IDACORP INC - 10-Q Quarterly Report

PART I - FINANCIAL INFORMATION
Item 1. Financial Statements
IDACORP, Inc.
Consolidated Statements of Operations
(unaudited)

				Three Months Ended June 30,
				2003		2002
				(thousands of dollars except for per
				share amounts)
OPERATING REVENUES:
	Electric utility:
		General business		$	166,613	$	187,564
		Off-system sales			19,839		10,976
		Other revenues			11,176		11,041
			Total electric utility revenues		197,628		209,581
	Energy marketing				(1,053)		(3,049)
	Other				3,701		3,300
		Total operating revenues			200,276		209,832

OPERATING EXPENSES:
	Electric utility:
		Purchased power			32,019		31,184
		Fuel expense			23,908		21,708
		Power cost adjustment			25,383		42,165
		Other operations and maintenance			59,537		53,351
		Depreciation			24,279		23,184
		Taxes other than income taxes			5,251		5,160
			Total electric utility expenses		170,377		176,752
	Energy marketing:
		Cost of revenues			(15)		13,005
		Selling, general and administrative			6,481		4,551
	Other				9,433		7,781
			Total operating expenses		186,276		202,089

OPERATING INCOME (LOSS):
	Electric utility				27,251		32,829
	Energy marketing				(7,519)		(20,605)
	Other				(5,732)		(4,481)
		Total operating income			14,000		7,743

OTHER INCOME					1,402		2,464

INTEREST EXPENSE AND OTHER:
	Interest on long-term debt				14,449		12,237
	Other interest				966		2,924
	Preferred dividends of Idaho Power Company				866		1,298
		Total interest expense and other			16,281		16,459

INCOME (LOSS) BEFORE INCOME TAXES					(879)		(6,252)

INCOME TAX EXPENSE (BENEFIT)					-		(9,329)

NET INCOME (LOSS)				$	(879)	$	3,077

AVERAGE COMMON SHARES
	OUTSTANDING (000's)				38,196		37,665

EARNINGS (LOSS) PER SHARE OF COMMON
	STOCK (basic and diluted)			$	(0.02)	$	0.08

The accompanying notes are an integral part of these statements.

IDACORP, Inc.
Consolidated Statements of Operations
(unaudited)

				Six Months Ended June 30,
				2003		2002
				(thousands of dollars except for per
				share amounts)
OPERATING REVENUES:
	Electric utility:
		General business		$	341,675	$	373,684
		Off-system sales			38,447		31,135
		Other revenues			20,928		19,862
			Total electric utility revenues		401,050		424,681
	Energy marketing				2,540		17,931
	Other				8,614		6,813
		Total operating revenues			412,204		449,425

OPERATING EXPENSES:
	Electric utility:
		Purchased power			45,625		61,374
		Fuel expense			49,446		49,636
		Power cost adjustment			77,230		76,225
		Other operations and maintenance			110,122		102,611
		Depreciation			48,413		46,355
		Taxes other than income taxes			10,408		10,346
			Total electric utility expenses		341,244		346,547
	Energy marketing:
		Cost of revenues			3,705		24,467
		Selling, general and administrative			13,184		10,583
		Net (gain) loss on legal disputes			10,938		(2,775)
	Other				17,699		15,603
			Total operating expenses		386,770		394,425

OPERATING INCOME (LOSS):
	Electric utility				59,806		78,134
	Energy marketing				(25,287)		(14,344)
	Other				(9,085)		(8,790)
		Total operating income			25,434		55,000

OTHER INCOME					4,002		7,558

INTEREST EXPENSE AND OTHER:
	Interest on long-term debt				29,642		25,554
	Other interest				2,012		6,572
	Preferred dividends of Idaho Power Company				1,734		2,660
		Total interest expense and other			33,388		34,786

INCOME (LOSS) BEFORE INCOME TAXES					(3,952)		27,772

INCOME TAX EXPENSE					-		-

NET INCOME (LOSS)				$	(3,952)	$	27,772

AVERAGE COMMON SHARES
	OUTSTANDING (000's)				38,169		37,613

EARNINGS (LOSS) PER SHARE OF COMMON
	STOCK (basic and diluted)			$	(0.10)	$	0.74

The accompanying notes are an integral part of these statements.

IDACORP, Inc.
Consolidated Balance Sheets
(unaudited)

			June 30,		December 31,
			2003		2002
ASSETS			(thousands of dollars)

CURRENT ASSETS:
	Cash and cash equivalents		$	20,125	$	42,736
	Receivables:
		Customer		113,272		176,846
		Allowance for uncollectible accounts		(43,048)		(43,311)
		Employee notes		7,849		7,646
		Other		18,969		15,025
	Energy marketing assets			68,006		85,138
	Accrued unbilled revenues			35,404		35,714
	Materials and supplies (at average cost)			22,126		22,812
	Fuel stock (at average cost)			9,619		6,943
	Prepayments			31,582		34,872
	Regulatory assets			15,413		17,147
		Total current assets		299,317		401,568

INVESTMENTS				208,437		206,348

PROPERTY, PLANT AND EQUIPMENT:
	Utility plant in service			3,134,019		3,086,965
	Accumulated provision for depreciation			(1,339,762)		(1,294,961)
		Utility plant in service - net		1,794,257		1,792,004
	Construction work in progress			101,945		96,209
	Utility plant held for future use			2,730		2,335
	Other property, net of accumulated depreciation			11,763		15,950
		Property, plant and equipment - net		1,910,695		1,906,498

OTHER ASSETS:
	American Falls and Milner water rights			31,585		31,585
	Company-owned life insurance			35,460		35,299
	Energy marketing assets - long-term			42,953		64,733
	Regulatory assets			409,452		482,159
	Long-term receivable			44,363		73,941
	Other			54,276		50,507
		Total other assets		618,089		738,224

		TOTAL	$	3,036,538	$	3,252,638

The accompanying notes are an integral part of these statements.

IDACORP, Inc.
Consolidated Balance Sheets
(unaudited)

				June 30,		December 31,
				2003		2002
LIABILITIES AND SHAREHOLDERS' EQUITY				(thousands of dollars)

CURRENT LIABILITIES:
	Current maturities of long-term debt			$	62,788	$	89,592
	Notes payable				119,050		176,200
	Accounts payable				51,539		130,930
	Energy marketing liabilities				30,726		59,917
	Taxes accrued				88,365		49,709
	Interest accrued				14,077		13,639
	Deferred income taxes				25,926		21,384
	Other				30,882		35,119
		Total current liabilities			423,353		576,490

OTHER LIABILITIES:
	Deferred income taxes				536,119		595,639
	Energy marketing liabilities - long-term				52,193		51,761
	Regulatory liabilities				114,663		114,247
	Other				93,402		87,605
		Total other liabilities			796,377		849,252

LONG-TERM DEBT					923,721		898,676

COMMITMENTS AND CONTINGENT LIABILITIES

PREFERRED STOCK OF IDAHO POWER COMPANY					52,562		53,393

SHAREHOLDERS' EQUITY:
	Common stock, no par value (shares authorized 120,000,000;
		38,341,362 and 38,152,436 shares issued, respectively)			474,271		470,361
	Retained earnings				375,875		415,315
	Accumulated other comprehensive income (loss)				(5,083)		(7,109)
	Treasury stock (145,075 and 134,667 shares at cost, respectively)				(4,538)		(3,740)
		Total shareholders' equity			840,525		874,827

			TOTAL	$	3,036,538	$	3,252,638

The accompanying notes are an integral part of these statements.

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

				Six Months Ended
				June 30,
				2003		2002
				(thousands of dollars)
OPERATING ACTIVITIES:
	Net income (loss)			$	(3,952)	$	27,772
	Adjustments to reconcile net income (loss) to net cash provided by
		operating activities:
		Net non-cash loss on legal disputes			10,938		-
		Allowance for uncollectible accounts			(263)		-
		Unrealized (gains) losses from energy marketing activities			11,691		58,165
		Depreciation and amortization			65,744		57,222
		Deferred taxes and investment tax credits			(54,465)		(45,137)
		Accrued PCA costs			75,314		71,892
		Change in:
			Receivables and prepayments		68,929		23,667
			Accrued unbilled revenues		309		(4,315)
			Materials and supplies and fuel stock		(1,990)		517
			Accounts payable and other accrued liabilities		(76,246)		(121,952)
			Taxes receivable/accrued		38,928		67,760
			Other current assets and liabilities		(2,053)		(10,007)
		Other - net			4,596		(1,680)
			Net cash provided by operating activities		137,480		123,904

INVESTING ACTIVITIES:
	Additions to property, plant and equipment				(57,599)		(56,259)
	Investments in low-income housing projects				-		(43,657)
	Other - net				(6,704)		(3,113)
		Net cash used in investing activities			(64,303)		(103,029)

FINANCING ACTIVITIES:
	Proceeds from issuance of first mortgage bonds				140,000		-
	Proceeds from issuance of other long-term debt				25,475		-
	Retirement of first mortgage bonds				(160,000)		(50,000)
	Retirement of other long-term debt				(7,329)		(7,521)
	Retirement of preferred stock of Idaho Power Company				(831)		(121)
	Dividends on common stock				(35,487)		(34,980)
	Change in short-term borrowings				(57,150)		47,650
	Common stock issued				4,123		7,715
	Acquisition of treasury shares				(798)		(826)
	Other - net				(3,791)		(2,374)
		Net cash used in financing activities			(95,788)		(40,457)

Net decrease in cash and cash equivalents					(22,611)		(19,582)

Cash and cash equivalents beginning of period					42,736		66,688

Cash and cash equivalents end of period				$	20,125	$	47,106

SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION:
	Cash paid (received) during the period for:
		Income taxes		$	16,216	$	(26,724)
		Interest (net of amount capitalized)		$	29,949	$	32,096

The accompanying notes are an integral part of these statements.

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

				Three Months Ended
				June 30,
				2003		2002
				(thousands of dollars)

NET INCOME (LOSS)				$	(879)	$	3,077

OTHER COMPREHENSIVE INCOME (LOSS):
	Unrealized gains (losses) on securities:
		Unrealized holding gains (losses) arising during the period,
			net of tax of $1,788 and ($633)		3,001		(974)
		Less: reclassification adjustment for (gains) losses included
			in net income, net of tax of $19 and $15		30		23
			Net unrealized gains (losses)		3,031		(951)

TOTAL COMPREHENSIVE INCOME				$	2,152	$	2,126

				Six Months Ended
				June 30,
				2003		2002
				(thousands of dollars)

NET INCOME (LOSS)				$	(3,952)	$	27,772

OTHER COMPREHENSIVE INCOME (LOSS):
	Unrealized gains (losses) on securities:
		Unrealized holding gains (losses) arising during the period,
			net of tax of $996 and ($756)		1,667		(1,223)
		Less: reclassification adjustment for (gains) losses included
			in net income, net of tax of $230 and ($15)		359		(24)
			Net unrealized gains (losses)		2,026		(1,247)

TOTAL COMPREHENSIVE INCOME (LOSS)				$	(1,926)	$	26,525

The accompanying notes are an integral part of these statements.

IDACORP, Inc.
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
(unaudited)

1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES:

Nature of Business
IDACORP, Inc. (IDACORP) is a holding company whose principal operating subsidiary is Idaho Power Company (IPC). IPC is regulated by the Federal Energy Regulatory Commission (FERC) and the state regulatory commissions of Idaho and Oregon 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 the Jim Bridger generating plant owned in part by IPC.

Another subsidiary, IDACORP Energy (IE), a marketer of electricity and natural gas, is in the process of winding down its operations.

IDACORP's other significant operating subsidiaries are:

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

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

Financial Statements
In the opinion of IDACORP and IPC, the accompanying unaudited consolidated financial statements contain all adjustments necessary to present fairly their consolidated financial position as of June 30, 2003, and consolidated results of operations for the three and six months ended June 30, 2003 and 2002 and consolidated cash flows for the six months ended June 30, 2003 and 2002. 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 the audited consolidated financial statements included in IDACORP's and IPC's Annual Report on Form 10-K for the year ended December 31, 2002. The results of operations for the interim periods are not necessarily indicative of the results to be expected for the full year.

Earnings Per Share
The computation of diluted earnings (loss) per share (EPS) differs from basic EPS only due to including immaterial amounts of potentially dilutive shares related to stock-based compensation awards.

Options on 1,280,000 shares of common stock were not included in computing the June 30, 2003 diluted EPS because their effects were antidilutive. Options on 849,000 shares of common stock were not included in computing the June 30, 2002 diluted EPS because the options' exercise prices were greater than the average market price of the common stock during the period. These options expire from 2010 to 2013 and were still outstanding at June 30, 2003.

Stock-Based Compensation
At June 30, 2003, two stock-based employee compensation plans existed. These plans are accounted for under the recognition and measurement principles of Accounting Principles Board Opinion 25, "Accounting for Stock Issued to Employees," and related interpretations. Grants of restricted stock are reflected in net income based on the market value at the award date, or the year-end price for shares not yet vested. No stock-based employee compensation cost is reflected in net income for stock options, as all options granted under these plans had an exercise price equal to the market value of the underlying common stock on the date of grant. IDACORP and IPC have adopted the disclosure only provision of Statement of Financial Accounting Standards (SFAS) 123, "Accounting for Stock-Based Compensation." The following table illustrates the effect on net income (loss) and EPS if the fair value recognition provisions of SFAS 123 had been applied to stock-based employee compensation (in thousands of dollars except for per share amounts):

			Three Months Ended				Six Months Ended
			June 30,				June 30,
			2003		2002		2003		2002

Net income (loss), as reported			$	(879)	$	3,077	$	(3,952)	$	27,772
Add: Stock-based employee compensation expense included
	in reported net income (loss), net of related tax effects			80		(122)		61		(7)
Deduct: Total stock-based employee compensation expense
	determined under fair value based method for all awards,
	net of related tax effects			396		579		560		1,186
		Pro forma net income (loss)	$	(1,195)	$	2,376	$	(4,451)	$	26,579
Earnings (loss) per share:
	Basic and diluted - as reported		$	(0.02)	$	0.08	$	(0.10)	$	0.74
	Basic and diluted - pro forma			(0.03)		0.06		(0.12)		0.71

Adopted Accounting Pronouncements
On January 1, 2003, IDACORP and IPC adopted SFAS 143, "Accounting for Asset Retirement Obligations." 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. SFAS 143 requires an entity to record the fair value of a liability for an asset retirement obligation (ARO) in the period in which it is incurred. When the liability is initially recorded, the entity increases the carrying amount of the related long-lived asset to reflect the future retirement cost. Over time, the liability is accreted to its present value and paid, and the capitalized cost is depreciated over the useful life of the related asset. If at the end of the asset's life the recorded liability differs from the actual obligations paid, a gain or loss would be recognized. As a rate-regulated entity, IPC recorded regulatory assets and liabilities instead of accretion, depreciation and gains or losses, and expects to apply for accounting orders from the Idaho Public Utilities Commission (IPUC) and the Oregon Public Utility Commission (OPUC) supporting such treatment.

IPC and IDACORP performed detailed assessments of the applicability and implications of SFAS 143, and AROs related to two of IPC's jointly owned coal-fired generation facilities and IPC's transmission and distribution facilities, have been identified. IPC recorded an ARO of $7 million, an asset of $2 million, accumulated depreciation of $1 million and a regulatory asset of $6 million. These amounts do not include an amount for the transmission and distribution facilities because, based on the indeterminate life of these assets, an ARO calculation cannot be made. The regulated operations of IPC also collect removal costs in rates for certain assets that do not have associated legal AROs. The adoption of SFAS 143 required IPC to redesignate these removal costs as regulatory liabilities. As of June 30, 2003, IPC estimated that it had approximately $139 million of such regulatory liabilities recorded in Accumulated Provision for Depreciation.

Also, an ARO exists for the reclamation of the Bridger Coal mine property, which is leased by Bridger Coal Company, an equity-method investee of IPC. Because Bridger Coal has a March 31, 2003 fiscal year end, it adopted SFAS 143 on April 1, 2003. Upon adoption of SFAS 143, IPC did not record a net change in its investment in Bridger Coal, as Bridger Coal also expects to apply regulatory accounting, recording regulatory assets and liabilities instead of accretion, depreciation and gains or losses.

If the conditions of SFAS 143 had been applied to the consolidated balance sheets at December 31, 2002 and 2001, IDACORP's and IPC's liability for AROs would have been $7 million and $6 million, respectively.

In May 2003, the Financial Accounting Standards Board (FASB) issued SFAS 150, "Accounting for Certain Financial Instruments with Characteristics of both Liabilities and Equity," which establishes standards for how an issuer classifies and measures certain financial instruments with characteristics of both liabilities and equity. SFAS 150 requires that an issuer classify a financial instrument that is within its scope as a liability (or an asset in some circumstances). Many of those instruments were previously classified as equity. SFAS 150 is effective for financial instruments entered into or modified after May 31, 2003, and otherwise is effective at the beginning of the first interim period beginning after June 15, 2003. The adoption of SFAS 150 did not have a material effect on IDACORP's or IPC's financial statements.

New Accounting Pronouncement
In April 2003, the FASB issued SFAS 149, "Amendment of Statement 133 on Derivative Instruments and Hedging Activities," which amends and clarifies accounting for derivative instruments, including certain derivative instruments embedded in other contracts, and for hedging activities under SFAS 133, "Accounting for Derivative Instruments and Hedging Activities."

SFAS 149 amends SFAS 133 for decisions made:

as part of the Derivatives Implementation Group process that effectively required amendments to SFAS 133,
in connection with other FASB projects dealing with financial instruments, and
regarding implementation issues raised in relation to the application of the definition of a derivative, particularly regarding the meaning of an "underlying" and the characteristics of a derivative that contains financing components.

SFAS 149 is effective for contracts entered into or modified after June 30, 2003, except as stated below and for hedging relationships designated after June 30, 2003. The guidance should be applied prospectively.

The provisions of SFAS 149 that relate to SFAS 133 Implementation Issues that have been effective for fiscal quarters that began prior to June 15, 2003, should continue to be applied in accordance with their respective effective dates.

IDACORP and IPC are currently assessing, but have not yet determined the impact of SFAS 149 on their financial statements.

In January 2003, the FASB issued Interpretation (FIN) 46, "Consolidation of Variable Interest Entities - an Interpretation of ARB No. 51." This interpretation provides guidance related to identifying variable interest entities (VIEs, previously known as special purpose entities or SPEs) and determining whether such entities should be consolidated. Certain disclosures are required if it is reasonably possible that a company will consolidate or disclose information about a VIE when it initially applies FIN 46. This interpretation must be applied immediately to VIEs created or obtained after January 31, 2003. During the first six months of 2003, IDACORP did not participate in the creation of, or obtain a new variable interest in, any VIE. For those VIEs created or obtained on or before January 31, 2003, IDACORP must apply the provisions of FIN 46 in the third quarter of 2003.

