IDACORP INC - 10-Q Quarterly Report

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

				Three Months Ended September 30,
				2003		2002
				(thousands of dollars except for per
				share amounts)
OPERATING REVENUES:
	Electric utility:
		General business		$	188,247	$	216,452
		Off-system sales			16,442		10,859
		Other revenues			10,172		10,217
			Total electric utility revenues		214,861		237,528
	Energy marketing				17,193		18,917
	Other				7,174		3,131
		Total operating revenues			239,228		259,576

OPERATING EXPENSES:
	Electric utility:
		Purchased power			77,280		50,240
		Fuel expense			25,606		26,529
		Power cost adjustment			(9,787)		57,153
		Other operations and maintenance			54,276		53,139
		Depreciation			24,439		23,577
		Taxes other than income taxes			5,164		5,069
			Total electric utility expenses		176,978		215,707
	Energy marketing:
		Cost of revenues			(1,733)		12,335
		Selling, general and administrative			8,070		5,887
	Other				7,939		9,027
			Total operating expenses		191,254		242,956

OPERATING INCOME (LOSS):
	Electric utility				37,883		21,821
	Energy marketing				10,856		695
	Other				(765)		(5,896)
		Total operating income			47,974		16,620

OTHER INCOME (EXPENSE)					2,131		(1,373)

INTEREST EXPENSE AND OTHER:
	Interest on long-term debt				14,571		13,089
	Other interest				407		2,858
	Preferred dividends of Idaho Power Company				847		919
		Total interest expense and other			15,825		16,866

INCOME (LOSS) BEFORE INCOME TAXES					34,280		(1,619)

INCOME TAX EXPENSE (BENEFIT)					(12,495)		(38,527)

NET INCOME				$	46,775	$	36,908

AVERAGE COMMON SHARES
	OUTSTANDING (000's)				38,200		37,771

EARNINGS PER SHARE OF COMMON
	STOCK (basic and diluted)			$	1.22	$	0.98

The accompanying notes are an integral part of these statements.

IDACORP, Inc.
Consolidated Statements of Income
(unaudited)

				Nine Months Ended September 30,
				2003		2002
				(thousands of dollars except for per
				share amounts)
OPERATING REVENUES:
	Electric utility:
		General business		$	529,922	$	590,136
		Off-system sales			54,889		41,994
		Other revenues			31,100		30,079
			Total electric utility revenues		615,911		662,209
	Energy marketing				19,733		36,848
	Other				15,788		9,944
		Total operating revenues			651,432		709,001

OPERATING EXPENSES:
	Electric utility:
		Purchased power			122,904		111,614
		Fuel expense			75,052		76,165
		Power cost adjustment			67,443		133,378
		Other operations and maintenance			164,398		155,750
		Depreciation			72,853		69,932
		Taxes other than income taxes			15,572		15,415
			Total electric utility expenses		518,222		562,254
	Energy marketing:
		Cost of revenues			1,972		36,802
		Selling, general and administrative			21,254		16,470
		Net (gain) loss on legal disputes			10,938		(2,775)
	Other				25,637		24,630
			Total operating expenses		578,023		637,381

OPERATING INCOME (LOSS):
	Electric utility				97,689		99,955
	Energy marketing				(14,431)		(13,649)
	Other				(9,849)		(14,686)
		Total operating income			73,409		71,620

OTHER INCOME					6,132		6,348

INTEREST EXPENSE AND OTHER:
	Interest on long-term debt				44,213		40,170
	Other interest				2,418		8,065
	Preferred dividends of Idaho Power Company				2,581		3,579
		Total interest expense and other			49,212		51,814

INCOME BEFORE INCOME TAXES					30,329		26,154

INCOME TAX EXPENSE (BENEFIT)					(12,495)		(38,527)

NET INCOME				$	42,824	$	64,681

AVERAGE COMMON SHARES
	OUTSTANDING (000's)				38,179		37,665

EARNINGS PER SHARE OF COMMON
	STOCK (basic and diluted)			$	1.12	$	1.72

The accompanying notes are an integral part of these statements.

IDACORP, Inc.
Consolidated Balance Sheets
(unaudited)

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

CURRENT ASSETS:
	Cash and cash equivalents		$	26,194	$	42,736
	Receivables:
		Customer		115,572		176,846
		Allowance for uncollectible accounts		(43,057)		(43,311)
		Employee notes		8,113		7,646
		Other		12,877		11,881
	Energy marketing assets			1,775		85,138
	Accrued unbilled revenues			28,456		35,714
	Materials and supplies (at average cost)			21,595		22,812
	Fuel stock (at average cost)			4,387		6,943
	Prepayments			29,552		34,872
	Regulatory assets			7,017		17,147
		Total current assets		212,481		398,424

