1, 2002. We are in the process of replacing these notes with comparable financing with a due date of approximately September 2003.

We currently have 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.

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

Credit Rating
On March 25, 2002, S&P lowered its Corporate Credit Rating from "A+" (negative outlook) to "A-" (negative outlook). Our financial profile has been considerably weakened by the accumulation of deferred power costs incurred during 2001.

On May 16, 2002, Fitch lowered its ratings on our securities. Fitch stated that the new ratings better reflect the earnings and cash flow volatility experienced during the recent drought. Fitch stated that the new ratings reflect the May 13, 2002 PCA order of the IPUC. Fitch also initiated coverage of our commercial paper with an F1 rating. The rating outlook 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 IDACORP's decision to wind down the power marketing business at IDACORP Energy (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 ratings of our securities:

	S & P
	From	To

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

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

OTHER MATTERS:

Regulatory Issues:

Deferred Power Supply Costs
Idaho: Our PCA mechanism 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 beginning October 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 we 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 will earn a six percent carrying charge on the balance.
Denied our 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. We believe that the Commission's order is inconsistent with an earlier order that allowed recovery of such costs and we filed a Petition for Reconsideration on May 2, 2002. The process we have embarked upon has a number of steps involved and could extend into the early fall. If we are unsuccessful in our 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: We filed an application with the OPUC to begin recovering extraordinary 2001 power supply costs in our 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 our 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. We 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 increased rates of recovery to six percent effective November 28, 2001.

Deferred power supply costs consist of the following:

			June 30,		December 31,
			2002		2001

Oregon deferral			$	14,742	$	14,866

Idaho PCA current deferral:
	Deferral for 2001-2002 rate year			-		78,395
	Deferral for 2002-2003 rate year			(685)		-
	Irrigation load reduction program			12,345		69,586
	Astaris load reduction agreement			6,016		62,247
	Irrigation and small general service deferral for
		recovery in the 2003-2004 rate year		11,703		-

Idaho PCA true-up:
	Remaining true-up authorized October 2001			-		36,500
	Remaining true-up authorized May 2001			-		42,895
	Remaining true-up authorized May 2002			188,806		-

	Total deferral		$	232,927	$	304,489

FMC/Astaris Settlement Agreement
On January 8, 2002, the IPUC initiated an investigation to examine the load-reduction rates contained in our Voluntary Load Reduction (VLR) Agreement with 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, we along with 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 we make to FMC/Astaris through May 2003 were decreased $5 million, reducing 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 us in the Fourth Judicial District for the State of Idaho.
FMC/Astaris will pay us approximately $31 million through March 2003 to settle the ESA.

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 our 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.

Power supply
We monitor the effect of streamflow conditions on Brownlee Reservoir, the water source for our three Hells Canyon hydroelectric facilities and our 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 our ability to produce low-cost hydropower.

Hydro generation on our 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, we are required to file with the IPUC and OPUC an Integrated Resource Plan (IRP), a comprehensive look at our 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 our peak periods. Prior to 2005, we 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 we are preparing a report for the IPUC on how it proposes to meet future power requirements if Garnet is not constructed.

Relicensing of Hydroelectric Projects
We, like other utilities that operate nonfederal hydroelectric projects, have obtained licenses for our hydroelectric projects from the FERC. These licenses generally last for 30 to 50 years depending on the size of the project. By 2010, the licenses for eight of our hydro projects will have expired. We are actively pursuing the relicensing of these projects, a process that will continue for the next 10 to 15 years. We submitted our first applications for license renewal to the FERC in December 1995. We have filed applications seeking renewal of licenses for our Bliss, Upper Salmon Falls, Lower Salmon Falls, CJ Strike, 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. We are currently engaged in procedures necessary to file timely license applications for each of these projects. Although various federal and state requirements and issues must be resolved through the license renewal process, we anticipate that we will relicense each of the 10 facilities. At this point, however, we cannot predict what type of environmental or operational requirements we may face, nor can we estimate the cost of license renewal. At 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 our hydro generation capacity and 41 percent of our total generating capacity. Presently, we are developing our 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. We expect 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. We are currently reviewing the NOPR, but at this time it is too early to assess what impact the NOPR, if implemented, would have on our operations.

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 and interest rates 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 4. Submission of Matters to a Vote of Security Holders

(a) Regular annual meeting of Idaho Power Company'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

	Common		4% Preferred		7.68% Preferred
Name	For	Withheld	For	Withheld	For	Withheld
Roger L. Breezley	37,612,351	-	1,785,740	120,540	94,433	465
John B. Carley	37,612,351	-	1,785,740	120,540	94,433	465
Jack K. Lemley	37,612,351	-	1,816,360	89,920	94,433	465
Evelyn Loveless	37,612,351	-	1,785,740	120,540	94,433	465

2) 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	37,612,351	-	-	37,612,351
4% Preferred	1,834,800	51,040	20,440	1,906,280
7.68% Preferred	93,623	1,050	225	94,898
Total	39,540,774	52,090	20,665	39,613,529

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

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

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

*3(a)(iii)	1-3198 Form 10-Q for 6/30/00	3(a)(iii)	Articles of Amendment to Restated Articles of Incorporation of IPC as filed with the Secretary of State of Idaho on June 15, 2000.