IDACORP is in the final stages of completing the adoption of FIN 46 and the majority of its investments are not expected to meet the criteria for consolidation included in FIN 46. Having considered the facts described herein, IDACORP does not expect the adoption of this standard to have a material impact on its financial statements.

Reclassifications
Certain items previously reported for periods prior to June 30, 2003 have been reclassified to conform to the current year's presentation. Net income and shareholders' equity were not affected by these reclassifications.

2. INCOME TAXES:

IDACORP uses an estimated annual effective tax rate for computing its provision for income taxes on an interim basis. IDACORP's effective tax rate for the six months ended June 30, 2003 and 2002 was zero percent. The zero percent rate for the six months ended June 30, 2002 reflected the expectation that tax expense by year-end 2002 would be zero. For 2003, IDACORP has projected annual pre-tax income but has also projected an annual income tax benefit (a negative effective tax rate). The income tax benefit results primarily from the realization of low-income housing tax credits.

Due to the fact that IDACORP has reported a pre-tax loss in the first two quarters of 2003, it has not applied the negative estimated annual effective tax rate to these pre-tax loss periods. IDACORP will recognize the income tax benefit during the periods when the pre-tax income is earned, which is projected to be in the last six months of 2003.

3. CAPITAL STOCK:

Common Stock
During the six months ended June 30, 2003, IDACORP issued 122,990 shares of common stock for its Dividend Reinvestment Plan and 65,932 shares for its Employee Savings Plan. In addition, IDACORP purchased 35,200 treasury shares and issued 26,094 treasury shares for its restricted stock plan.

Preferred Stock of Idaho Power Company
During the six months ended June 30, 2003, IPC reacquired and retired 8,305 shares of 4% preferred stock.

4. FINANCING:

The following table summarizes long-term debt at (in thousands of dollars):

			June 30,		December 31,
			2003		2002
First mortgage bonds:
	6.40% Series due 2003		$	-	$	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
	4.75% Series due 2012			100,000		100,000
	4.25% Series due 2013			70,000		-
	7.50% Series due 2023			-		80,000
	6 % Series due 2032			100,000		100,000
	5.50% Series due 2033			70,000		-
		Total first mortgage bonds		730,000		750,000
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 2027			4,360		4,360
		Total pollution control revenue bonds		170,460		170,460

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				(2,310)		(2,405)

Debt related to investments in low-income housing				32,877		37,428

Tax credit notes				22,745		-

Other subsidiary debt				7		15
	Total			986,509		988,268
Current maturities of long-term debt				(62,788)		(89,592)

		Total long-term debt	$	923,721	$	898,676

IDACORP currently has two shelf registration statements totaling $800 million that can be used for the issuance of unsecured debt (including medium-term notes) and preferred or common stock. At June 30, 2003, none had been issued.

On March 14, 2003, IPC filed a $300 million shelf registration statement that could be used for first mortgage bonds (including medium-term notes), unsecured debt and preferred stock. On May 8, 2003, IPC issued $140 million of secured medium-term notes, which were divided into two series. The first was $70 million First Mortgage Bonds 4.25% Series due 2013 and the second was $70 million First Mortgage Bonds 5.50% Series due 2033. Proceeds were used to pay down IPC short-term borrowings incurred from the maturity and payment of $80 million First Mortgage Bonds 6.40% Series due 2003 and the early redemption of $80 million First Mortgage Bonds 7.50% Series due 2023, on May 1, 2003. At June 30, 2003, $160 million remain available to be issued on this shelf registration statement.

IDACORP has a $175 million credit facility that expires on March 19, 2004, and a $140 million credit facility that expires on March 25, 2005. 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 bank credit facilities. At June 30, 2003, IDACORP's short-term borrowings totaled $110 million.

At June 30, 2003, IPC had regulatory authority to incur up to $250 million of short-term indebtedness. IPC has a $200 million credit facility that expires on March 19, 2004. Under this facility IPC pays a facility fee on the commitment, quarterly in arrears, based on IPC's corporate credit rating. IPC's commercial paper may be issued up to the amounts supported by the bank credit facilities. At June 30, 2003, IPC's short-term borrowings totaled $9 million.

The following tax credit notes have been issued by IFS during 2003 (in thousands of dollars):

		Principal		Interest
Issue Date	Series	Amount		Rate	Maturity
March 12, 2003	2003-1	$	25,475	5.00%	2003 - 2010
July 15, 2003	2003-2		15,000	3.98%	2003 - 2009

Additionally, $25 million of debt was secured by IFS from a corporate lender on July 25, 2003 at an interest rate of 3.65 percent, maturing from 2003-2008.

Proceeds from the issuance of these debt instruments were primarily used to pay intercompany notes to IDACORP. IDACORP used these proceeds to pay short-term borrowings. The debt for series 2003-1 is non-recourse to both IFS and IDACORP. The debt for the remaining two issuances is recourse only to IFS.

5. COMMITMENTS AND CONTINGENT LIABILITIES:

From time to time IDACORP and IPC are a party to various other legal claims, actions and complaints not discussed below. IDACORP and IPC believe that they have defenses to all lawsuits and legal proceedings in which they are defendants and will vigorously defend against them, although they are unable to predict with certainty whether or not they will ultimately be successful. However, based on the companies' evaluations, they believe that the resolution of these matters will not have a material adverse effect on their consolidated financial positions, results of operations or cash flows.

Legal Proceedings
United Systems, Inc., f/k/a Commercial Building Services, Inc.: On March 18, 2002, United Systems, Inc. (United Systems) filed a complaint in Idaho State District Court in and for the County of Ada against IDACORP Services Co., a subsidiary of IDACORP, dba IDACORP Solutions. United Systems is a heating, ventilation, refrigeration and plumbing contracting company that entered into a contract with IDACORP Services in December 2000.

Under the terms of the contract, IDACORP Services authorized United Systems to do business as "IDACORP Solutions." The contract was to be effective from January 2001 through December 2005.

In November 2001, IDACORP Services notified United Systems that IDACORP Services was terminating the contract for convenience. The contract allowed for such termination but required the terminating party to compensate the other party for all costs incurred in preparation for, and in performance of the contract, and for reasonable net profit for the remaining term of the contract. United Systems claims $7 million in net profits lost and costs incurred.

IDACORP Services asserts that termination related compensation owed to United Systems, if any, is substantially less than the amount claimed by United Systems.

On August 8, 2002, United Systems filed an amended complaint adding IDACORP, IE and IPC as additional defendants claiming they should be held jointly and severally liable for any judgment entered against IDACORP Services. The parties in this matter agreed to delay the jury trial set for June 13, 2003 and reset it to begin on November 10, 2003.

On October 4, 2002, United Systems filed a Motion for Partial Summary Judgment as to their damages. United Systems has estimated their damages to be approximately $7 million as stated above. Oral argument on the motion was heard on November 21, 2002. No decision has been entered on the Motion for Partial Summary Judgment.

The companies intend to vigorously defend their position in this proceeding and believe these matters will not have a material adverse effect on their consolidated financial positions, results of operations or cash flows.

Public Utility District No. 1 of Grays Harbor County, Washington: On October 15, 2002, Public Utility District No. 1 of Grays Harbor County, Washington (Grays Harbor) filed a lawsuit in the Superior Court of the State of Washington, for the County of Grays Harbor, against IDACORP, IPC and IE. On March 9, 2001, Grays Harbor entered into a 20 megawatt (MW) purchase transaction with IPC for the purchase of electric power from October 1, 2001 through March 31, 2002, at a rate of $249 per megawatthour (MWh). In June 2001, with the consent of Grays Harbor, IPC assigned all of its rights and obligations under the contract to IE. In its lawsuit, Grays Harbor alleged that the assignment was void and unenforceable, and sought restitution from IE and IDACORP, or in the alternative, Grays Harbor alleged that the contract should be rescinded or reformed. Grays Harbor sought as damages an amount equal to the difference between $249 per MWh and the "fair value" of electric power delivered by IE during the period October 1, 2001 through March 31, 2002.

IDACORP, IPC and IE had this action removed from the state court to the United States District Court for the Western District of Washington at Tacoma. On November 12, 2002, the companies filed a motion to dismiss Grays Harbor's complaint, asserting that the Federal District Court lacked jurisdiction as the matter is preempted under the Federal Power Act (FPA) by the FERC. The court ruled in favor of the companies' motion to dismiss and dismissed the case with prejudice on January 28, 2003. On February 25, 2003, Grays Harbor filed a Notice of Appeal, appealing the final judgment of dismissal to the United States Court of Appeals for the Ninth Circuit, and briefing is in progress. The companies intend to vigorously defend their position on appeal and believe this matter will not have a material adverse effect on their consolidated financial position, results of operations or cash flows.

State of California Attorney General: The California Attorney General (AG) filed the complaint in this case in the California Superior Court in San Francisco on May 30, 2002. This is one of thirteen virtually identical cases brought by the AG against various sellers of power in the California market, seeking civil penalties pursuant to California's unfair competition law - - California Business and Professions Code Section 17200. Section 17200 defines unfair competition as any "unlawful, unfair or fraudulent business act or practice . . .." The AG alleges that IPC engaged in unlawful conduct by violating the FPA in two respects: (1) by failing to file its rates with the FERC as required by the FPA; and (2) charging unjust and unreasonable rates in violation of the FPA. The AG alleged that there were "thousands of . . . sales or purchases" for which IPC failed to file its rates, and that IPC charged unjust and unreasonable rates on "thousands of occasions." Pursuant to Business and Professions Code Section 17206, the AG seeks civil penalties of up to $2,500 for each alleged violation. On June 25, 2002, IPC removed the action to federal court, and on July 25, 2002, the AG filed a motion to remand back to state court. On March 25, 2003, the Court denied the AG's motion to remand and granted IPC's motion to dismiss the case based upon grounds of federal preemption and the filed rate doctrine. On March 28, 2003, the AG filed a Notice of Appeal, appealing from the Court's final judgment dismissing the action to the United States Court of Appeals for the Ninth Circuit. Appellate briefs are due to be filed on August 13, 2003 with IPC's brief due on September 12, 2003. IPC intends to vigorously defend its position on appeal and believes this matter will not have a material adverse effect on its consolidated financial position, results of operations or cash flows.

Wholesale Electricity Antitrust Cases I & II: These cross-actions against IE and IPC emerge from multiple California state court proceedings first initiated in late 2000 against various power generators/marketers by various California municipalities and citizens, including California Lieutenant Governor Cruz Bustamante and California legislator Barbara Matthews in their personal capacities. Suit was filed against entities including Reliant Energy Services, Inc., Reliant Ormond Beach, L.L.C., Reliant Energy Etiwanda, L.L.C., Reliant Energy Ellwood, L.L.C., Reliant Energy Mandalay, L.L.C. and Reliant Energy Coolwater, L.L.C. (collectively, Reliant); and Duke Energy Trading and Marketing, L.L.C., Duke Energy Morro Bay, L.L.C., Duke Energy Moss Landing, L.L.C., Duke Energy South Bay, L.L.C. and Duke Energy Oakland, L.L.C. (collectively, Duke). While varying in some particulars, these cases made a common claim that Reliant, Duke and certain others (not including IE or IPC) colluded to influence the price of electricity in the California wholesale electricity market. Plaintiffs asserted various claims that the defendants violated California Antitrust Law (the Cartwright Act), Business & Professions Code Section 16720, et seq., and California's Unfair Competition Law, Business & Professions Code Section 17200, et seq. Among the acts complained of are bid rigging, information exchanges, withholding of power and various other wrongful acts. These actions were subsequently consolidated, resulting in the filing of Plaintiffs' Master Complaint (PMC) in San Diego Superior Court on March 8, 2002.

On April 22, 2002, more than a year after the initial complaints had been filed, two of the original defendants, Duke and Reliant, filed separate cross-complaints against IPC and IE, and approximately 30 other cross-defendants. Duke and Reliant's cross-complaints seek indemnity from IPC, IE and the other cross-defendants for an unspecified share of any amounts they must pay in the underlying suits because, they allege, other market participants like IPC and IE engaged in the same conduct at issue in the PMC. Duke and Reliant also seek declaratory relief as to the respective liability and conduct of each of the cross-defendants in the actions alleged in the PMC. Reliant has also asserted a claim against IPC for alleged violations of the California Unfair Competition Law, Business and Professions Code Section 17200, et seq. As a buyer of electricity in California, Reliant seeks the same relief from the cross-defendants, including IPC, as that sought by plaintiffs in the PMC as to any power Reliant purchased through the California markets.

Some of the newly added defendants (foreign citizens and federal agencies) removed that litigation to federal court. IPC and IE, together with numerous other defendants added by the cross-complaints, moved to dismiss these claims, and those motions were heard in September 2002, together with motions to remand the case back to state court filed by the original plaintiffs. On December 13, 2002, the Federal District Court granted Plaintiffs' Motion to Remand to State Court but did not issue a ruling on IPC and IE's motion to dismiss. The Ninth Circuit has granted certain Defendants and Cross-Defendants' Motions to Stay the Remand Order while they appeal the Order. An expedited briefing schedule was also ordered. As a result of the various motions, no trial date is set at this time. The companies cannot predict the outcome of this proceeding, nor can they evaluate the merits of any of the claims at this time but they intend to vigorously defend this lawsuit.

Idaho Rivers United: On December 10, 2002, Idaho Rivers United filed a complaint against IPC in U.S. District Court for the District of Idaho. In the complaint, Idaho Rivers United alleged that IPC violated the Clean Water Act by discharging an amount of dredged and fill material into the navigable waters of the Snake River in excess of that allowed by a Section 404 permit issued by the U.S. Army Corps of Engineers. The action relates to work completed by IPC, pursuant to a Section 404 permit issued by the Corps on September 3, 1999, in the area of the tailrace downstream of IPC's Bliss hydroelectric project on the Snake River in Idaho. Idaho Rivers United asked the court to impose civil penalties on IPC under sections 309(d) and 505(a) of the Clean Water Act to require IPC to pay for any remedial or restoration

work necessary to amend any environmental harm caused by the alleged violation and to pay reasonable attorney fees.

On March 28, 2003, IPC and Idaho Rivers United entered into a consent decree resolving the disputed allegations of the complaint. Under the terms of the consent decree, IPC, without admitting liability, agreed to contribute the sum of $86,800, in three equal annual payments, to The Nature Conservancy (TNC), an internationally recognized non-profit organization specializing in habitat restoration and protection, to be used for design, management and construction of TNC's proposed Blind Canyon and Thousand Springs wetlands projects on the Snake River in Idaho. These projects have a positive impact on water quality in the Snake River by removing sediments and nutrients from irrigation canal waters before they are returned to the river. IPC also agreed to pay attorney fees incurred by Idaho Rivers United in the amount of $15,000.

The federal court entered the consent decree on April 26, 2003. IPC submitted the first installment of $28,933 to TNC on May 28, 2003. Subsequent installments are due on or before January 15, 2004 and 2005.

California Energy Proceedings at the FERC:
California Power Exchange Chargeback
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 defaulted on a payment to the exchange, the other participants were required to pay their allocated share of the default amount to the exchange. The allocated shares were based upon the level of trading activity, which included 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 million - a "default share invoice" - as a result of an alleged Southern California Edison (SCE) payment default of $215 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 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 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 the CalPX and the California Independent System Operator (Cal ISO) 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 the FERC to intervene in a proceeding that 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 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.

The FERC issued an order on April 6, 2001 requiring the CalPX to rescind all chargeback actions related to PG&E's and SCE's liabilities. Shortly after that time, the CalPX segregated the CalPX chargeback amounts it had collected in a separate account. The CalPX claims it is awaiting further orders of the FERC and the bankruptcy court before distributing the funds that it collected under its chargeback tariff mechanism. Although certain parties to the California refund proceeding urged the FERC's Presiding Administrative Law Judge (ALJ) to consider the chargeback amounts in his determination of who owes what to whom, in his Certification of Proposed Findings on California Refund Liability, he concluded that the matter already was pending before the FERC for disposition.

California Refund
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 spot market sales prices if the FERC determined that those prices were not just and reasonable, and therefore not in compliance with the FPA. The June 19 order 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's Chief ALJ 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.

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, IE believes its exposure is likely to be offset by amounts due from California entities. Multiple parties have filed requests for rehearing and petitions for review. The latter, more than 60, have been consolidated by the United States Court of Appeals for the Ninth Circuit and held in abeyance while the FERC continues its deliberations. The Ninth Circuit also directed the FERC to permit the parties to adduce additional evidence respecting market manipulation. See "Market Manipulation" below.

This case had been further complicated by an August 13, 2002 FERC staff (Staff) Report which included the recommendation to replace the published California indices for gas prices that the FERC previously established as just and reasonable for calculating a Mitigated Market Clearing Price (MMCP) to calculate refunds with other published indices for producing basin prices plus a transportation allowance. Staff's recommendation is grounded on speculation that some sellers had an incentive to report exaggerated prices to publishers of the indices, resulting in overstated published index prices. Staff based its speculation in large part on a statistical correlation analysis of Henry Hub and California prices. IE, in conjunction with others, submitted comments on the Staff recommendation - asserting that Staff's conclusions were incorrect because the Staff's correlation study ignored evidence of normal market forces and scarcity that created the pricing variations that Staff observed, rather than improper manipulation of reported prices.

The ALJ issued a Certification of Proposed Findings on California Refund Liability on December 12, 2002. The FERC has indicated the intention to largely conclude work on the California refund matters, including the ALJ's decision, the gas pricing component of its MMCP methodology and claims of market manipulation.

The FERC issued its Order on Proposed Findings on Refund Liability on March 26, 2003. In large part, the FERC affirmed the recommendations of its ALJ. However, the FERC changed a component of the formula the ALJ was to apply when it adopted findings of its staff that published California spot market prices for gas did not reliably reflect the prices a gas market that had not been manipulated would have produced, despite the fact that many gas buyers paid those amounts. The findings of the ALJ, as adjusted by the FERC's March 26, 2003 order, are expected to substantially increase the offsets to amounts still owed by the Cal ISO and the CalPX to the companies. Calculations remain uncertain because the FERC has required the Cal ISO to correct a number of defects in its calculations and because the FERC has stated that if refunds will prevent a seller from recovering its California portfolio costs during the refund period, it will provide an opportunity for a cost showing by such a respondent. As a result, IE is unsure of the impact this ruling will have on the refunds due from California.

IE, along with a number of other parties, filed a petition with the FERC on April 25, 2003 seeking review of the March 26, 2003 order.