INVESTMENTS				203,755		206,348

PROPERTY, PLANT AND EQUIPMENT:
	Utility plant in service			3,164,212		3,086,965
	Accumulated provision for depreciation			(1,363,765)		(1,294,961)
		Utility plant in service - net		1,800,447		1,792,004
	Construction work in progress			110,552		96,209
	Utility plant held for future use			2,705		2,335
	Other property, net of accumulated depreciation			10,667		15,950
		Property, plant and equipment - net		1,924,371		1,906,498

OTHER ASSETS:
	American Falls and Milner water rights			31,585		31,585
	Company-owned life insurance			35,748		35,299
	Energy marketing assets - long-term			17,275		64,733
	Regulatory assets			424,961		482,159
	Long-term receivable			43,457		73,941
	Other			54,534		50,507
		Total other assets		607,560		738,224

		TOTAL	$	2,948,167	$	3,249,494

The accompanying notes are an integral part of these statements.

IDACORP, Inc.
Consolidated Balance Sheets
(unaudited)

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

CURRENT LIABILITIES:
	Current maturities of long-term debt			$	70,183	$	89,592
	Notes payable				25,044		176,200
	Accounts payable				54,305		130,930
	Energy marketing liabilities				4,861		59,917
	Taxes accrued				96,019		46,565
	Interest accrued				22,649		13,639
	Deferred income taxes				4,869		21,203
	Other				27,040		35,119
		Total current liabilities			304,970		573,165

OTHER LIABILITIES:
	Deferred income taxes				538,976		595,820
	Energy marketing liabilities - long-term				17,275		51,761
	Regulatory liabilities				114,126		114,247
	Other				98,891		87,605
		Total other liabilities			769,268		849,433

LONG-TERM DEBT					951,956		898,676

COMMITMENTS AND CONTINGENT LIABILITIES

PREFERRED STOCK OF IDAHO POWER COMPANY					52,484		53,393

SHAREHOLDERS' EQUITY:
	Common stock, no par value (shares authorized 120,000,000;
		38,341,358 and 38,152,436 shares issued, respectively)			473,884		470,361
	Retained earnings				404,877		415,315
	Accumulated other comprehensive income (loss)				(4,734)		(7,109)
	Treasury stock at cost (134,737 and 134,667 shares, respectively)				(4,538)		(3,740)
		Total shareholders' equity			869,489		874,827

			TOTAL	$	2,948,167	$	3,249,494

The accompanying notes are an integral part of these statements.

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

				Nine Months Ended
				September 30,
				2003		2002
				(thousands of dollars)
OPERATING ACTIVITIES:
	Net income			$	42,824	$	64,681
	Adjustments to reconcile net income to net cash provided by
		operating activities:
		Net non-cash loss on legal disputes			10,938		-
		Allowance for uncollectible accounts			(254)		17
		Unrealized losses from energy marketing activities			42,517		37,325
		Depreciation and amortization			97,802		91,193
		Deferred taxes and investment tax credits			(71,466)		(91,729)
		Accrued PCA costs			65,446		128,215
		Change in:
			Receivables and prepayments		71,248		42,914
			Accrued unbilled revenues		7,258		8,658
			Materials and supplies and fuel stock		3,773		(791)
			Accounts payable and other accrued liabilities		(71,355)		(148,962)
			Taxes receivable/accrued		49,453		79,958
			Other current assets and liabilities		978		26,723
		Other - net			8,021		4,597
			Net cash provided by operating activities		257,183		242,799

INVESTING ACTIVITIES:
	Additions to property, plant and equipment				(97,567)		(88,797)
	Investments in low-income housing projects				-		(43,843)
	Other - net				(3,779)		(3,565)
		Net cash used in investing activities			(101,346)		(136,205)

FINANCING ACTIVITIES:
	Proceeds from issuance of first mortgage bonds				140,000		-
	Proceeds from issuance of other long-term debt				65,492		-
	Retirement of first mortgage bonds				(160,000)		(50,000)
	Retirement of other long-term debt				(11,769)		(11,979)
	Retirement of preferred stock of Idaho Power Company				(909)		(50,402)
	Dividends on common stock				(53,260)		(52,545)
	Change in short-term borrowings				(151,175)		53,241
	Common stock issued				4,123		12,140
	Acquisition of treasury shares				(798)		(998)
	Other - net				(4,083)		(3,072)
		Net cash used in financing activities			(172,379)		(103,615)

Net increase (decrease) in cash and cash equivalents					(16,542)		2,979

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

Cash and cash equivalents end of period				$	26,194	$	69,667

SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION:
	Cash paid (received) during the period for:
		Income taxes		$	15,677	$	(21,717)
		Interest (net of amount capitalized)		$	35,765	$	40,922

The accompanying notes are an integral part of these statements.