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

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

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

*4(a)(ii)			IPC Supplemental Indentures to Mortgage and Deed of Trust:
			Number	Dated
	1-MD	B-2-a	First	July 1, 1939
	2-5395	7-a-3	Second	November 15, 1943
	2-7237	7-a-4	Third	February 1, 1947
	2-7502	7-a-5	Fourth	May 1, 1948
	2-8398	7-a-6	Fifth	November 1, 1949
	2-8973	7-a-7	Sixth	October 1, 1951
	2-12941	2-C-8	Seventh	January 1, 1957
	2-13688	4-J	Eighth	July 15, 1957
	2-13689	4-K	Ninth	November 15, 1957
	2-14245	4-L	Tenth	April 1, 1958
	2-14366	2-L	Eleventh	October 15, 1958
	2-14935	4-N	Twelfth	May 15, 1959
	2-18976	4-O	Thirteenth	November 15, 1960
	2-18977	4-Q	Fourteenth	November 1, 1961
	2-22988	4-B-16	Fifteenth	September 15, 1964
	2-24578	4-B-17	Sixteenth	April 1, 1966
	2-25479	4-B-18	Seventeenth	October 1, 1966
	2-45260	2(c)	Eighteenth	September 1, 1972
	2-49854	2(c)	Nineteenth	January 15, 1974
	2-51722	2(c)(i)	Twentieth	August 1, 1974
	2-51722	2(c)(ii)	Twenty-first	October 15, 1974
	2-57374	2(c)	Twenty-second	November 15, 1976
	2-62035	2(c)	Twenty-third	August 15, 1978
	33-34222	4(d)(iii)	Twenty-fourth	September 1, 1979
	33-34222	4(d)(iv)	Twenty-fifth	November 1, 1981
	33-34222	4(d)(v)	Twenty-sixth	May 1, 1982
	33-34222	4(d)(vi)	Twenty-seventh	May 1, 1986
	33-00440	4(c)(iv)	Twenty-eighth	June 30, 1989
	33-34222	4(d)(vii)	Twenty-ninth	January 1, 1990
	33-65720	4(d)(iii)	Thirtieth	January 1, 1991
	33-65720	4(d)(iv)	Thirty-first	August 15, 1991
	33-65720	4(d)(v)	Thirty-second	March 15, 1992
	33-65720	4(d)(vi)	Thirty-third	April 1, 1993
	1-3198 Form 8-K Dated 12/17/93	4	Thirty-fourth	December 1, 1993
	1-3198 Form 8-K Dated 11/21/00	4	Thirty-fifth	November 1, 2000

	1-3198 Form 8-K Dated 9/27/01	4(a)	Thirty-sixth	October 1, 2001

4(b)			Indenture for Debt Securities dated as of August 1, 2001 between Idaho Power Company and Bank One Trust Company N.A. as trustee

4(c)			First Supplemental Indenture dated as of September 1, 2001 to Indenture for Debt Securities dated as of August 1, 2001 between Idaho Power Company and Bank One Trust Company N.A. as trustee.

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

*4(e)	33-65720	4(f)	Agreement of IPC to furnish certain debt instruments.

*4(f)	33-00440	2(a)(iii)	Agreement and Plan of Merger dated March 10, 1989, between Idaho Power Company, a Maine Corporation, and Idaho Power Migrating Corporation.

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

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

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

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

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

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

*10(e)(i)	2-62034	5(s)	Agreement for Construction, Ownership and Operation of the Number One Boardman Station on Carty Reservoir, dated as of October 15, 1976, between Portland General Electric Company and IPC.

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

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

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

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

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

*10(f)	2-68574	5(z)	Participation Agreement, dated September 1, 1979, relating to the sale and leaseback of coal handling facilities at the Number One Boardman Station on Carty Reservoir.

*10(g)	2-64910	5(y)	Agreements for the Operation, Construction and Ownership of the North Valmy Power Plant Project, dated December 12, 1978, between Sierra Pacific Power Company and IPC.

*10(h)(i) 1	1-3198 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(h)(ii) 1	1-3198 Form 10-K for 2001	10(n)(ii)	The Executive Annual Incentive Plan for senior management employees of IPC effective January 1, 2001.

*10(h)(iii) 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(h)(iv) 1	1-3198 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, as amended.

*10(h) (v) 1	1-3198 Form 10-Q for 3/31/02	10(h)(v)	IDACORP, Inc. Non-Employee Directors Stock Compensation Plan as of May 17, 1999, as amended.

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

*10(h)(vii)	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)(viii)	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(h)(ix) 1	1-3198 Form 10-Q for 3/31/02	10(h)(ix)	IDACORP, Inc. 2000 Long-Term Incentive and Compensation Plan, as amended.

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

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

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

*10(j)	33-65720	10(m)	Agreement Regarding the Ownership, Construction, Operation and Maintenance of the Milner Hydroelectric Project (FERC No. 2899), dated January 22, 1990, between IPC and the Twin Falls Canal Company and the Northside Canal Company Limited.

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

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

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

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

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

15			Letter Re: Unaudited Interim Financial Information.

*21	1-3198 Form 10-K for 2001	21	Subsidiary of IPC.

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.

(b) 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

* 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.

				IDAHO POWER COMPANY
				(Registrant)

Date	August 13, 2002	By:	/s/	J LaMont Keen
				J. LaMont Keen
				President and Chief
				Operating 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)

[1] Compensatory Plan

Positive
Negative
Uncertain
Constraining
Legalese
Litigous
Readability	7th grade Good

Idaho Power 10-Q2002 Q2 Quarterly report

Content analysis

PART II - OTHER INFORMATION