In June 2001, IPC transferred its non-utility wholesale electricity marketing operations to IE. Effective with this transfer, the outstanding receivables and payables with the CalPX and Cal ISO were assigned from IPC to IE. At June 30, 2003, with respect to the CalPX chargeback and the California Refund proceedings, discussed above, the CalPX and Cal ISO owed $14 million and $30 million, respectively, for energy sales made to them by IPC in November and December 2000. IE has accrued a reserve of $42 million against these receivables.

This reserve was calculated taking into account the uncertainty of collection, given the California energy situation. Based on the reserve recorded as of June 30, 2003, IDACORP believes that the future collectibility of these receivables or any potential refunds ordered by the FERC would not have a significant impact on its consolidated financial position, results of operations or cash flows.

Market Manipulation
In a November 20, 2002 order the FERC permitted discovery and the submission of evidence respecting market manipulation by various sellers during the western power crises of 2000 and 2001.

On March 3, 2003, the California Parties (the investor owned utilities, the California Attorney General, the California Electricity Oversight Board and the California Public Utilities Commission) filed voluminous documentation asserting that a number of wholesale power suppliers, including IE and IPC had engaged in one of a variety of forms of conduct that the California Parties contended were impermissible. Although the contentions of the California Parties were contained in more than 11 compact discs of data and testimony, approximately 12,000 pages, IE and IPC were mentioned in limited contexts-the overwhelming majority of the claims of the California Parties related to claims respecting the conduct of other parties.

As a consequence, the California Parties urged the FERC to apply the precepts of its earlier decision, to replace actual prices charged in every hour starting May 1, 2000 through the beginning of the existing refund period (October 2, 2000) with a MMCP, seeking approximately $8 billion in refunds to the Cal ISO and the CalPX. On March 20, 2003, numerous parties, including the companies, submitted briefs and responsive testimony.

In its March 26, 2003 order, discussed above, the FERC declined to generically apply its refund determinations across the board to sales by all market participants, although it stated that it reserved the right to provide remedies for the market against parties shown to have engaged in proscribed conduct.

On June 25, 2003, the FERC ordered over 50 entities that participated in the western wholesale power markets between January 1, 2000 and June 20, 2001, including IPC, to show cause why certain trading practices did not constitute gaming or anomalous market behavior in violation of the Cal ISO and CalPX tariffs. The Cal ISO was ordered to provide data on each entity's trading practices within 21 days of the order, and each entity must respond explaining their trading practices within 45 days of receipt of the Cal ISO data. With respect to IPC, the amounts in controversy do not appear to be material and the FERC has encouraged parties to settle these matters with the FERC Trial Staff. The FERC also issued an order instituting an internal investigation of Anomalous Bidding Behavior and Practices in the Western Wholesale Power Markets. In this investigation, the FERC will review evidence of alleged economic withholding of generation. The FERC has determined that all bids into the CalPX and Cal ISO markets for more than $250 per MWh for the time period May 1, 2000 through October 1, 2000 will be considered prima facie evidence of economic withholding. The FERC has issued data requests in this investigation to over 60 market participants including IPC. If alleged violations in the show cause orders are proven or it is determined that IPC engaged in improper bidding, the FERC has indicated that sanctions may include disgorgement of alleged profits and other non-monetary actions, including possible revocation of market based rate authority and/or additional required provisions in codes of conduct. IPC has received some information regarding these matters from the Cal ISO and is in the process of preparing responses to the FERC. Based on the information received to date from the Cal ISO, IDACORP and IPC believe that any potential penalties imposed by the FERC would not have a significant impact on their consolidated financial position, results of operations or cash flows.

Pacific Northwest Refund: On July 25, 2001, the FERC issued an order establishing 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 ALJ submitted recommendations and findings to the FERC on September 24, 2001. The ALJ found that prices should be governed by the Mobile-Sierra standard of the public interest rather than the just and reasonable standard, that the Pacific Northwest spot markets were competitive and that no refunds should be allowed. Procedurally, the ALJ's decision is a recommendation to the commissioners of the FERC. Multiple parties have submitted comments to the FERC respecting the ALJ's recommendations. The ALJ's recommended findings had been pending before the FERC, when at the request of the City of Tacoma and the Port of Seattle on December 19, 2002, the FERC reopened the proceedings to allow the submission of additional evidence related to alleged manipulation of the power market by Enron and others. IE opposed that request. As was the case in the California refund proceeding, at the conclusion of the discovery period, parties alleging market manipulation were to submit their claims to the FERC and responses were due on March 20, 2003. Grays Harbor, whose civil litigation claims were dismissed, as noted above, has intervened in this FERC proceedings asserting on March 3, 2003 that its six month forward contract, for which performance has been completed, should be treated as a spot market contract for purposes of the FERC's consideration of refunds and requesting refunds from IPC of $5 million. Grays Harbor did not suggest that there was any misconduct by the company. The company submitted responsive testimony defending vigorously against Grays Harbor's refund claims.

In addition, the Port of Seattle, the City of Tacoma and Seattle City Light made filings with the FERC on March 3, 2003 claiming that because some market participants drove prices up throughout the west through acts of manipulation, prices for contracts throughout the Pacific Northwest market should be re-set starting in May 2000 using the same factors the FERC would use for California markets. Although the majority of the claims of these parties are generic, they named a number of power market suppliers, including IPC and IE, as having used parking services provided by other parties under FERC-approved tariffs and thus as being candidates for claims of having received incorrectly congestion revenues from the Cal ISO. On June 25, 2003, after having considered oral argument held earlier in the month, the FERC issued its Order Granting Rehearing, Denying Request to Withdraw Complaint and Terminating Proceeding, in which it terminated the proceeding and required that no refunds be paid. The order remains subject to rehearing by the FERC and review by appellate courts. The companies are unable to predict the outcome of this matter.

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 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 described their view of rights under the WSPP Agreement and suggested a negotiated resolution. IE and NPC unsuccessfully attempted to mediate a resolution to this dispute.

IE filed a complaint on April 25, 2003, against NPC in Idaho State District Court in and for the County of Ada. This complaint was served on NPC on May 14, 2003. IE asked the Idaho State District Court for damages in excess of $9 million pursuant to the contracts. On June 17, 2003, NPC filed a Motion to Dismiss IE's complaint, alleging, among other allegations, that: the Idaho State District Court lacks jurisdiction over NPC; a separate complaint seeking declaratory judgment was filed in Nevada Federal District Court on May 14, 2003, by NPC against IPC, IE and IDACORP, involving the same subject matter as the complaint filed by IE against NPC; IE does not have standing to maintain certain of its claims against NPC; Idaho is not a convenient forum to adjudicate the matter; and IE filed the action in Idaho State District Court in violation of the contracts. The Idaho State District Court has not ruled on NPC's Motion.

IE intends to vigorously prosecute the action it filed in Idaho State District Court, and IPC, IE and IDACORP intend to vigorously defend against the complaint filed against them by NPC in Nevada Federal District Court.

At June 30, 2003, IE had a $4 million receivable related to the NPC claim.

Washington Retail Consumer Class Action Complaint: The complaint in this case was filed on December 20, 2002 in the United States District Court for the Western District of Washington at Seattle, against various entities, including IPC. The complaint was served on IPC on February 3, 2003. This action seeks class action status on behalf of all persons and businesses residing in Washington who were purchasers of electrical and/or natural gas energy from any period beginning in January 2000 to the present. The complaint alleges claims under the Washington Consumer Protection Act, RCW 19.86, as well as common law claims of fraud by concealment, negligence and requests an accounting. The complaint asserts that the defendants, including IPC, engaged in, among other things, unfair and deceptive acts, in violation of the FPA, by (a) withholding the supply of energy; (b) misrepresenting the amount of its energy supplies; (c) exercising improper control over the energy markets; and (d) manipulating the price of energy markets resulting in energy rates being unjust, unreasonable and unlawful. The plaintiff seeks certification of a class action, equitable and injunctive relief, an accounting, treble damages, attorneys' fees and costs. On February 3, 2003, another defendant, Reliant, moved to transfer the case to the Judge who is presiding over Multiple District Litigation (MDL) No. 1405. The MDL rejected this request because that Judge, as a Washington resident, is a member of the class. On March 11, 2003, IPC, along with other defendants, filed a motion with the MDL seeking to transfer the case to be consolidated with similar actions before the Judge who is presiding over the California Attorney General Action, and other similar cases. On March 21, 2003, the Court granted IPC's motion for an extension of time to respond to the complaint until 30 days after the MDL panel rules. Subsequently, plaintiffs sought permission from the Court to voluntarily dismiss their claims without prejudice, which the Court granted on May 1, 2003.

Oregon Retail Consumer Class Action Complaint: The complaint in this case was filed on December 16, 2002 in the Circuit Court of the State of Oregon for the County of Multnomah, against various entities, including IPC. The complaint was served on IPC on February 7, 2003. The case was removed by another defendant, Reliant, to the United States District Court, District of Oregon on February 4, 2003. The complaint seeks class action status on behalf of all persons and businesses residing in Oregon who were purchasers of electrical and/or natural gas energy from any period beginning in January 2000 to the present. The complaint alleges claims under the Oregon Unfair Trade Practices Act, ORS 646.605 et seq. in addition to claims of fraud by concealment, negligence and requests an accounting. The complaint asserts that the defendants, including IPC, engaged in, among other things, unfair and deceptive acts, in violation of the FPA, by (a) withholding the supply of energy; (b) misrepresenting the amount of its energy supplies; (c) exercising improper control over the energy markets; and (d) manipulating the price of energy markets resulting in energy rates being charged to Oregon energy consumers that were unjust, unreasonable and unlawful. The plaintiff seeks certification of a class action, equitable and injunctive relief, an accounting, attorneys' fees and costs. The action was removed to federal court, and on March 11, 2003, IPC, along with other defendants, filed a motion with the MDL seeking to transfer the case to be consolidated with similar actions before the Judge who is presiding over the California Attorney General Actions, and other similar cases. A stipulation has been submitted to the Court for an extension of time to respond to the complaint, until 30 days after the MDL panel rules. Subsequently, plaintiffs sought permission from the Court to voluntarily dismiss their claims without prejudice, which the Court granted on May 5, 2003.

Enron Bankruptcy Case: When Enron Corporation and certain of its affiliates, including Enron Power Marketing, Inc. (EPMI) and Enron North America Corp. (ENA) (collectively, Enron) petitioned for bankruptcy protection in December 2001, IE and IPC exercised their rights to terminate all contracts with Enron. During October 2002, IE submitted claims in the Enron bankruptcy proceeding for net pre-petition obligations owed by Enron to IE of approximately $17 million, primarily for power and energy delivered prior to the Enron bankruptcy. IE also asserted various contingent and unliquidated claims against Enron. IE acknowledged in its claims that there are also monetary values associated with the forward contracts for post-petition deliveries that were terminated, which, when analyzed separately, may result in a substantial net liability to Enron after setoff of such pre-petition obligations.

On November 13, 2002, IE received demand letters from EPMI and ENA asserting that IE's net liability, including interest, amounted to approximately $44 million to EPMI and $3 million to ENA, as of that date. IPC received a similar demand letter from EPMI asserting a net amount owed to EPMI of approximately $1 million.

For several months, IE and IPC attempted to reach agreement with Enron, under a non-disclosure and confidentiality agreement, on appropriate values for both the pre-petition and forward obligations in order to calculate a net termination payment value and negotiate a mutually agreed upon net settlement value. However, on February 27, 2003, IE received a complaint filed by EPMI in the U.S. Bankruptcy Court, Southern District of New York. The complaint asserted that EPMI was entitled to a net termination payment of approximately $39 million, plus interest from the termination date. The complaint asked for declaratory relief and damages and made objections to IE's filed claim.

During March 2003, IE and IPC reached agreement with Enron on both a settlement amount to be paid by IE and IPC and the terms and conditions of a settlement agreement. The settlement agreement also contains certain confidentiality requirements. IE and IPC executed and delivered the settlement agreement to Enron on March 31, 2003. The settlement agreement was approved by the U.S. Bankruptcy Court on May 15, 2003, and all payments and other actions required under the settlement agreement have been completed. Pursuant to the settlement agreement, the Enron complaint against IE was dismissed with prejudice by order of the Bankruptcy Court on May 15, 2003.

As a result of the settlement, IE recognized a gain during March 2003, which was recorded in "Net (gain) loss on legal disputes" in the Consolidated Statement of Operations for the first quarter of 2003.

Port of Seattle: On May 21, 2003, the Port of Seattle, a Washington municipal corporation, filed a lawsuit against 20 energy firms, including IPC and IDACORP, in the United States District Court for the Western District of Washington at Seattle. The Port of Seattle's complaint alleges fraud and violations of state and federal antitrust law and the Racketeering Influenced and Corrupt Organization Act. There are currently several procedural motions pending, and IDACORP's and IPC's responses to the Port of Seattle's complaint are due to be filed August 20, 2003. Both companies intend to vigorously defend against the Port of Seattle's complaint.

6. REGULATORY MATTERS:

Wind Down of Energy Marketing
IDACORP announced in 2002 that IE would wind down its energy marketing operations. In connection with the wind down, certain matters were identified that required resolution with the FERC and the IPUC. IE and IPC voluntarily contacted the FERC in September 2002 to discuss these matters.

The FERC matters have been resolved by the issuance of two FERC orders:

On February 26, 2003, the FERC issued an order approving the assignment of certain wholesale power and transmission services agreements from IPC to IE. The FERC also found that IPC violated Section 203 of the FPA by assigning the agreements in June 2001 without seeking prior approval from the FERC. The FERC noted that noncompliance with Section 203 of the FPA may prompt the FERC in certain instances to impose remedies as a condition of its approval; however, no such remedies were imposed in this order.

On May 16, 2003, the FERC issued an order approving a stipulation and consent agreement resolving issues regarding access to IPC's transmission system, IPC's noncompliance with Sections 203 and 205 of the FPA, standards of conduct and codes of conduct. The order provided for (1) the refund of $0.3 million to certain counterparties associated with the inappropriate use of native load priority and for failure to obtain FERC approval prior to assigning certain contracts from IPC to IE, (2) the transfer of $5.8 million in benefits from IE to IPC as the result of certain transactions between the affiliates and (3) the implementation of certain compliance and auditing programs to ensure future compliance with FERC requirements.

In an IPUC proceeding that has been underway since May 2001, IPC, the IPUC staff and several interested customer groups have been working to determine the appropriate compensation IE should provide to IPC as a result of transactions between the affiliates. The IPUC has issued several orders since then regarding these matters. Order No. 28852 issued on September 28, 2001 covered the time period prior to February 2001. Order No. 29026 covered the time period from March 2001 through March 2002. The IPUC also approved IPC's ongoing hedging and risk management strategies in Order No. 29102 issued on August 28, 2002. This formalized IPC's agreement to implement a number of changes to its existing practices for managing risk and initiating hedging purchases and sales. In the same order, the IPUC directed IPC to present a resolution or a status report to the IPUC on additional compensation due to the utility for the use of its transmission system and other capital assets by IE and any remaining transfer pricing issues. Status reports were filed with the IPUC on December 20, 2002, March 20, 2003 and May 13, 2003 and settlement discussions are actively being pursued. The $5.8 million in benefits related to the FERC settlement have been included in the Power Cost Adjustment (PCA) and credited to Idaho retail customers in accordance with the PCA methodology.

IDACORP and IPC do not believe that resolution of these transactions will have any adverse impact on their ongoing operations. However, because it cannot be predicted at this point what regulatory actions might be taken or when, it cannot be determined what effect there may be on earnings and whether it will be material.

As previously disclosed, the FERC filing made on May 14, 2001, with respect to the pricing of real-time energy transactions between IPC and IE, is still under review by the FERC. For the period June 2001 through March 2002, IE paid IPC approximately $6 million, which was calculated based upon the pricing methodology for the entire period that was most favorable to IPC. This amount was credited to Idaho retail customers through the PCA. An additional $1 million has been paid to IPC for the period April 2002 through July 2002 based upon the same pricing methodology. However, until the FERC takes final action on this filing, rates for real-time transactions between IE and IPC are subject to adjustment.

Oregon Public Utility Commission
On April 29, 2003, the staff of the OPUC issued a report on trading activities during the western energy crisis in 2000-2001 by regulated utilities serving customers in Oregon including Portland General Electric, PacifiCorp and IPC. With respect to IPC, the report reviews positions IPC has taken at the FERC on trading strategies, the FERC proceeding on market manipulation and issues voluntarily disclosed by IE and IPC in September 2002 regarding affiliate transactions. The report acknowledges that IE and IPC have denied participating in the trading strategies. The staff report recommended that staff report back in 90 days regarding whether the OPUC should open a formal investigation of IPC. On June 12, 2003, the OPUC determined to suspend any further consideration of actions relating to IPC until after the IPUC and FERC had concluded their reviews.

Deferred Power Supply Costs
IPC's deferred power supply costs consist of the following at (in thousands of dollars):

			June 30,		December 31,
			2003		2002

Oregon deferral			$	13,949	$	14,172

Idaho PCA current year power supply cost deferrals:
	Deferral during the 2003-2004 rate year			3,934		-
	Deferral during the 2002-2003 rate year			-		8,910
	Astaris load reduction agreement			-		27,160

Idaho PCA true-up awaiting recovery:
	Irrigation and small general service deferral for recovery in
		the 2003-2004 rate year		-		12,049
	Industrial customer deferral for recovery in the 2003-2004 rate year			-		3,744
	Remaining true-up authorized May 2002			-		74,253
	Remaining true-up authorized May 2003			47,091		-

	Total deferral		$	64,974	$	140,288

Idaho: IPC has a PCA mechanism that provides for annual adjustments to the rates charged to its Idaho retail customers. These adjustments, which take effect in May, are based on forecasts of net power supply expenses and the true-up of the prior year's forecast. During the year, 90 percent of the difference between the actual and forecasted costs is deferred with interest. The ending balance of this deferral, called a true-up, is then included in the calculation of the next year's PCA adjustment.

On April 15, 2003, IPC filed its 2003-2004 PCA with the IPUC, and, with a small adjustment to the filing, the rates were approved by the IPUC and became effective on May 16, 2003. As approved, IPC's rates have been adjusted to collect $81 million above 1993 base rates, a $114 million reduction from the 2002-2003 PCA.

Oregon: IPC is also recovering calendar year 2001 extraordinary power supply costs applicable to the Oregon jurisdiction. In two separate 2001 orders, the OPUC approved rate increases totaling six percent, which is the maximum annual rate of recovery allowed under Oregon state law. These increases are recovering approximately $2 million annually. The Oregon deferred balance was $14 million as of June 30, 2003.

7. DERIVATIVE FINANCIAL INSTRUMENTS:

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

			Three Months Ended				Six Months Ended
			June 30,				June 30,
			2003		2002		2003		2002
Gross Margin:
	Realized or otherwise settled		$	11,808	$	21,680	$	10,526	$	51,629
	Unrealized losses			(12,846)		(37,734)		(11,691)		(58,165)
		Total	$	(1,038)	$	(16,054)	$	(1,165)	$	(6,536)

8. INDUSTRY SEGMENT INFORMATION:

IDACORP has identified two reportable operating segments, utility operations and energy marketing. See Note 6 - Regulatory Matters and Note 9 - Restructuring Costs, for discussion on the wind down of energy marketing.

The following table summarizes the segment information for IDACORP's utility operations, energy marketing operations and the total of all other segments, and reconciles this information to total enterprise amounts (in thousands of dollars):

		Utility		Energy						Consolidated
		Operations		Marketing		Other		Eliminations		Total

Three months ended June 30, 2003:
	Revenues	$	197,628	$	(1,053)	$	3,701	$	-	$	200,276
	Net income (loss)		11,767		(4,171)		(8,475)		-		(879)

Total assets at June 30, 2003		$	2,658,771	$	220,976	$	314,935	$	(158,144)	$	3,036,538

Three months ended June 30, 2002:
	Revenues	$	209,581	$	(3,049)	$	3,300	$	-	$	209,832
	Net income (loss)		12,536		(12,087)		2,628		-		3,077

Total assets at December 31, 2002:		$	2,738,493	$	381,690	$	358,471	$	(226,016)	$	3,252,638

Six months ended June 30, 2003:
	Revenues	$	401,050	$	2,540	$	8,614	$	-	$	412,204
	Net income (loss)		25,480		(14,783)		(14,649)		-		(3,952)

Six months ended June 30, 2002:
	Revenues	$	424,681	$	17,931	$	6,813	$	-	$	449,425
	Net income (loss)		34,059		(7,986)		1,699		-		27,772

9. RESTRUCTURING COSTS:

In 2002, IDACORP announced two separate plans to wind down IE's energy marketing operations. The initial announcement, in June 2002, specified that IE would not seek new electric customers; would limit its maximum value at risk to less than $3 million; would target a reduction of working capital requirements to less than $100 million by the end of 2003; and would reduce its workforce at its Boise operations by approximately 50 percent. The second announcement, in November 2002, indicated that IE would close its Denver office by year-end 2002, would shut down its natural gas trading operation in Houston by March 2003, and would further reduce its workforce in its Boise operations through mid-2003. Since these announcements in 2002, IE has reduced its workforce by approximately 83 percent and will continue to reduce its workforce as contractual obligations terminate. The Denver office ceased operations in December 2002 and the Houston office ceased operations in April 2003.

In 2002, IE incurred $5 million of involuntary termination benefit expenses and approximately $4 million of lease termination and other exit-related costs. As of December 31, 2002, IE had paid $2 million of these costs with a remaining outstanding accrual of $7 million. During the three months ended June 30, 2003, $1 million of involuntary termination benefits, lease termination costs and other exit-related costs were paid for a total of $3 million for the six months ended June 30, 2003. The termination benefit expense relates to the termination of 98 employees (primarily energy traders and administrative support positions), 88 of whom had been laid off by June 30, 2003. Nineteen of the 88 employees laid off were hired by other IDACORP subsidiaries, and thus received no severance benefits.

The following table presents the change in accrued restructuring charges during the period (in thousands of dollars).

				Lease
		Severance		Termination
		Benefits		Costs		Other		Total

Balance at December 31, 2002		$	4,171	$	2,485	$	195	$	6,851
	Amounts paid		(2,700)		(371)		(71)		(3,142)
	Amounts reversed		(124)		-		-		(124)
Balance at June 30, 2003		$	1,347	$	2,114	$	124	$	3,585

INDEPENDENT ACCOUNTANTS' REPORT

To the Board of Directors and Shareholders of IDACORP, Inc.
Boise, Idaho

We have reviewed the accompanying consolidated balance sheet of IDACORP, Inc. and subsidiaries as of June 30, 2003, and the related consolidated statements of operations and of comprehensive income (loss) for the three and six month periods ended June 30, 2003 and 2002 and the consolidated statements of cash flows for the six month periods ended June 30, 2003 and 2002. 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, 2002, 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 February 6, 2003, 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, 2002 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
August 6, 2003

Idaho Power Company
Consolidated Statements of Income
(unaudited)

			Three Months Ended
			June 30,
			2003		2002
			(thousands of dollars)
OPERATING REVENUES:
	General business		$	166,613	$	187,564
	Off-system sales			19,839		10,976
	Other revenues			10,813		10,528
		Total operating revenues		197,265		209,068

OPERATING EXPENSES:
	Operation:
		Purchased power		32,019		31,184
		Fuel expense		23,908		21,708
		Power cost adjustment		25,383		42,165
		Other		41,296		36,839
	Maintenance			17,790		16,141
	Depreciation			24,279		23,184
	Taxes other than income taxes			5,251		5,160
		Total operating expenses		169,926		176,381

INCOME FROM OPERATIONS				27,339		32,687

OTHER INCOME:
	Allowance for equity funds used during construction			642		54
	Other - net			1,171		3,835
		Total other income		1,813		3,889

INTEREST CHARGES:
	Interest on long-term debt			13,561		12,237
	Other interest			1,257		2,483
	Allowance for borrowed funds used during construction			(756)		(1,127)
		Total interest charges		14,062		13,593

INCOME BEFORE INCOME TAXES				15,090		22,983

INCOME TAX EXPENSE				2,457		9,149

NET INCOME				12,633		13,834

	Dividends on preferred stock			866		1,298

EARNINGS ON COMMON STOCK			$	11,767	$	12,536

The accompanying notes are an integral part of these statements.

Idaho Power Company
Consolidated Statements of Income
(unaudited)

			Six Months Ended
			June 30,
			2003		2002
			(thousands of dollars)
OPERATING REVENUES:
	General business		$	341,675	$	373,684
	Off-system sales			38,447		31,135
	Other revenues			20,133		18,835
		Total operating revenues		400,255		423,654

OPERATING EXPENSES:
	Operation:
		Purchased power		45,625		61,374
		Fuel expense		49,446		49,636
		Power cost adjustment		77,230		76,225
		Other		78,087		73,683
	Maintenance			31,374		28,161
	Depreciation			48,413		46,355
	Taxes other than income taxes			10,408		10,346
		Total operating expenses		340,583		345,780

INCOME FROM OPERATIONS				59,672		77,874

OTHER INCOME:
	Allowance for equity funds used during construction			1,493		43
	Other - net			5,464		10,964
		Total other income		6,957		11,007

INTEREST CHARGES:
	Interest on long-term debt			28,053		25,554
	Other interest			2,588		4,974
	Allowance for borrowed funds used during construction			(1,576)		(1,320)
		Total interest charges		29,065		29,208

INCOME BEFORE INCOME TAXES				37,564		59,673

INCOME TAX EXPENSE				10,350		22,954

NET INCOME				27,214		36,719

	Dividends on preferred stock			1,734		2,660

EARNINGS ON COMMON STOCK			$	25,480	$	34,059

The accompanying notes are an integral part of these statements.

Idaho Power Company
Consolidated Balance Sheets
(unaudited)

				June 30,		December 31,
				2003		2002
ASSETS				(thousands of dollars)

ELECTRIC PLANT:
	In service (at original cost)			$	3,134,019	$	3,086,965
	Accumulated provision for depreciation				(1,339,762)		(1,294,961)
		In service - Net			1,794,257		1,792,004
	Construction work in progress				97,825		92,481
	Held for future use				2,730		2,335

			Electric plant - Net		1,894,812		1,886,820

INVESTMENTS AND OTHER PROPERTY					42,744		42,272

CURRENT ASSETS:
	Cash and cash equivalents				6,785		12,699
	Receivables:
		Customer			47,694		56,947
		Allowance for uncollectible accounts			(1,303)		(1,566)
		Notes			5,058		4,992
		Employee notes			7,849		7,646
		Related parties			22,864		27,905
		Other			4,220		2,702
	Accrued unbilled revenues				35,404		35,714
	Materials and supplies (at average cost)				21,144		21,458
	Fuel stock (at average cost)				9,619		6,943
	Prepayments				30,102		32,818
	Regulatory assets				15,413		17,147

			Total current assets		204,849		225,405


DEFERRED DEBITS:
	American Falls and Milner water rights				31,585		31,585
	Company-owned life insurance				35,460		35,299
	Regulatory assets				409,452		482,159
	Other				39,869		34,953

			Total deferred debits		516,366		583,996


	TOTAL			$	2,658,771	$	2,738,493

The accompanying notes are an integral part of these statements.

Idaho Power Company
Consolidated Balance Sheets
(unaudited)

				June 30,		December 31,
CAPITALIZATION AND LIABILITIES				2003		2002
				(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			362,046		361,948
		Capital stock expense			(2,691)		(2,710)
		Retained earnings			320,294		330,300
		Accumulated other comprehensive income (loss)			(5,083)		(7,109)

			Total common stock equity		768,597		776,460

	Preferred stock				52,562		53,393

	Long-term debt				880,798		870,741

			Total capitalization		1,701,957		1,700,594

CURRENT LIABILITIES:
	Long-term debt due within one year				50,082		80,084
	Notes payable				8,800		10,500
	Accounts payable				35,693		52,728
	Taxes accrued				79,148		89,090
	Interest accrued				12,406		12,399
	Deferred income taxes				15,392		17,056
	Other				22,371		22,906

			Total current liabilities		223,892		284,763

DEFERRED CREDITS:
	Deferred income taxes				546,283		574,233
	Regulatory liabilities				114,663		114,247
	Other				71,976		64,656

			Total deferred credits		732,922		753,136


COMMITMENTS AND CONTINGENT LIABILITIES

			TOTAL	$	2,658,771	$	2,738,493

The accompanying notes are an integral part of these statements.

Idaho Power Company
Consolidated Statements of Capitalization
(unaudited)

				June 30,				December 31,
				2003		%		2002		%
				(thousands of dollars)
COMMON STOCK EQUITY:
	Common stock			$	94,031			$	94,031
	Premium on capital stock				362,046				361,948
	Capital stock expense				(2,691)				(2,710)
	Retained earnings				320,294				330,300
	Accumulated other comprehensive income (loss)				(5,083)				(7,109)
		Total common stock equity			768,597		45		776,460		46

PREFERRED STOCK:
	4% preferred stock				12,562				13,393
	7.68% Series, serial preferred stock				15,000				15,000
	7.07% Series, serial preferred stock				25,000				25,000
		Total preferred stock			52,562		3		53,393		3

LONG-TERM DEBT:
	First mortgage bonds:
		6.40% Series due 2003			-				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
		4.75% Series due 2012			100,000				100,000
		4.25% Series due 2013			70,000				-
		7.50% Series due 2023			-				80,000
		6 % Series due 2032			100,000				100,000
		5.50% Series due 2033			70,000				-
			Total first mortgage bonds		730,000				750,000
		Amount due within one year			(50,000)				(80,000)
			Net first mortgage bonds		680,000				670,000

	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 2027			4,360				4,360
			Total pollution control revenue bonds		170,460				170,460

	REA notes				1,145				1,185
		Amount due within one year			(82)				(84)
			Net REA notes		1,063				1,101

	American Falls bond guarantee				19,885				19,885

	Milner Dam note guarantee				11,700				11,700

	Unamortized premium/discount - net				(2,310)				(2,405)

			Total long-term debt		880,798		52		870,741		51

TOTAL CAPITALIZATION				$	1,701,957		100	$	1,700,594		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,
				2003		2002
				(thousands of dollars)
OPERATING ACTIVITIES:
	Net income			$	27,214	$	36,719
	Adjustments to reconcile net income to net cash provided by
		operating activities:
		Allowance for uncollectible accounts			(263)		-
		Depreciation and amortization			54,717		52,801
		Deferred taxes and investment tax credits			(29,101)		(19,502)
		Accrued PCA costs			75,314		71,562
		Change in:
			Accounts receivable and prepayments		17,597		(27,411)
			Accrued unbilled revenue		309		(4,315)
			Materials and supplies and fuel stock		(2,362)		(281)
			Accounts payable		(17,041)		(41,265)
			Taxes receivable/accrued		(9,942)		51,356
			Other current assets and liabilities		(458)		16,103
		Other - net			81		963
			Net cash provided by operating activities		116,065		136,730

INVESTING ACTIVITIES:
	Additions to utility plant				(57,012)		(52,102)
	Note receivable payment from (advance to) parent				(2,302)		12,162
	Other - net				112		(205)
		Net cash used in investing activities			(59,202)		(40,145)

FINANCING ACTIVITIES:
	Issuance of first mortgage bonds				140,000		-
	Retirement of first mortgage bonds				(160,000)		(50,000)
	Retirement of preferred stock				(831)		(121)
	Dividends on common stock				(35,487)		(34,980)
	Dividends on preferred stock				(1,734)		(2,660)
	Change in short-term borrowings				(1,700)		(41,650)
	Other - net				(3,025)		(2,169)
		Net cash used in financing activities			(62,777)		(131,580)

Net decrease in cash and cash equivalents					(5,914)		(34,995)

Cash and cash equivalents at beginning of period					12,699		43,040

Cash and cash equivalents at end of period				$	6,785	$	8,045

SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION:
	Cash paid during the period for:
		Income taxes		$	50,090	$	(8,459)
		Interest (net of amount capitalized)		$	27,864	$	29,184

The accompanying notes are an integral part of these statements.

Idaho Power Company
Consolidated Statements of Comprehensive Income
(unaudited)

				Three Months Ended
				June 30,
				2003		2002
				(thousands of dollars)

NET INCOME				$	12,633	$	13,834

OTHER COMPREHENSIVE INCOME (LOSS):
	Unrealized gains (losses) on securities:
		Unrealized holding gains (losses) arising during the period,
			net of tax of $1,788 and ($633)		3,001		(974)
		Less: reclassification adjustment for (gains) losses included
			in net income, net of tax of $19 and $15		30		23
			Net unrealized gains (losses)		3,031		(951)

TOTAL COMPREHENSIVE INCOME				$	15,664	$	12,883

				Six Months Ended
				June 30,
				2003		2002
				(thousands of dollars)

NET INCOME				$	27,214	$	36,719

OTHER COMPREHENSIVE INCOME (LOSS):
	Unrealized gains (losses) on securities:
		Unrealized holding gains (losses) arising during the period,
			net of tax of $996 and ($756)		1,667		(1,223)
		Less: reclassification adjustment for (gains) losses included
			in net income, net of tax of $230 and ($15)		359		(24)
			Net unrealized gains (losses)		2,026		(1,247)

TOTAL COMPREHENSIVE INCOME				$	29,240	$	35,472

The accompanying notes are an integral part of these statements.

IDAHO POWER COMPANY
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
(unaudited)

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

Except as modified below, the Notes to the Consolidated Financial Statements of IDACORP included in this Quarterly Report on Form 10-Q are incorporated herein by reference insofar as they relate to IPC.

Note 1 - Summary of Significant Accounting Policies
Note 3 - Capital Stock
Note 4 - Financing
Note 5 - Commitments and Contingent Liabilities
Note 6 - Regulatory Matters

1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES:

Stock-Based Compensation
The following table illustrates the effect on net income if the fair value recognition provisions of SFAS 123, had been applied to stock-based employee compensation (in thousands of dollars):

			Three months ended				Six months ended
			June 30,				June 30,
			2003		2002		2003		2002

Net income, as reported			$	12,633	$	13,834	$	27,214	$	36,719
Add: Stock-based employee compensation expense included
	in reported net income, net of related tax effects			62		(99)		54		(3)
Deduct: Total stock-based employee compensation expense
	determined under fair value based method for all awards,
	net of related tax effects			318		438		476		874
		Pro forma net income	$	12,377	$	13,297	$	26,792	$	35,842

2. INCOME TAXES:

IPC uses an estimated annual effective tax rate to compute its provision for income taxes on an interim basis. IPC's effective tax rate for the six months ended June 30, 2003 was 27.6 percent, compared with an effective tax rate of 38.5 percent for the six months ended June 30, 2002. The decrease in the 2003 estimated tax rate, compared with 2002, is due primarily to the favorable resolution during the first half of 2003 of a prior year tax issue, and the on going favorable effects of a tax accounting method change, which was adopted after the first half of 2002.

10. RELATED PARTY TRANSACTIONS:

In exchange for the transfer of energy marketing to IE in June 2001, IPC received a partnership interest in IE, which was then transferred to IDACORP in exchange for notes receivable from IDACORP totaling approximately $76 million. This amount represents the historical book value of the transferred energy marketing net assets on May 31, 2001 of $21 million and retained intercompany tax liabilities of $55 million. The notes receivable are due over periods of one to ten years and bear interest at IDACORP's

overall variable short-term borrowing rate, which was 1.3 percent at June 30, 2003. The balance of this note at June 30, 2003 was approximately $22 million, including accrued interest.

The following table presents IPC's sales to and purchases from IE for the three and six months ended June 30 (in thousands of dollars):

	Three Months Ended				Six Months Ended
	June 30,				June 30,
	2003		2002		2003		2002

Sales to IE	$	111	$	6,773	$	2,197	$	19,682
Purchases from IE		-		7,263		-		9,279

INDEPENDENT ACCOUNTANTS' REPORT

To the Board of Directors and Shareholder of 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, 2003, and the related consolidated statements of income and of comprehensive income for the three and six month periods ended June 30, 2003 and 2002 and the consolidated statements of cash flows for the six month periods ended June 30, 2003 and 2002. These financial statements are the responsibility of the Company's management.

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, 2002, 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 February 6, 2003, 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, 2002 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
August 6, 2003

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

(Dollars in thousands unless otherwise indicated. Megawatt hours (MWh) in thousands).

INTRODUCTION:

In Management's Discussion and Analysis of Financial Condition and Results of Operations (MD&A), the general financial condition and results of operations for IDACORP, Inc. and its subsidiaries (IDACORP) and Idaho Power Company and its subsidiary (IPC) are discussed. IDACORP is a holding company formed in 1998 as the parent of IPC and several other entities.

IPC is an electric utility with a service territory covering over 20,000 square miles, primarily in southern Idaho and eastern Oregon. IPC is the parent of Idaho Energy Resources Co., a joint venturer in Bridger Coal Company, which supplies coal to the Jim Bridger generating plant owned in part by IPC.

Another subsidiary, IDACORP Energy (IE), a marketer of electricity and natural gas, is in the process of winding down its operations.

IDACORP's other significant operating subsidiaries are:

Ida-West Energy - developer and manager of independent power projects;

IdaTech - developer of integrated fuel cell systems;

IDACORP Financial Services, Inc. (IFS) - low-income housing and other real estate investments;

Velocitus - commercial and residential Internet service provider; and

IDACOMM - provider of telecommunications services.

This MD&A should be read in conjunction with the accompanying consolidated financial statements. This discussion updates the MD&A included in the Annual Report on Form 10-K for the year ended December 31, 2002, 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), IDACORP and IPC are hereby filing cautionary statements identifying important factors that could cause actual results to differ materially from those projected in forward-looking statements (as such term is defined in the Reform Act) made by or on behalf of IDACORP or IPC 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:

changes in governmental policies and regulatory actions, including those of the Federal Energy Regulatory Commission (FERC), the Idaho Public Utilities 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, operation and construction of plant facilities, recovery of purchased power and other capital investments, and present or prospective wholesale and retail competition (including but not limited to retail wheeling and transmission costs) and other refund proceedings;

litigation resulting from the energy situation in the western United States;

economic, geographic and political factors and risks;

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

weather variations affecting customer energy usage;

operating performance of plants and other facilities;

system conditions and operating costs;

population growth rates and demographic patterns;

pricing and transportation of commodities;

market demand and prices for energy, including structural market changes;

changes in capacity and fuel availability and prices;

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

changes in actuarial assumptions;

adoption of or changes in critical accounting policies or estimates;

exposure to operational, market and credit risk in energy trading and marketing operations;

changes in operating expenses and capital expenditures;

capital market conditions;

rating actions by Moody's, Standard & Poor's and Fitch;

competition for new energy development opportunities;

results of financing efforts, including the ability to obtain financing on favorable terms, which can be affected by various factors, including credit ratings and general economic conditions;

natural disasters, acts of war or terrorism;

legal and administrative proceedings (whether civil or criminal) and settlements that influence business and profitability; and

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.

RISK FACTORS:

The following are some important factors that could have a significant impact on the operations and financial results of IDACORP and IPC and could cause actual results or outcomes to differ materially from those discussed in any forward-looking statements:

Reduced hydroelectric generation can significantly affect operating results. IPC has a predominately hydroelectric generating base. Because of its heavy reliance on inexpensive hydroelectric generation, IPC's operations can be significantly affected by the weather. IPC is experiencing its fourth consecutive year of below normal water conditions. When hydroelectric generation is reduced because of below normal water conditions, IPC must increase its use of more expensive other generating resources and purchased power. Although IPC generally recovers certain increased power costs through its Power Cost Adjustment (PCA), the recovery is on a deferred basis and is subject to the regulatory process.

Changes in temperature can reduce power sales and affect operating results. In addition to the below normal water conditions, IPC experienced warmer than usual temperatures in its service territory in the first quarter of 2003, which reduced sales. Temperatures in the second quarter of 2003 have been warmer than normal resulting in increased sales. Warmer than normal winters or cooler than normal summers will reduce revenues from power sales.

Conditions that may be imposed in connection with hydroelectric license renewals may negatively affect earnings. IPC is currently involved in renewing federal licenses for certain of its hydroelectric projects. IPC currently expects new licenses for five middle Snake River region hydroelectric plants to be issued in late 2003. In addition, IPC filed its license application on July 18, 2003 for the Hells Canyon Complex (HCC), which provides 40 percent of IPC's total generating capacity. IPC cannot predict what conditions, if any, with respect to environmental, operating and other matters the FERC may impose in connection with the renewal of these licenses and the effect of any such conditions on IPC's operations.

The cost of complying with environmental regulations can significantly affect operating results. IDACORP and IPC are subject to extensive federal, state and local environmental statutes, rules and regulations relating to air quality, water quality, natural resources and health and safety. There are significant capital, operating and other costs associated with compliance with these environmental statutes, rules and regulations, and those costs could be even more significant in the future as a result of, among other factors, changes in legislation and enforcement policies and additional requirements imposed in connection with the relicensing of IPC's hydroelectric projects.

If requested rate relief is not granted, IPC's earnings and cash flow will be negatively affected. IPC currently anticipates filing a general rate case with the IPUC by the end of the year 2003. The rate case is being filed as a result of capital expenditures made and increased operating costs experienced by IPC since 1993, the last rate case test year, except for those capital costs associated with construction of the Milner and expansion of the Twin Falls hydroelectric projects which were included in rates in 1995. IPC cannot predict the outcome of this case or the effect on its operations if the requested rate relief is not granted.

Terrorist threats and activities can significantly affect operating results. IDACORP and IPC are subject to direct and indirect effects of terrorist threats and activities. Generation and transmission facilities, in general, have been identified as potential targets. The effects of terrorist threats and activities include, among other things, actions or responses to such actions or threats, the inability to generate, purchase or transmit power and the increased cost and adequacy of security and insurance.

IPC and its affiliate, IE, may be subject to potential liabilities as a result of energy marketing operations. As IE winds down its energy marketing operations, certain matters have been identified that required resolution with the FERC and the IPUC. On February 26, 2003, the FERC issued an order approving the assignment of certain wholesale power and transmission services agreements from IPC to IE. On May 16, 2003, the FERC issued an order that provided for (1) the refund of $0.3 million to certain counterparties associated with the inappropriate use of native load priority and for failure to obtain FERC approval prior to assigning certain contracts from IPC to IE, (2) the transfer of $5.8 million in benefits from IE to IPC as the result of certain transactions between the affiliates and (3) the implementation of certain compliance and auditing programs to ensure future compliance with FERC requirements. In the IPUC proceeding that has been underway since May 2001, IPC, the IPUC staff and several interested customer groups have been working to determine the appropriate compensation IE should provide to IPC as a result of transactions between the affiliates. IPC and IE do not believe that resolution of the IPUC proceeding will have any adverse impact on retail customers or a material adverse effect on their ongoing operations. However, because it cannot be predicted at this point what regulatory actions might be taken or when, it cannot be determined what effect there may be on earnings and whether it will be material.

IDACORP, IE and IPC are subject to costs and other effects of legal and administrative proceedings, settlements, investigations and claims, including those that may arise out of the California energy situation. Regarding the California energy situation, IDACORP, IE and IPC are involved in a number of proceedings including a complaint filed against sellers of power in California, based on California's unfair competition law, a cross-action wholesale electric antitrust case against various sellers and generators of power in California and the California refund proceeding at the FERC. Other cases that are the direct or indirect result of the energy crisis in California include efforts by certain public parties to reform or terminate contracts for the purchase of power from IE and various show cause proceedings that consider whether certain trading practices constituted gaming or acting in concert in furtherance of a gaming strategy at the FERC. It is possible that additional proceedings may be filed in the future against IDACORP, IE or IPC related to the California energy crisis.

Increased capital expenditures can significantly affect liquidity. Increases in both numbers of customers and demand for energy require expansion and reinforcement of transmission, distribution and generating systems. Additionally, a significant portion of IPC's facilities was constructed many years ago. Aging equipment, even if maintained in accordance with good engineering practices, may require significant capital expenditures. Failure of equipment or facilities used in IPC's systems could potentially increase repair and maintenance expenses, purchased power expenses and capital expenditures. Potential regulatory changes may also adversely affect IPC by reducing revenues, increasing expenses or increasing capital expenditures.

Limitations on access to the capital markets can negatively affect liquidity. IDACORP and IPC rely on access to capital markets as a significant source of liquidity for capital requirements not satisfied by operating cash flows. Access to capital markets at a reasonable cost is determined in large part by credit quality. An inability to raise capital on favorable terms, particularly during times of uncertainty in the capital markets, could impact the liquidity of IDACORP and IPC and would likely increase their interest costs. It could also affect the companies' ability to implement their business plans.

The issues and associated risks and uncertainties described above are not the only ones IDACORP and IPC may face. Additional issues may arise or become material. The risks and uncertainties associated with these additional issues could impair IDACORP's and IPC's businesses in the future.

SUMMARY OF SECOND QUARTER 2003 AND 2003 OUTLOOK:

Overall Results
IDACORP's earnings (loss) per share (EPS) was a $0.02 loss for the second quarter 2003. This reduction in EPS compared to the same period last year is due to decreased earnings from IPC, net losses recorded at IE and the impact of a required income tax adjustment deferring the benefit of low-income housing tax credits to later quarters.

IPC reported EPS of $0.31, a $0.02 per share decrease compared to second quarter 2002. These results are due to the continued impact of below normal water conditions and increased operations and maintenance expenses.

IE recorded a net loss of $0.11 per share for the second quarter 2003 compared to a net loss of $0.32 per share in the second quarter of 2002. IE's continued losses are a reflection of the continued wind down of energy marketing as announced in June 2002.

Below Normal Water Conditions
The Snake River basin above Brownlee Dam experienced below normal snowpack accumulations during the winter of 2002/2003 resulting in below normal streamflow conditions for 2003.

April-through-July inflow into Brownlee Reservoir was 3.5 million acre-feet (maf). This volume is 55 percent of the 30-year average April-through-July inflow of 6.3 maf but is slightly better than the 2002 inflow volume of 3.2 maf. Based on this year's snowpack and current and forecasted inflows, IPC is experiencing its fourth consecutive year of below normal water conditions. IPC increases its use of other company-owned generating resources as well as wholesale purchases from the energy markets when necessary to overcome below normal water conditions and meet its energy needs.

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 IPC's utility service territory by mid-2005.

PPL Montana Power Purchase Agreement: During May 2003, IPC and PPL Montana, LLC (PPLM) entered into a firm wholesale Power Purchase Agreement (PPA) under which IPC will purchase energy from PPLM during the heavy load hours of June, July and August from 2004 through 2009.

Request for Proposal: On February 24, 2003, IPC issued a formal Request for Proposal (RFP) seeking bids for the construction of up to 200 megawatts (MW) of additional generation to support the growing seasonal demand for electricity in IPC's service area. Bids were submitted to IPC on April 28, 2003. A proposal for an IPC self-build option was submitted at the same time. IPC is presently in the evaluation phase of the process, which is expected to be completed during the third quarter of 2003.

Power Cost Adjustment and General Rate Relief
On April 15, 2003, IPC filed its 2003-2004 PCA with the IPUC, and, with a small adjustment to the filing, the rates were approved by the IPUC and became effective on May 16, 2003. As approved, IPC's rates have been adjusted to collect $81 million above 1993 base rates, a $114 million reduction from the 2002-2003 PCA.

IPC plans to file a general rate case with the IPUC before year-end 2003. IPC will request revenue recovery for certain costs of serving its customers, such as increased operating expenses and substantial demands for infrastructure improvements, increased capital costs for the protection, mitigation and enhancement (PM&E) requirements of new licenses at some of its hydroelectric projects, for the cost of new sources of power and continued expansion of its transmission and distribution network. The success of this rate case is dependent on the IPUC review and approval, and IPC is unable to predict what rate relief, if any, the IPUC will grant.

Relicensing of Hydroelectric Projects
Currently, the licenses for five of IPC's hydroelectric projects have expired. These projects continue to operate under annual licenses until the FERC issues a new permanent license. Three more of IPC's hydroelectric project licenses will expire by 2010. A new license application was filed for the HCC, IPC's largest generating facility, in July 2003.

Legal Issues and Regulatory Matters
IE is involved in a number of FERC proceedings arising out of the California energy situation. They include proceedings involving (1) the chargeback provisions of the California Power Exchange (CalPX) participation agreement, which was triggered when a participant defaulted on a payment to the CalPX. Upon such a default, other participants were required to pay their allocated share of the default amount to the CalPX. This provision was first triggered by the Southern California Edison default and later by the Pacific Gas & Electric Company default; (2) efforts by the state of California to obtain refunds for a portion of the spot market sales prices from sellers of electricity into California from October 2, 2000 through June 20, 2001. California is claiming that the prices were not just and reasonable and were not in compliance with the Federal Power Act (FPA); (3) the Pacific Northwest refund proceedings in which it was argued that the spot market in the Pacific Northwest was affected by the dysfunction in the California market, warranting refunds. The FERC rejected this claim on June 25, 2003, but the FERC order remains subject to rehearing and judicial review; and (4) two cases which result from a ruling of the U.S. Court of Appeals for the Ninth Circuit that the FERC permitted the California parties in the California refund proceeding to submit materials to the FERC demonstrating market manipulation by various sellers of electricity into California. On June 25, 2003, the FERC ordered a large number of parties including IPC to show cause why certain trading practices did not constitute gaming or anomalous market behavior in violation of the California Independent System Operator (Cal ISO) and CalPX tariffs. The FERC also issued an order instituting an internal investigation of Anomalous Bidding Behavior and Practices in the Western Wholesale Power Markets.

In connection with the wind down of energy marketing, certain matters were identified that required resolution with the FERC or the IPUC. On February 26, 2003, the FERC issued an order approving the assignment of certain wholesale power and transmission services agreements from IPC to IE while stating that IPC violated Section 203 of the FPA. On May 16, 2003, the FERC issued another order on these matters which provided for (1) the refund of $0.3 million to certain counterparties associated with the inappropriate use of native load priority and for failure to obtain FERC approval prior to assigning certain contracts from IPC to IE, (2) the transfer of $5.8 million in benefits from IE to IPC as the result of certain transactions between the affiliates and (3) the implementation of certain compliance and auditing programs to ensure future compliance with FERC requirements. The IPUC matters include a proceeding that has been underway since May 2001 where IPC, the IPUC staff and several interested customer groups have been working to determine the appropriate compensation IE should provide to IPC as a result of transactions between the affiliates. The IPUC proceeding has become active since the FERC order became final, with settlement workshops conducted between IPC, IPUC staff and other interveners in June and July 2003.

Liquidity
IDACORP's and IPC's operating cash flows were $137 million and $116 million, respectively for the six months ended June 30, 2003. IDACORP's cash flows include cash received from IE on contracts realized or otherwise settled. IPC's cash flows from operating activities include continued collections of PCA deferrals that were used for additions to utility plant, the redemption and retirement of first mortgage bonds and payment of dividends on common stock.

Forecasted net cash provided by operating activities for the year ending 2003 at IDACORP is $218 million, a decrease from the previous estimate of $225 million. IPC is forecasting that net cash provided by operating activities will be approximately $176 million for the year ending 2003 compared to its previous estimate of $190 million.

Defined benefit pension plan expense is expected to increase from approximately $0 in 2002 to approximately $7 million in 2003. Based on current estimates, cash contributions during 2003 are not expected. Benefits under the plan are based on years of service and the employee's final average earnings.

At June 30, 2003, IDACORP had approximately $110 million in commercial paper outstanding against its $315 million available bank credit facility. IPC had approximately $9 million in commercial paper outstanding against its $200 million available bank credit facility.

The credit facilities require IDACORP and IPC to maintain a ratio of debt to total capitalization (leverage ratio) of no more than 65 percent. At June 30, 2003, IDACORP's and IPC's leverage ratios were 55 percent and 53 percent, respectively. IDACORP is also required to maintain an interest coverage ratio of

at least 2.75 to 1. At June 30, 2003, IDACORP's interest coverage ratio was in compliance with this requirement.

Capital Expenditures: Capital expenditures at IPC are expected to come in just under the budgeted levels of $150 million for the year. The capital needs of the utility in 2004 and 2005 are expected to increase to $215 million in 2004 and $200 million in 2005. The ultimate decision on whether these amounts will be spent will be based in part on the results of the current RFP process for new generating resources. If IPC is selected as the successful bidder with its self-build option, the cash required for the new generating resource would be expected to be funded through the issuance of a combination of long-term debt and to the extent necessary at the time, new equity or equity-like securities issued at either IDACORP or IPC.

The ultimate outcome of the ability of IDACORP and IPC to generate adequate operating cash flow to fund these increased capital requirements and their ability to access the capital markets in 2004 and 2005 will be heavily dependent on weather, hydroelectric generating conditions and results of the general rate case filing. These factors will drive the level of capital that IDACORP and IPC can reinvest back into the utility and return to shareholders.

Dividends: The amount and timing of dividend payments on IDACORP's common stock are within the sole discretion of IDACORP's Board of Directors. The Board of Directors reviews the common dividend rate quarterly to determine its appropriateness in light of IDACORP's current and long-term financial position and results of operations, capital requirements, rating agency requirements, legislative and regulatory developments affecting the electric utility industry in general and IPC in particular, competitive conditions and any other factors the Board of Directors deems relevant.

IDACORP is challenged by operating results that are significantly below the current annual dividend. With the wind down of IE, the long-term sustainability of the dividend is primarily dependent upon the earnings and operating cash flow generated by IPC. IPC's earnings and operating cash flow depend on many factors, but the most significant are weather and hydroelectric generating conditions, the ability to obtain rate relief to cover operating costs and capital spending requirements. The impacts of lower than anticipated cash flows in 2003, expected increases in investments in utility plant in 2004 and 2005 and credit quality considerations are also factors being considered. Because of these factors IDACORP's ability to sustain the level of dividends paid in the past is less certain and it is possible the Board of Directors may reduce the dividend as early as 2003. The Board of Directors will continue to evaluate these and other factors in determining the appropriate and sustainable level of payout to IDACORP shareholders going forward. The Board of Directors has made no determination at this time as to the long-term sustainability of the existing dividend on common stock.

IPC's articles of incorporation contain restrictions on the payment of dividends on its common stock if preferred stock dividends are in arrears. IPC paid dividends to IDACORP of $35 million for both the six months ended June 30, 2003 and 2002.

Financing Activities
On May 1, 2003, $80 million in first mortgage bonds of IPC matured and IPC redeemed another $80 million in first mortgage bonds that were due in 2023. Short-term debt of $136 million was issued to redeem and retire these series and the remaining amount was paid using short-term investments.

On May 8, 2003, IPC issued $140 million of secured medium-term notes. Proceeds were used to pay down the above mentioned IPC short-term borrowings.

During July 2003, IFS issued a total of $40 million in debt. Proceeds were used to pay intercompany notes to IDACORP. IDACORP used these proceeds to pay short-term borrowings.

CRITICAL ACCOUNTING POLICIES:

IDACORP's and IPC's discussion and analysis of their financial condition and results of operations are based upon their consolidated financial statements, which have been prepared in accordance with accounting principles generally accepted in the United States of America (GAAP). The preparation of these financial statements requires IDACORP and IPC to make estimates and judgments that affect the reported amounts of assets, liabilities, revenues and expenses and related disclosure of contingent assets and liabilities. On an ongoing basis, IDACORP and IPC evaluate these estimates, including those related to rate regulation, mark-to-market accounting on energy trading contracts, contingencies, litigation, income taxes, restructuring costs, benefit costs and bad debts. These estimates are based on historical experience and on various other assumptions and factors that are believed to be reasonable under the circumstances, and are the basis for making judgments about the carrying values of assets and liabilities that are not readily apparent from other sources. IDACORP and IPC, based on their ongoing reviews, will make adjustments when facts and circumstances dictate.

IDACORP's and IPC's critical accounting policies are discussed in more detail in the Annual Report on Form 10-K for the year ended December 31, 2002, and information related to IDACORP's policy on "Mark-to-Market Accounting for Energy Trading Contracts" is updated in "RESULTS OF OPERATIONS - Energy Marketing" below. Except for those updates, IDACORP's and IPC's critical accounting policies have not changed materially from the discussions included in the 2002 Annual Report on Form 10-K.

RESULTS OF OPERATIONS:

In this section IDACORP's earnings and the factors that affected them are discussed, beginning with a general overview followed by a more detailed discussion of the electric utility and energy marketing activities for the three and six months ended June 30.

			Three Months Ended				Six Months Ended
			June 30,				June 30,
			2003		2002		2003		2002
Earnings per share of common stock
	Electric utility		$	0.31	$	0.33	$	0.67	$	0.91
	Energy marketing			(0.11)		(0.32)		(0.39)		(0.21)
	Other			(0.22)		0.07		(0.38)		0.04
		Total	$	(0.02)	$	0.08	$	(0.10)	$	0.74

EPS from utility operations decreased $0.02 and $0.24 for the three and six months ended June 30, 2003. Though the second quarter results were nearly the same as last year's, the year-to-date results demonstrate the continuing impact of below normal hydroelectric generating conditions in the service area; reduced customer energy sales due to weather; and increases in other operations and maintenance expenses.

Energy marketing incurred losses for both the three and six months ended June 30, 2003. General and administrative expenses associated with continued performance of existing contracts along with legal expenses related to regulatory and legal disputes are the primary cause of the second quarter loss. The year-to-date results also reflect the settlement costs of reaching resolution in three legal disputes, which were recorded in the first quarter.

GAAP requires companies to apply an estimated annual effective tax rate to interim periods, which has had the effect of deferring significant intra-period tax benefits from the first and second quarters to later in the year. The tax benefits deferred consist primarily of Section 42 low-income housing tax credits recorded at IFS. This adjustment is not expected to have an impact on IDACORP's annual earnings because the adjustment will reverse and flow into earnings during the remainder of the year. Combined EPS from IDACORP's other subsidiaries prior to this tax adjustment was unchanged for the three months ended June 30, 2003 and increased $0.06 per share for the six months ended June 30, 2003.

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

General Business Revenue: The following table presents IPC's general business revenues 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
		2003		2002		2003	2002	2003		2002		2003	2002

Residential		$	60,031	$	60,948	937	887	$	144,239	$	155,102	2,136	2,244
Commercial			42,450		47,863	820	838		90,860		96,449	1,664	1,714
Industrial			29,661		43,530	758	790		71,920		86,649	1,528	1,564
Irrigation			34,471		35,223	676	666		34,656		35,484	677	669
	Total	$	166,613	$	187,564	3,191	3,181	$	341,675	$	373,684	6,005	6,191

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 2003 is due primarily to the following:

The annual PCA resulted in decreased revenues of approximately $13 million and $10 million for the three and six months ended June 30, 2003. The PCA is discussed in more detail below in "REGULATORY ISSUES - Deferred Power Supply Costs."

Customer growth in IPC's service territory was approximately three percent, resulting in a $4 million and $9 million increase in revenues for the three and six months ended June 30, 2003.

Usage and weather factors decreased revenues $3 million and $20 million for the three and six months ended June 30, 2003. The three-month decrease is attributed to decreased cooling degree days of seven percent while the six-month decrease is attributed to a 19 percent decrease in heating degree days experienced during the first quarter of 2003. Heating degree days and cooling degree days are a common measure used in the utility industry to analyze demand and indicate when a customer would use electricity for heating or air-conditioning.

The remaining change is attributed to decreased payments from FMC/Astaris. FMC/Astaris, previously IPC's largest volume customer, closed its plants late in 2001 but was required, under a take or pay contract, to pay IPC for generation capacity regardless of delivery. This contract expired in March 2003.

Off-system sales: Off-system sales consist primarily of long-term sales contracts and opportunity sales of surplus system energy. 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,
	2003		2002		2003		2002

Off-system sales	$	19,839	$	10,976	$	38,447	$	31,135
MWh sold		569		431		982		1,253
Revenue per MWh	$	34.88	$	25.47	$	39.16	$	24.85

Purchased power: The following table presents IPC's purchased power for the three and six months ended June 30:

		Three Months Ended				Six Months Ended
		June 30,				June 30,
		2003		2002		2003		2002
Purchased Power:
	Purchases	$	32,019	$	23,349	$	42,495	$	36,513
	Load reduction costs	$	-	$	7,835	$	3,130	$	24,861

MWh purchased			795		823		1,014		1,304
Cost per MWh purchased		$	40.28	$	28.36	$	41.90	$	28.01

Purchased power volumes decreased during the three and six months ended June 30, 2003 due to reduced customer demand and slightly better water conditions over last year. This decrease was offset by increased costs per MWh. The changes in the load reduction payments also included in purchased power are due to expiration of the FMC/Astaris Voluntary Load Reduction program.

Fuel expense: The following table presents IPC's fuel expenses and generation at its thermal generating plants for the three and six months ended June 30:

	Three Months Ended				Six Months Ended
	June 30,				June 30,
	2003		2002		2003		2002

Fuel expense	$	23,908	$	21,708	$	49,446	$	49,636
Thermal MWh generated		1,481		1,492		3,311		3,413
Cost per MWh	$	16.15	$	14.55	$	14.93	$	14.55

PCA: The PCA expense component is related to IPC's PCA regulatory mechanism. The PCA is discussed in more detail below in "REGULATORY ISSUES - Deferred Power Supply Costs." The following table presents the components of IPC's PCA expense for the three and six months ended June 30:

		Three Months Ended				Six Months Ended
		June 30,				June 30,
		2003		2002		2003		2002

Current year power supply costs accrual
	(deferral)	$	(3,540)	$	1,049	$	(3,163)	$	4,570
FMC/Astaris and irrigation program costs
	(deferral)		-		(5,994)		(2,245)		(19,019)
Amortization of prior year authorized balances			28,875		45,650		82,590		89,214
Write-off of disallowed costs			48		1,460		48		1,460
	Total power cost adjustment	$	25,383	$	42,165	$	77,230	$	76,225

Other Operations and Maintenance Expenses: Other operations and maintenance expenses have increased $6 million and $8 million for the three and six months ended June 30, 2003, respectively. The majority of each increase is due to pension expense, which increased $2 million for the quarter and $3 million year-to-date and thermal plant expenses, which increased $3 million for the quarter and year to date. Over the last four years of below normal water conditions, IPC has relied on thermal generation. This usage has required an increase in maintenance expenses to maintain operating capacity of these facilities. The remaining year-to-date increase is due to increased transmission and distribution expenses of $3 million.

Energy Marketing
In 2002, IDACORP announced two separate plans to wind down IE's energy marketing operations. The initial announcement, in June 2002, specified that IE would not seek new electric customers; would limit its maximum value at risk to less than $3 million; would target a reduction of working capital requirements to less than $100 million by the end of 2003; and would reduce its workforce at its Boise operations by approximately 50 percent. The second announcement, in November 2002, indicated that IE would close its Denver office by year-end 2002, would shut down its natural gas trading operation in Houston by March 2003, and would further reduce its workforce in its Boise operations through mid-2003. Since these announcements in 2002, IE has reduced its workforce by approximately 83 percent and will continue to reduce its workforce as contractual obligations terminate. The Denver office ceased operations in December 2002 and the Houston office ceased operations in April 2003.

In 2002, IE incurred $5 million of involuntary termination benefit expenses and approximately $4 million of lease termination and other exit-related costs. As of December 31, 2002, IE had paid $2 million of these costs with a remaining outstanding accrual of $7 million. During the three months ended June 30, 2003, $1 million of involuntary termination benefits, lease termination costs and other exit-related costs were paid, for a total of $3 million for the six months ended June 30, 2003. The termination benefit expense relates to the termination of 98 employees (primarily energy traders and administrative support positions), 88 of whom had been laid off by June 30, 2003. Nineteen of the 88 employees laid off were hired by other IDACORP subsidiaries, and thus received no severance benefits.

In connection with the wind down of energy marketing, certain matters were identified that required resolution with the FERC and the IPUC. The FERC matters have been resolved by the issuance of two FERC orders. These matters are discussed in more detail in Notes 6 and 9 to the Consolidated Financial Statements.

For the three months ended June 30, 2003 and 2002, IE reported operating losses of $8 million and $21 million, respectively. The second quarter loss is a result of general and administrative expenses associated with the continued performance of existing contracts along with legal expenses related to regulatory and legal disputes.

Operating losses were $25 million and $14 million for the six months ended June 30, 2003 and 2002, respectively. This is largely the result of losses incurred in the first quarter of 2003 from the settlement of legal disputes.

IE anticipates that approximately 22 percent of its unrealized forward positions recorded as of June 30, 2003 will be settled by the end of 2003, 46 percent settled by the end of 2004 and 62 percent settled by the end of 2005. All forward positions as of June 30, 2003 are expected to be settled within eight years. Changes in market conditions in future periods could substantially change the amounts of gain or loss ultimately realized upon settlement of the contracts.

Revenues: Operating revenues include sales of electricity and natural gas netted against purchases. All financial transactions and unrealized income are presented on a net basis as operating revenue. Operating expenses include general and administrative expenses, net gains or loss on legal disputes, transmission expenses and broker fees.

The following table presents IE's energy marketing revenues and volumes for the three and six months ended June 30:

			Three Months Ended				Six Months Ended
			June 30,				June 30,
			2003		2002		2003		2002

Net operating revenues:
	Electricity		$	(1,091)	$	(2,892)	$	2,433	$	12,670
	Gas			38		(157)		107		5,261
		Total operating revenues	$	(1,053)	$	(3,049)	$	2,540	$	17,931

Operating volumes (settled):
	Electricity (MWh)			3,371,171		13,522,259		8,156,231		26,520,038
	Gas (MMbtu)			8,450		11,706,894		2,255,881		23,880,601

The decline in revenues between 2002 and 2003 is a result of the decision to exit the energy marketing and trading business and the resulting decline in volume. IE anticipates revenues in 2003 to continue to be lower than prior years as IE continues to complete its obligations under existing contracts and wind down its business.

Contracts Accounted for at Fair Value: When determining the fair value of marketing and trading contracts, IE uses 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, IE uses (when available) prices provided by other external sources. When prices from external sources are not available, IE determines prices by using internal pricing models that incorporate available current and historical pricing information. Finally, the fair market value of contracts is adjusted 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 energy marketing operations for the three and six months ended June 30:

			Three Months Ended				Six Months Ended
			June 30,				June 30,
			2003		2002		2003		2002
Gross Margin:
	Realized or otherwise settled		$	11,808	$	21,680	$	10,526	$	51,629
	Unrealized losses			(12,846)		(37,734)		(11,691)		(58,165)
		Total	$	(1,038)	$	(16,054)	$	(1,165)	$	(6,536)

The change in net fair value (energy marketing assets less energy marketing liabilities) between year-end 2002 and June 30, 2003 is explained as follows:

Net fair value of contracts outstanding as of 12/31/2002		$	38,193
Contracts realized or otherwise settled during the period			(10,526)
Changes in net fair value attributable to market prices and other market changes			373
	Net fair value of contracts outstanding as of 6/30/2003	$	28,040

The fair value of energy marketing and trading contracts is an accounting estimate based on reasonable assumptions related to interest rates, energy prices and price volatility. Different assumptions regarding these variables could result in a change to the net fair value of energy marketing and trading contracts. The following table shows the estimated adverse change to the reported fair value of energy marketing and trading contracts for defined adverse moves associated with the key assumptions incorporated into this estimate:

	Adverse move
	in fair value
Change in assumption used in fair value calculation

1% change in interest rates	$	266
$1/MWh change in electricity prices	$	29
$0.50/MMbtu change in gas prices	$	-
1% change in volatility	$	224

The following table presents the net fair value of contracts outstanding at June 30, 2003, 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			$	20,068	$	6,851	$	3,742	$	-	$	30,661
Prices provided by other
	external sources			14,578		(7,525)		(14,126)		1,646		(5,427)
Prices based on models
	and other valuation
	methods			2,126		(1,148)		1,828		-		2,806
		Total	$	36,772	$	(1,822)	$	(8,556)	$	1,646	$	28,040

Prices actively quoted are quoted daily by brokers and trading exchanges such as NYMEX, TFS, Intercontinental and Bloomberg. The time horizon is July 2003 through June 2008. 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 2003 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 2003 through December 2007. Products include transmission, options and ancillary services related to heavy and light load power.

LIQUIDITY AND CAPITAL RESOURCES:

Operating Cash Flows
IDACORP's operating cash flows for the six months ended June 30, 2003 were $137 million compared to $124 million for the six months ended June 30, 2002. This increase is attributed to cash received from IE of $28 million on contracts realized or otherwise settled, offset by decreased cash flows at IPC.

IPC's operating cash flows for the six months ended June 30, 2003 were $116 million compared to $137 million for the six months ended June 30, 2002. This decrease was driven by current year tax payments of $50 million, partially offset by decreased purchased power expenditures of $22 million related to the FMC/Astaris Voluntary Load Reduction program.

Looking forward to the balance of the year, net cash provided by operating activities at IDACORP is forecasted to be $218 million, down from the previous estimate of $225 million. IPC is forecasting that net operating cash will be approximately $176 million compared to its previous estimate of $190 million. The decline in forecasted operating cash flows are attributable to increased operating expenses at IPC and the timing of payments of certain working capital amounts including income taxes offset by increases in cash expected from the continued wind down of IE.

Working Capital
Cash received from IFS of $36 million and IE of $23 million was used to pay down IDACORP's notes payable.

Decreases of $52 million in accounts receivable and $61 million in accounts payable at IE are attributed to contracts realized or otherwise settled and settled legal disputes with Truckee-Donner Public Utility District and Enron Power Marketing, Inc. and Enron North America Corp.

Energy marketing assets and liabilities reflect the fair value of energy marketing contracts as of the reporting date. The fair value of these contracts is unrealized and therefore does not necessarily indicate a current source or use of funds. The change in the net energy marketing assets and liabilities from December 31, 2002 to June 30, 2003 is primarily a reflection of the wind down of the energy marketing business.

Cash received from energy trading counterparties serves as collateral against open positions on energy related contracts and is reported in cash and cash equivalents. The resultant liability is recorded as a reduction to the energy marketing asset generated by the open position. Regarding the use of posted collateral, the margining agreements provide "...the right to: (i) sell, pledge, rehypothecate, assign, invest, use, commingle or otherwise dispose of, or otherwise use in its business any posted collateral it holds..." as long as IDACORP maintains a credit rating of at least BBB- (S&P) or Baa3 (Moody's). IDACORP has continued to maintain a credit rating above this minimum and has no restrictions on the use of collateral funds.

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

Contractual Obligations
The following table presents IDACORP's total contractual obligations in the respective periods in which they are due:

	2003		2004		2005		2006		2007		Thereafter

IPC long-term debt	$	44	$	50,077	$	60,079	$	82	$	81,228	$	739,370
Other long-term debt		7,396		11,433		10,286		8,634		6,550		11,330
IPC fuel supply contracts		15,969		30,970		27,466		27,300		9,266		22,856
IPC power purchase agreement		-		3,613		4,610		4,610		4,610		9,159

Pension Expense
IPC maintains a qualified defined benefit pension plan covering most employees. Pension expense is dependent on several assumptions used in the actuarial valuation of the plan. The primary assumptions are the long-term return on plan assets and the discount rate. Annually, these assumptions are reviewed in light of changes in market conditions, trends and future expectations. These assumptions and the results of actuarial valuations are discussed in the Annual Report on Form 10-K for the year ended December 31, 2002.

Pension expense is expected to increase from approximately $0 in 2002 to approximately $7 million during 2003. For the six months ended June 30, 2003, pension expense of approximately $4 million was recorded. Of these amounts, approximately 70-75 percent impact IPC's operations and maintenance expenses. Based on current estimates, cash contributions during 2003 are not expected.

Capital Requirements
Utility Construction Program: Current utility construction expenditures for generation, transmission and distribution are designed to meet continuing customer growth and to improve efficiencies of IPC's energy delivery systems. Construction expenditures, excluding Allowance for Funds Used During Construction, were $57 million for the six months ended June 30, 2003 compared to $52 million for the same period in 2002. IPC expects construction expenditures will be $150 million, $215 million and $200 million in 2003, 2004 and 2005, respectively. Included in the 2004 and 2005 amounts are estimates for resource acquisitions in connection with IPC's 2002 IRP of between $55 million and $75 million. The ultimate decision on whether these amounts will be expended will be based in part on the results of the current RFP process seeking new generating resources. If IPC is the successful bidder with the self-build option, the expenditure of cash on the new generating resource would be funded through the issuance of long-term debt and to the extent deemed necessary, new equity or equity-like securities at IDACORP or IPC. IPC may arrange short-term financing for the resource pending final credit consideration and regulatory review. Construction expenditure estimates are subject to periodic review and adjustment in light of changing economic, regulatory, environmental and conservation factors.

Other Capital Requirements: Capital requirements at IDACORP's other subsidiaries were $7 million for the six months ended June 30, 2003 compared to $47 million for the same period in 2002. The decline in 2003 capital investment was attributable to the decision to reduce new investments in low-income housing projects in 2003.

IDACORP and IPC forecast that internal cash generation after dividends will provide approximately 88 percent of total capital requirements in 2003, and 80 percent during the two-year period 2004-2005. The contribution for internal cash generation is dependent primarily upon IPC's cash flows from operations, which are subject to risks and uncertainties relating to weather and water conditions and IPC's ability to obtain rate relief to cover its operating costs. IDACORP and IPC expect to continue financing the utility construction program and other capital requirements with internally generated funds and externally financed capital.

The forecast for internally generated cash for total capital requirements in 2003 has decreased from the 97 percent reported in the Annual Report on Form 10-K for the year ended December 31, 2002 due to continued below normal water conditions, warmer than normal temperatures during the first quarter 2003 and contract settlements. The forecast for 2004-2005 has not changed materially from that reported in the Annual Report on Form 10-K for the year ended December 31, 2002.

Financing Programs
Credit facilities: IDACORP has a $175 million facility that expires on March 19, 2004, and a $140 million facility that expires on March 25, 2005. 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 bank credit facilities.

IPC has a $200 million facility that expires on March 19, 2004. Under this facility IPC pays a facility fee on the commitment, quarterly in arrears, based on IPC's corporate credit rating. IPC's commercial paper may be issued up to the amount supported by the bank credit facilities. At June 30, 2003, IPC had regulatory authority to incur up to $250 million of short-term indebtedness.

Short-term financings: At June 30, 2003, IDACORP's short-term borrowing totaled $110 million, compared to $166 million at December 31, 2002. At June 30, 2003, IPC's short-term borrowings totaled $9 million, compared to $11 million at December 31, 2002.

Long-term financings: IDACORP currently has two shelf registration statements totaling $800 million that can be used for the issuance of unsecured debt (including medium-term notes) and preferred or common stock. At June 30, 2003, none had been issued. IDACORP does not anticipate issuing new common equity or equity linked securities during the remainder of 2003. In March 2003, IDACORP ceased issuing original issue shares of common stock and began purchasing shares on the open market for the Dividend Reinvestment Plan, the Employee Savings Plan, the Restricted Stock Plan and the IDACORP Long-Term Incentive and Compensation Plan.

On May 15, 2003, IPC amended its indenture and increased the limit of aggregate principal amount of first mortgage bonds that may be outstanding at any one time from $900 million to $1.1 billion.

IPC anticipates refinancing its $49.8 million Pollution Control Revenue Bonds 8.30% Series 1984 due 2014 to take advantage of the current low interest rate environment. These bonds are callable on December 1, 2003 at premium of three percent, but the new pollution control bonds may be issued as early as September 1, 2003.

The following tax credit notes have been issued by IFS during 2003:

		Principal		Interest
Issue Date	Series	Amount		Rate	Maturity
March 12, 2003	2003-1	$	25,475	5.00%	2003 - 2010
July 15, 2003	2003-2		15,000	3.98%	2003 - 2009

Additionally, $25 million of debt was secured by IFS from a corporate lender on July 25, 2003 at an interest rate of 3.65 percent, maturing from 2003-2008.

LEGAL AND ENVIRONMENTAL ISSUES:

Legal and Other Proceedings
California Energy Proceedings at the FERC:
California Refund
The FERC issued its Order on Proposed Findings on Refund Liability on March 26, 2003. In large part, the FERC affirmed the recommendations of its Administrative Law Judge (ALJ). However, the FERC changed a component of the formula the ALJ was to apply when it adopted findings of its staff that published California spot market prices for gas did not reliably reflect the prices a gas market that had not been manipulated would have produced, despite the fact that many gas buyers paid those amounts. The findings of the ALJ, as adjusted by the FERC's March 26, 2003 order, are expected to substantially increase the offsets to amounts still owed by the Cal ISO and the CalPX to the companies. Calculations remain uncertain because the FERC has required the Cal ISO to correct a number of defects in its calculations and because the FERC has stated that if refunds will prevent a seller from recovering its California portfolio costs during the refund period, it will provide an opportunity for a cost showing by such a respondent. As a result, IE is unsure of the impact this ruling will have on the refunds due from California.

IE, along with a number of other parties, filed a petition with the FERC on April 25, 2003 seeking review of the March 26, 2003 order.

Market Manipulation
In a November 20, 2002 order, the FERC permitted discovery and the submission of evidence respecting market manipulation by various sellers during the western power crises of 2000 and 2001.

As a consequence, the California Parties urged the FERC to apply the precepts of its earlier decision, to replace actual prices charged in every hour starting May 1, 2000 through the beginning of the existing refund period (October 2, 2000) with a Mitigated Market Clearing Price, seeking approximately $8 billion in refunds to the Cal ISO and the CalPX. On March 20, 2003, numerous parties, including the companies, submitted briefs and responsive testimony.

potential penalties imposed by the FERC would not have a significant impact on their consolidated financial position, results of operations or cash flows.

Other Legal Proceedings: IDACORP, IPC and/or IE are involved in various lawsuits and legal proceedings, discussed above and in detail in Note 5 to the Consolidated Financial Statements. The companies believe they have defenses to all lawsuits and legal proceedings where they have been named as defendants. Resolution of any of these matters will take time, and the companies cannot predict the outcome of any of these proceedings. The companies believe that their reserves are adequate for these matters. IPC reached a settlement agreement with Idaho Rivers United requiring IPC to pay approximately $101,800.

FERC Investigations Regarding Trading Practices and the California Parties Conduct of Discovery Respecting the Same: In a series of requests for information ending 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 inquiries respecting 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 the various responses sought by the FERC. The May 2002 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 impermissible trading practice described in the Enron memoranda and identified by the FERC. The energy purchased within and exported out of California was resold to supply preexisting load obligations, to supply preexisting term transactions or to supply a contemporaneous sales transaction. The companies denied engaging in the other ten practices 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 practice 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 practice 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.

U.S. Commodity Futures Trading Commission Investigations Regarding Trading Practices: On October 2, 2002, the U.S. Commodity Futures Trading Commission (CFTC) issued a subpoena to IPC requesting, among other things, all records related to all natural gas and electricity trades by IPC involving "round trip trades," also known as "wash trades" or "sell/buyback trades" including, but not limited to those made outside the Western Systems Coordinating Council region. The subpoena applies to both IE and IPC. As discussed above, on May 22, 2002, both IE and IPC responded to a similar request from the FERC stating that they did not engage in "round trip" or "wash" trades. By letter from the CFTC dated October 7, 2002, the Division of Enforcement agreed to hold in abeyance until a later date all items requested in the subpoena with the exception of one paragraph which related to three trades on a certain date with a specific party. The companies provided the requested information.

On January 14, 2003, IPC received a request from the CFTC, pursuant to the October 2002 subpoena, for documents related to "round trip" or "wash trades" and information supplied to energy industry publications. The request applies to both IPC and IE. The companies stated in their response to the CFTC that they did not engage in any "round trip" or "wash trade" transactions and that they believe the only information provided to energy industry publications was actual transaction data. The companies have provided the requested information.

Environmental Issues
Threatened and Endangered Snails: In December 1992, the U.S. Fish and Wildlife Service (USFWS) listed five species of snails that inhabit the middle Snake River as threatened or endangered species under the Endangered Species Act (ESA). In 1995, in preparation for the FERC relicensing of certain of IPC's hydroelectric projects, IPC obtained a permit from the USFWS to study the listed snails. Since that date, IPC has been collecting field data and conducting studies in an effort to determine the status of the listed snails and how they may be affected by a variety of factors, including hydroelectric production, water quality and irrigation practices.

Based upon the studies initiated by IPC in 1995, in July and October of 2002, IPC, in cooperation with the State of Idaho, filed petitions with the USFWS to remove the Bliss Rapids snail and Idaho springsnail from the federal list of threatened and endangered wildlife. Because of the pending relicensing proceedings at the FERC and the ESA consultation between the FERC and the USFWS on the potential effect of project operations on ESA listed snails, IPC submitted the petitions, and the studies upon which they were based, to the FERC for inclusion in the Mid-Snake and CJ Strike relicensing proceedings.

On December 13, 2002, because of inconsistencies discovered between the field data collected by IPC since 1995, the macro invertebrate database into which the field data were entered and the use of that database in the preparation of the studies used to support the pending petitions, IPC notified the USFWS and the FERC that it was withdrawing the petitions. IPC then retained an independent scientist to review the snail studies. This review was completed in April 2003 and IPC submitted the report to the FERC on April 30, 2003.

The report identified various discrepancies in the annual snail survey reports (1995-2001) that were used to support the petitions to delist the Bliss Rapids snail and Idaho springsnail. Generally, these discrepancies included: errors in summarization of field data and the entry of the data into the macroinvertebrate database; errors in compiling data for analysis; calculation or extrapolation errors; and the lack of a standard measure for expressing snail relative abundance data. While the report concluded that annual snail surveys were unreliable because of these discrepancies, it also concluded that the primary or underlying data that were used to prepare the annual survey reports appeared to be complete and, as a consequence, could be used to correct any errors in the annual reports.

Due to the importance of these snail data to issues pending in the relicensing of IPC's hydroelectric projects and the pending ESA consultation between the FERC and the USFWS, IPC retained the independent scientist that conducted the review to analyze the primary data used to prepare the 1995-2001 snail survey reports and to prepare new and corrected annual reports. In its submission to the FERC, IPC has also requested that the pending ESA consultations and other decisions relative to the relicensing of the Mid-Snake and CJ Strike projects be held in abeyance pending preparation of the corrected annual snail survey reports. On June 13, 2003, the FERC responded to IPC's request, advising that it had reviewed the information submitted by IPC on April 30, 2003 and had decided to not hold in abeyance the preparation of licensing orders with regard to the referenced projects and to proceed with the ESA consultation. The FERC also advised that should IPC continue with the revision of the annual reports, and file them with the FERC, the FERC would consider them, and any other information filed by IPC, prior to issuing license orders. Also on June 13, 2003, the FERC requested that the USFWS provide the FERC with final biological opinions for the referenced projects within 60 days of June 13, 2003. IPC is continuing to prepare revised annual snail survey reports for 1995-2001 and, upon completion, will provide them to the FERC for consideration with regard to the licensing of the projects. IPC is uncertain at this time what the corrected reports will show or what their implications, if any, might be for filings IPC has previously made at the FERC, the biological opinions being prepared by the USFWS or the licensing of the referenced projects.

REGULATORY ISSUES:

Deferred Power Supply Costs
IPC's deferred power supply costs consist of the following at:

			June 30,		December 31,
			2003		2002

Oregon deferral			$	13,949	$	14,172

Idaho PCA current year power supply cost deferrals:
	Deferral during the 2003-2004 rate year			3,934		-
	Deferral during the 2002-2003 rate year			-		8,910
	Astaris load reduction agreement			-		27,160

Idaho PCA true-up awaiting recovery:
	Irrigation and small general service deferral for recovery in
		the 2003-2004 rate year		-		12,049
	Industrial customer deferral for recovery in the 2003-2004 rate year			-		3,744
	Remaining true-up authorized May 2002			-		74,253
	Remaining true-up authorized May 2003			47,091		-

	Total deferral		$	64,974	$	140,288

Integrated Resource Plan
Every two years, IPC is required to file with the IPUC and OPUC an IRP, a comprehensive look at IPC's present and future demands for electricity and plans for meeting that demand. The 2002 IRP identified the need for additional resources to address potential electricity shortfalls within IPC's utility service territory by mid-2005.

On February 11, 2003, the IPUC issued Order No. 29189, which accepted and acknowledged IPC's 2002 IRP as modified and directed IPC to implement certain changes in its 2004 IRP related to both the public process and the evaluation of demand-side options. The accepted IRP indicated the purchase of 100 MW from the wholesale market for IPC's retail customers during June, July, November and December. On February 24, 2003, IPC issued a formal RFP seeking bids for the construction of up to 200 MW of additional generation to support the growing seasonal demand for electricity in IPC's service area. Bids were submitted to IPC on April 28, 2003. A proposal for an IPC self-build option was submitted at the same time. IPC is presently in the evaluation phase of the process, which is expected to be completed in the third quarter of 2003.

PPL Montana Power Purchase Agreement: During May 2003, IPC and PPLM entered into a firm wholesale PPA under which IPC will purchase energy from PPLM during the heavy load hours of June, July and August from 2004 through 2009. With the exception of the month of August 2004, in which the quantity of energy to be purchased is 26 MW per hour, during each month of the PPA IPC will purchase 83 MW per hour from PPLM at a price of $44.50 per MWh. After deducting transmission losses, IPC will receive approximately 80 MW per hour. The IPUC approved this PPA on July 8, 2003.

Automatic Meter Reading
On February 21, 2003, the IPUC issued Order No. 29196 which directed IPC to submit a plan no later than March 20, 2003 to replace its existing meters with advanced meters that are capable of both automated meter reading (AMR) and time-of-use pricing. On April 15, 2003, the IPUC issued Order No. 29226, which modified and clarified Order No. 29196. The requirement to commence installation in 2003 was removed; however, IPC is expected to implement AMR as soon as practicable, subject to updated analysis showing AMR to be cost effective for customers. As ordered by the IPUC, IPC submitted an updated analysis on May 9, 2003. A workshop with IPUC staff and other interested parties to discuss the analysis was held on May 19, 2003. The IPUC issued Order No. 29291 on July 14, 2003, providing interested parties the opportunity to submit comments regarding IPC's updated analysis. Should IPC be directed to implement an AMR system, a four-year implementation commencing in 2004 is estimated to cost $86 million. IPC would include these costs in future rate filings.

Relicensing of Hydroelectric Projects
IPC, like other utilities that operate nonfederal hydroelectric projects, obtains licenses for its hydroelectric projects from the FERC. These licenses generally last for 30 to 50 years depending on the size and complexity of the project. Currently, the licenses for five hydroelectric projects have expired. These projects continue to operate under annual licenses until the FERC issues a new permanent license. Three more hydroelectric project licenses will expire by 2010.

IPC is actively pursuing the relicensing of these projects, a process that may continue for the next ten to 15 years. The current status of IPC's relicensing efforts is summarized in the table below.

Projects	Current status
Bliss, Upper Salmon Falls, Lower Salmon Falls, Shoshone Falls and CJ Strike	Annual licenses issued under terms and conditions of the expired permanent license. Final Environmental Impact Statements have been
	issued. FERC licenses anticipated in late 2003.

Upper Malad and Lower Malad	License expires in 2004. New license application filed in July 2002.

Brownlee-Oxbow-Hells Canyon	License expires in 2005. New license application filed in July 2003.

The most significant relicensing effort is the HCC, which provides approximately two-thirds of IPC's hydroelectric generation capacity and 40 percent of its total generating capacity. IPC developed the license application for the HCC through a collaborative process involving representatives of state and federal agencies, businesses, environmental, tribal, customer, local government and local landowner interests. The license application for the HCC was filed in July 2003. The application includes existing and proposed PM&E measures estimated to total (assuming a 30-year license) approximately $106 million in the first five years of the license and $218 million over the following 25 years. However, the actual costs of the PM&E measures and other costs associated with the relicensing of the project will not be known until the new license is issued by the FERC. The current license for the project expires in July 2005. IPC will thereafter operate the project under annual licenses issued by the FERC until the new license is issued.

The four Mid-Snake River projects, Bliss, Upper Salmon Falls, Lower Salmon Falls and Shoshone Falls, and the CJ Strike projects, may affect five species of snails listed under the ESA. See previous discussion in "LEGAL AND ENVIRONMENTAL ISSUES - Environmental Issues - Threatened and Endangered Snails."

At June 30, 2003, $54 million of pre-relicensing costs were included in Construction Work in Progress (CWIP) and $8 million of pre-relicensing costs were included in Electric Plant in Service. The pre-relicensing costs are recorded and held in CWIP until a new permanent license or annual license is issued by the FERC, at which time the charges are transferred to Electric Plant in Service. Pre-relicensing costs as well as costs related to the new licenses, as referenced above, will be submitted to regulators for recovery through the rate-making process. The relicensing process is discussed more fully in IDACORP'S and IPC's Annual Report on Form 10-K for the year ended December 31, 2002.

American Rivers Petition: On May 1, 2003, American Rivers and Idaho Rivers United petitioned the United States Court of Appeals for the District of Columbia Circuit requesting that the court issue a Writ of Mandamus compelling the FERC to respond to a petition American Rivers filed with the FERC in 1997 requesting that the FERC initiate formal consultation pursuant to Section 7(a)(2) of the ESA with the National Marine Fisheries Service (NMFS) on the effects of the ongoing operations of IPC's HCC on four species of Snake River salmon and steelhead trout that are listed as threatened or endangered under the ESA. American Rivers contends that consultation is necessary because the operations of the HCC have a current, adverse impact on the listed anadromous fish.

IPC contested the 1997 petition before the FERC on several bases: first, that there is no evidence to support the American Rivers contention that the operations of the HCC have an adverse impact on ESA listed species; and second, that neither the ESA nor the FPA grant the FERC the type of discretionary federal control that constitutes the consultation-triggering federal action required under Section 7(a)(2) of the ESA. Since 1997, the FERC has taken no action on the pending petition, but has been engaged in informal discussions with IPC and the NMFS on issues associated with the effect of HCC operations on fishery resources below the HCC. Some of these discussions have occurred in the context of the Snake River Basin Adjudication mediation, which is subject to a court imposed confidentiality order.

On June 30, 2003, the FERC filed a response to the Petition for Mandamus. The FERC opposed the petition, first, because there was no federal action before the FERC to trigger a consultation responsibility under ESA Section 7(a)(2); second, because there was no evidence to substantiate the allegations of the petitioners that the ESA listed species have continued to decline since the filing of the original petition with the FERC in 1997; and lastly, because there were no grounds to support the allegations of unreasonable delay given the ongoing interaction between the FERC, IPC and other interested parties with regard to issues associated with the ESA listed species and the HCC. IPC filed a brief in support of the FERC's position on July 3, 2003. The petitioners filed a reply in support of the Petition for Mandamus with the court on July 8, 2003.

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

In October 2000 and March 2002, in response to FERC Order No. 2000, IPC and other regional transmission owners filed Stage One and Stage Two plans to form RTO West, an entity that will operate the transmission grid in seven western states. RTO West will have its own independent governing board. The participating transmission owners will retain ownership of the lines, but will not have a role in operating the grid.

These FERC filings represent a portion of the filing necessary to form RTO West. However, substantial additional filings will be necessary to include the tariff and integration agreements associated with the new entity. State approvals also need to be obtained. In September 2002, the FERC issued an order granting in part RTO West's Stage Two request for a declaratory order, approving with modification the majority of the proposed plan for development of a RTO by ten utilities in the northwest and Canada and the Bonneville Power Association. IPC is one of the filing utilities. With further development of detail and some modification, the FERC stated that the proposal "will satisfy not only the Order No. 2000 requirements, but can also provide a basic framework for standard market design for the west." Further development of the RTO West proposal by the filing utilities continues.

In July 2002, the FERC issued a Notice of Proposed Rulemaking (NOPR) on Standard Market Design (SMD) for regulated utilities. If implemented as proposed, the NOPR will substantially change how wholesale markets operate throughout the United States. The proposed rulemaking expands the FERC's intent to unbundle transmission operations from integrated utilities and ensure robust competition in wholesale markets. The proposed rule contemplates that all wholesale and retail customers will be on a single network transmission service tariff. The proposed rule also contemplates the implementation of a bid-based system for buying and selling energy in wholesale markets to manage congestion. The market would be administered by RTOs, or Independent Transmission Providers. RTOs would also be responsible for putting together regional plans that identify opportunities to construct new transmission, generation or demand-side programs to reduce transmission constraints and meet regional energy requirements. Finally, the proposed rule envisions the development of regional market monitors responsible for ensuring that individual participants do not exercise unlawful market power. Comments to the proposed rules were filed with the FERC in February 2003.

On April 28, 2003, the FERC issued a White Paper, which sets forth the FERC's new wholesale power market platform and identifies revisions to its July 2002 proposed SMD given concerns raised in response to the NOPR. The White Paper emphasizes a focus on the formation of RTOs and on ensuring that all independent transmission organizations have sound market rules. The White Paper further indicates that the implementation schedule will vary depending on regional needs and will also allow for regional differences. This White Paper was developed based on input from numerous state regulatory agencies, utility companies, industry and consumer groups, as well as the public. The FERC's stated goals with respect to wholesale power markets include: reliable and reasonably priced electric service for all customers; sufficient electric infrastructure; transparent markets with fair rules for all market participants; stability and regulatory certainty for customers, the electric power industry, and investors; technological innovation; and efficient use of the nation's resources. The White Paper proposes a significant role being played by regional authorities in setting up regional power markets. IPC is evaluating the White Paper and recognizes there is uncertainty regarding the timing and outcome of the rulemaking. Accordingly, the likely impact on IPC's operations is unknown.

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

IDACORP and IPC are exposed to various market risks, including changes in interest rates, changes in certain commodity prices, credit risk and equity price risk. Interest rate risk and equity price risk have not changed materially from those reported in the Annual Report on Form 10-K for the year ended December 31, 2002.

Commodity Price Risk
Utility: IPC's commodity price risk has not changed materially from that reported in the Annual Report on Form 10-K for the year ended December 31, 2002.

Energy Trading: IE buys and sells financial and physical natural gas and electricity commodity contracts as part of its business, exposing IE to electricity and natural gas commodity price risk as well as interest rate risk. IE has a risk management policy defining the limits within which it contains its commodity price risk. IE trades commodity futures, forwards, options and swaps as a method of managing the commodity price risk and optimizing the profitability of its electricity and natural gas trading. IE also transacts in interest rate futures and swaps to manage the interest rate risk embedded in its commodity portfolio.

When buying and selling energy, the volatility of energy prices can have a significant negative impact on profitability if not appropriately managed. Also, counterparty creditworthiness is key to ensuring that transactions entered into can withstand potentially dramatic market fluctuations. To manage the risks inherent in the energy commodity industry, IE's Risk Management Committee (RMC), comprised of IDACORP and IE officers, oversees IE's risk management program as defined in the risk management policy. The objective of IE's risk management program is to manage the risk associated with the purchase and sale of natural gas and electricity within levels established by the RMC. IE's policy also allows the use of these commodity derivative instruments for trading purposes in support of its operations.

The value-at-risk (VAR) measure is a tool used by IE's RMC to understand on a daily basis the potential impact on earnings arising from changes in market prices.

The June 30, 2003 VAR for energy marketing operations is approximately $197,000 at a 95 percent confidence level and $278,000 at a 99 percent confidence level, both for a holding period of one business day. The average VAR for the three months ended June 30, 2003, at a 95 percent confidence level and one-day holding period, was approximately $205,000 compared to $1.5 million during the three months ended June 30, 2002. The average VAR for the six months ended June 30, 2003, at a 95 percent confidence level and one-day holding period was approximately $313,000 compared to $1.4 million during the six months ended June 30, 2002. The VAR was calculated using an analytic VAR methodology. This methodology computes VAR based upon positions and forward market prices as of June 30, 2003, and historical forward price volatility and correlation. The VAR is understood to be a forecast and is not guaranteed to occur. The 95 percent confidence level and one-day holding period imply that there is a five percent chance that the daily loss will exceed approximately $197,000. The 99 percent confidence level implies a one percent chance that daily loss will exceed $278,000. The VAR calculation is principally affected by market prices and volatility of prices. The RMC actively manages the risk to keep IE's trading activities within trading limits.

Credit Risk
Utility: IPC's credit risk has not changed materially from that reported in the Annual Report on Form 10-K for the year ended December 31, 2002.

Energy Trading: IE is exposed to counterparty credit risk as part of its energy trading business. This risk is defined as exposure to decreases in expected earnings or cash flow when a counterparty to an energy commodity contract cannot or will not pay or deliver. To manage counterparty credit risk within acceptable levels, the RMC has established credit risk limits for each counterparty. Credit risk exposure is measured and reported daily to members of the RMC. In order to provide further protection from a counterparty's deteriorating creditworthiness, IE utilizes industry standard agreements containing various protective creditworthiness provisions. Other tools used to manage credit risk are the holding of collateral in the form of cash or letters of credit and the use of margining agreements with counterparties when credit risk exceeds certain pre-determined thresholds. Because of the volatile nature of energy market prices, margining agreements can require the posting of large amounts of cash between counterparties to hold as collateral against the value of the energy contracts. This practice mitigates credit risk but increases the need for cash or other liquid securities to ensure the ability to meet all margin requirements when the markets are most volatile.

At June 30, 2003, 66 percent of the credit exposure related to IE's unrealized positions was with investment grade counterparties, seven percent was with non-investment grade counterparties and the remaining 27 percent was with non-rated counterparties. The majority of the non-rated entities are municipalities, public utility districts and electric cooperatives. More than 50 percent of IE's total credit exposure is to one investment grade counterparty under a contract with less than two years remaining. The following table presents the maturity of credit risk exposure for energy marketing at June 30, 2003:

		Less than		2-5		More than
		2 Years		Years		5 Years			Total
Investment Grade		$	63,751	$	2,270	$		1,342	$	67,363
Non-Investment Grade			3,793		3,270			-		7,063
No External Ratings			22,483		5,265			525		28,273
	Total	$	90,027	$	10,805		$	1,867	$	102,699

ITEM 4. CONTROLS AND PROCEDURES

(a) Disclosure controls and procedures:

The Chief Executive Officer and Chief Financial Officer of IDACORP, Inc., based on their evaluation of IDACORP, Inc.'s disclosure controls and procedures (as defined in Exchange Act Rule 13a-15(e)) as of June 30, 2003, have concluded that IDACORP, Inc.'s disclosure controls and procedures are effective.

The Chief Executive Officer and Chief Financial Officer of Idaho Power Company, based on their evaluation of Idaho Power Company's disclosure controls and procedures (as defined in Exchange Act Rule 13a-15(e)) as of June 30, 2003, have concluded that Idaho Power Company's disclosure controls and procedures are effective.

(b) Changes in internal control over financial reporting:

There has been no change in IDACORP, Inc.'s or Idaho Power Company's internal control over financial reporting identified in connection with the evaluation required by Exchange Act Rule 13a-15(d) that occurred during IDACORP, Inc.'s or Idaho Power Company's most recent fiscal quarter that has materially affected, or is reasonably likely to materially affect IDACORP, Inc.'s or Idaho Power Company's internal control over financial reporting.

PART II - OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS

Reference is made to Note 5 to the Consolidated Financial Statements in this Quarterly Report on Form 10-Q and the Quarterly Report on Form 10-Q for the three months ended March 31, 2003.

ITEM 2. CHANGES IN SECURITIES AND USE OF PROCEEDS

As part of their compensation, directors of IDACORP, Inc. who are not employees each received a grant of common stock equal to $16,000 on July 18, 2003. 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

IDACORP, Inc.:

(a)

Regular annual meeting of IDACORP, Inc.'s stockholders, held May 15, 2003 in Boise,

Idaho.

(b)

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

Christopher L. Culp

Peter S. O'Neill

Gary G. Michael

Jan B. Packwood

Continuing Directors:

Rotchford L. Barker

Evelyn Loveless

John B. Carley

Jon H. Miller

Jack K. Lemley

Robert A. Tintsman

(c)

To elect four Director Nominees:

Name

For

Withheld

Total Voted

Christopher L. Culp

29,936,048

1,228,474

31,164,522

Gary G. Michael

29,908,954

1,225,568

31,164,522

Peter S. O'Neill

30,242,195

922,327

31,164,522

Jan B. Packwood

30,235,671

928,851

31,164,522

To ratify the selection of Deloitte & Touche LLP as independent auditors for

the fiscal year ending December 31, 2003:

Class of Stock

For

Against

Abstain

Total Voted

Common

29,706,328

1,176,819

281,375

31,164,522

Idaho Power Company:

(a)		Regular annual meeting of Idaho Power Company's stockholders, held May 15,
		2003 in Boise, Idaho.

(b)		Directors elected at the meeting for a three-year term:
				Christopher L. Culp						Peter S. O'Neill
				Gary G. Michael						Jan B. Packwood

		Continuing Directors:
				Rotchford L. Barker						Evelyn Loveless
				John B. Carley						Jon H. Miller
				Jack K. Lemley						Robert A. Tintsman

(c)	1)	To elect four Director Nominees:

						Common			4% Preferred				7.68% Preferred
		Name				For	Withheld		For			Withheld	For		Withheld
		Christopher L. Culp				37,612,351	-		1,781,140			16,280	88,273		1190
		Gary G. Michael				37,612,351	-		1,768,820			28,600	88,273		1190
		Peter S. O'Neill				37,612,351	-		1,780,040			17,380	88,273		1190
		Jan B. Packwood				37,612,351	-		1,775,160			22,260	88,273		1190

	2)	To ratify the selection of Deloitte & Touche LLP as independent auditors for
		the fiscal year ending December 31, 2003:

		Class of Stock			For			Against			Abstain			Total Voted
		Common			37,612,351			-			-			37,612,351
		4% Preferred			1,771,020			15,040			11,360			1,797,420
		7.68% Preferred			88,588			400			475			89,463
			Total		39,471,959			15,440			11,835			39,499,234

ITEM 5. OTHER INFORMATION

Evelyn Loveless resigned from the Board of Directors of IDACORP, Inc. and Idaho Power Company in July 2003 because she reached the mandatory retirement age of 70. Ms. Loveless served with distinction as director of Idaho Power Company since 1987 and IDACORP, Inc. since 1998.

ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K

(a) Exhibits.

*Previously Filed and Incorporated Herein by Reference

Exhibit	File Number	As Exhibit

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

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

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

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

*3(a)(iii)	1-3198 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 3/31/03	3(b)	By-laws of IPC amended on March 20, 2003, 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.

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

*3(d)(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(d)(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(e)	333-104254	4(e)	Amended Bylaws of IDACORP, Inc. amended on March 20, 2003, and presently in effect.

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

*4(a)(ii)			IPC Supplemental Indentures to Mortgage and Deed of Trust:

			Number	Dated
	1-MD	B-2-a	First	July 1, 1939
	2-5395	7-a-3	Second	November 15, 1943
	2-7237	7-a-4	Third	February 1, 1947
	2-7502	7-a-5	Fourth	May 1, 1948
	2-8398	7-a-6	Fifth	November 1, 1949
	2-8973	7-a-7	Sixth	October 1, 1951
	2-12941	2-C-8	Seventh	January 1, 1957
	2-13688	4-J	Eighth	July 15, 1957
	2-13689	4-K	Ninth	November 15, 1957
	2-14245	4-L	Tenth	April 1, 1958
	2-14366	2-L	Eleventh	October 15, 1958
	2-14935	4-N	Twelfth	May 15, 1959
	2-18976	4-O	Thirteenth	November 15, 1960
	2-18977	4-Q	Fourteenth	November 1, 1961
	2-22988	4-B-16	Fifteenth	September 15, 1964
	2-24578	4-B-17	Sixteenth	April 1, 1966
	2-25479	4-B-18	Seventeenth	October 1, 1966
	2-45260	2(c)	Eighteenth	September 1, 1972
	2-49854	2(c)	Nineteenth	January 15, 1974
	2-51722	2(c)(i)	Twentieth	August 1, 1974
	2-51722	2(c)(ii)	Twenty-first	October 15, 1974
	2-57374	2(c)	Twenty-second	November 15, 1976
	2-62035	2(c)	Twenty-third	August 15, 1978
	33-34222	4(d)(iii)	Twenty-fourth	September 1, 1979
	33-34222	4(d)(iv)	Twenty-fifth	November 1, 1981
	33-34222	4(d)(v)	Twenty-sixth	May 1, 1982
	33-34222	4(d)(vi)	Twenty-seventh	May 1, 1986
	33-00440	4(c)(iv)	Twenty-eighth	June 30, 1989
	33-34222	4(d)(vii)	Twenty-ninth	January 1, 1990
	33-65720	4(d)(iii)	Thirtieth	January 1, 1991
	33-65720	4(d)(iv)	Thirty-first	August 15, 1991
	33-65720	4(d)(v)	Thirty-second	March 15, 1992
	33-65720	4(d)(vi)	Thirty-third	April 1, 1993
	1-3198 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	Thirty-sixth	October 1, 2001

	1-3198 Form 8-K Dated 4/15/03	4	Thirty-seventh	April 1, 2003

4(a)(iii)			Thirty-eighth	May 15, 2003

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

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

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

*4(e)	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 to The Bank of New York, as Rights Agent.

*4(f)	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 Deutsche Bank Trust Company Americas (formerly known as Bankers Trust Company), as trustee.

*4(g)	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 Deutsche Bank Trust Company Americas (formerly known as Bankers Trust Company), as trustee.

*4(h)	333-67748	4.13	Indenture for Debt Securities dated as of August 1, 2001 between Idaho Power Company and Deutsche Bank Trust Company Americas (formerly known as Bankers Trust Company), as trustee.

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

*10(h)(ii) 1	1-14465 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	1-14465 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 8, 1999, as amended.

*10(h)(v) 1	1-14465 1-3198 Form 10-K for 2002	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-Q for 6/30/99	10(g)	Executive Employment Agreement dated April 12, 1999 between IPC and Marlene Williams.

*10(h)(vii)	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, Darrel T. Anderson, Bryan Kearney, Robert W. Stahman and Marlene K. Williams.

*10(h)(viii) 1	1-14465 1-3198 Form 10-Q for 3/31/02	10(i) 10(h)(ix)	IDACORP, Inc. 2000 Long-Term Incentive and Compensation Plan, as amended.

*10(h)(ix) 1	1-14465 1-3198 Form 10-K for 2002	10(h)(x)	IDACORP Energy, L.P. 2002 Incentive Plan.

*10(h)(x) 1	1-14465 1-3198 Form 10-K for 2002	10(h)(xi)	IDACORP, Inc. 2002 Executive Incentive Plan.

*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.

1 Compensatory plan


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

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

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

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

10(k)			Power Purchase Agreement between IPC and PPL Montana, LLC, dated March 1, 2003 and Revised Confirmation Agreement dated May 9, 2003.

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

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

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

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

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

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

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

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

15			Letter Re: Unaudited Interim Financial Information

*21	1-14465 1-3198 Form 10-K for 2002	21	Subsidiaries of IDACORP, Inc. and IPC.

31(a)			Rule 13a-14(a) certification.

31(b)			Rule 13a-14(a) certification.

31(c)			Rule 13a-14(a) certification.

31(d)			Rule 13a-14(a) certification.

32(a)			Section 1350 certification.

32(b)			Section 1350 certification.

(b) Reports on SEC Form 8-K. The following Reports on Form 8-K were filed for the three months ended June 30, 2003:

Items Reported	Date of Report	Filed by
Item 7 - Financial Statements and Exhibits	April 15, 2003	Idaho Power Company
Item 7 - Financial Statements and Exhibits	May 1, 2003	IDACORP, Inc. and Idaho Power Company
Item 7 - Financial Statements and Exhibits	May 7, 2003	IDACORP, Inc. and Idaho Power Company
Items 5 and 7- Other Events and Regulation FD	May 16, 2003	IDACORP, Inc. and Idaho Power Company
Disclosure and Financial Statements and Exhibits

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 7, 2003	By:	/s/	Jan B. Packwood
				Jan B. Packwood
				President and Chief Executive Officer
				and Director

Date	August 7, 2003	By:	/s/	Darrel T. Anderson
				Darrel T. Anderson
				Vice President, Chief Financial Officer
				and Treasurer
				(Principal Accounting Officer)

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 7, 2003	By:	/s/	J. LaMont Keen
				J. LaMont Keen
				President and Chief Operating Officer

Date	August 7, 2003	By:	/s/	Darrel T. Anderson
				Darrel T. Anderson
				Vice President, Chief Financial Officer
				and Treasurer
				(Principal Accounting Officer)

	Exact name of registrants as specified	I.R.S. Employer
Commission File	in their charters, state of incorporation, address	Identification
Number	of principal executive offices, and telephone number	Number
1-14465	IDACORP, Inc.	82-0505802
1-3198	Idaho Power Company	82-0130980
	1221 W. Idaho Street
	Boise, ID 83702-5627

	Telephone: (208) 388-2200
	State of Incorporation: Idaho
	Web site: www.idacorpinc.com

Page

Part I. Financial Information:
	Item 1. Financial Statements (unaudited)
		IDACORP, Inc.:
			Consolidated Statements of Operations	1-2
			Consolidated Balance Sheets	3-4
			Consolidated Statements of Cash Flows	5
			Consolidated Statements of Comprehensive Income (Loss)	6
			Notes to Consolidated Financial Statements	7-24
			Independent Accountants' Report	25
		Idaho Power Company:
			Consolidated Statements of Income	26-27
			Consolidated Balance Sheets	28-29
			Consolidated Statements of Capitalization	30
			Consolidated Statements of Cash Flows	31
			Consolidated Statements of Comprehensive Income	32
			Notes to Consolidated Financial Statements	33-34
			Independent Accountants' Report	35

	Item 2. Management's Discussion and Analysis of Financial
		Condition and Results of Operations		36-58

	Item 3. Quantitative and Qualitative Disclosures about Market Risk			58-60

	Item 4. Controls and Procedures			60

Part II. Other Information:

	Item 1. Legal Proceedings			61

	Item 2. Changes in Securities and Use of Proceeds			61

	Item 4. Submission of Matters to a Vote of Security Holders			61-62

	Item 5. Other Information			62

	Item 6. Exhibits and Reports on Form 8-K			63-68

Signatures				69-70

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

IDACORP, Inc.:	38,196,287
Idaho Power Company:	37,612,351 all held by IDACORP, Inc.

COMMONLY USED TERMS

AFDC	-	Allowance for Funds Used During Construction
ALJ	-	Administrative Law Judge
APB	-	Accounting Principles Board
Cal ISO	-	California Independent System Operator
CalPX	-	California Power Exchange
EPA	-	Environmental Protection Agency
EPS	-	Earnings per share
FASB	-	Financial Accounting Standards Board
FERC	-	Federal Energy Regulatory Commission
FPA	-	Federal Power Act
GAAP	-	Accounting Principles Generally Accepted in the United States of America
HCC	-	Hells Canyon Complex
Ida-West	-	Ida-West Energy, a subsidiary of IDACORP, Inc.
IE	-	IDACORP Energy, a subsidiary of IDACORP, Inc.
IFS	-	IDACORP Financial Services, Inc., a subsidiary of IDACORP, Inc.
IPC	-	Idaho Power Company, a subsidiary of IDACORP, Inc.
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
PCA	-	Power Cost Adjustment
PG&E	-	Pacific Gas and Electric Company
PM&E	-	Protection, Mitigation and Enhancement
PPA	-	Power Purchase Agreement
PPLM	-	PPL Montana, LLC
REA	-	Rural Electrification Administration
RMC	-	Risk Management Committee
RTOs	-	Regional Transmission Organizations
SCE	-	Southern California Edison
SFAS	-	Statement of Financial Accounting Standards
SPPCo	-	Sierra Pacific Power Company

Three Months Ended

Six Months Ended

Date of Report

Filed by