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

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

NET INCOME				$	46,775	$	36,908

OTHER COMPREHENSIVE INCOME (LOSS):
	Unrealized gains (losses) on securities:
		Unrealized holding gains (losses) arising during the period,
			net of tax of $296 and ($1,212)		521		(1,865)
		Reclassification adjustment for (gains) losses included
			in net income, net of tax of ($111) and $553		(172)		851
			Net unrealized gains (losses)		349		(1,014)

TOTAL COMPREHENSIVE INCOME				$	47,124	$	35,894

				Nine Months Ended
				September 30,
				2003		2002
				(thousands of dollars)

NET INCOME				$	42,824	$	64,681

OTHER COMPREHENSIVE INCOME (LOSS):
	Unrealized gains (losses) on securities:
		Unrealized holding gains (losses) arising during the period,
			net of tax of $1,291 and ($1,968)		2,189		(3,088)
		Reclassification adjustment for losses included
			in net income, net of tax of $120 and $538		186		827
			Net unrealized gains (losses)		2,375		(2,261)

TOTAL COMPREHENSIVE INCOME				$	45,199	$	62,420

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 an electric utility engaged in the generation, transmission, distribution, sale and purchase of electric energy. IPC is regulated by the Federal Energy Regulatory Commission (FERC) and the state regulatory commissions of Idaho and 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 of IDACORP, IDACORP Energy (IE), a marketer of electricity and natural gas, is in the process of winding down its operations.

IDACORP's other operating subsidiaries include:

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 September 30, 2003, consolidated results of operations for the three and nine months ended September 30, 2003 and 2002, and consolidated cash flows for the nine months ended September 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 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 721,800 shares of common stock were not included in computing diluted EPS for the three and nine months ended September 30, 2003, because the options' exercise prices were greater than the average market price of the common stock during the period. For the same periods in 2002, 849,000 options were excluded from the diluted EPS calculation for the same reason. In total, 1,150,800 options were outstanding at September 30, 2003, with expiration dates between 2010 and 2013.

Stock-Based Compensation
At September 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 period-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 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				Nine Months Ended
			September 30,				September 30,
			2003		2002		2003		2002

Net income, as reported			$	46,775	$	36,908	$	42,824	$	64,681
Add: Stock-based employee compensation expense included
	in reported net income, net of related tax effects			63		19		125		12
Deduct: Total stock-based employee compensation expense
	determined under fair value based method for all awards,
	net of related tax effects			384		551		801		1,737
		Pro forma net income	$	46,454	$	36,376	$	42,148	$	62,956
Earnings per share:
	Basic and diluted - as reported		$	1.22	$	0.98	$	1.12	$	1.72
	Basic and diluted - pro forma			1.22		0.96		1.10		1.67

Adopted Accounting Pronouncements
SFAS 143: 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 records regulatory assets and liabilities instead of accretion, depreciation and gains or losses, and has applied for an accounting order from the Idaho Public Utilities Commission (IPUC) and expects to apply for an accounting order from the Oregon Public Utility Commission (OPUC) supporting such treatment. The regulatory assets recorded in relation to SFAS 143 do not earn a return on investment.

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 were identified. Upon adoption, 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 collectremoval 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 September 30, 2003, IPC estimated that it had approximately $141 million of such regulatory liabilities presented in its Consolidated Balance Sheet in Accumulated Provision for Depreciation.

An ARO also exists for the reclamation of the Bridger Coal mine property, which is leased by Bridger Coal Company, an equity-method investee of IPC. As Bridger Coal Company 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 Company, as Bridger Coal Company also is applying regulatory accounting, recording regulatory assets and liabilities instead of accretion, depreciation and gains or losses.

If the requirements of SFAS 143 had been applied to prior reporting periods, IDACORP's and IPC's liability for AROs would have been $7 million at December 31, 2002 and $6 million at December 31, 2001.

SFAS 149: In April 2003, the Financial Accounting Standards Board (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 noted 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 were effective for fiscal quarters that began prior to June 15, 2003 continue to be applied in accordance with their respective effective dates. The adoption of SFAS 149 did not have a material effect on IDACORP's or IPC's financial statements.

SFAS 150: In May 2003, the FASB issued SFAS 150, "Accounting for 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
FIN 46: 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 nine months of 2003, IDACORP and IPC 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 and IPC must apply the provisions of FIN 46 in the fourth quarter of 2003.

IDACORP and IPC are in the final stages of their analysis of FIN 46 and the majority of their investments are not expected to meet the criteria for consolidation included in FIN 46. Having considered the facts described herein, IDACORP and IPC do not expect the adoption of this standard to have a material effect on their financial statements.

Reclassifications
Certain items previously reported for periods prior to September 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 to compute its provision for income taxes on an interim basis. IDACORP's effective tax rate for the nine months ended September 30, 2003 was negative 41.2 percent compared with an effective tax rate of negative 147.3 percent for the nine months ended September 30, 2002. The negative tax rate for the nine months ended September 30, 2003 reflects the expectation that annual tax credits and favorable tax resolutions will provide tax benefits that exceed the tax expense related to pre-tax earnings. The negative tax rate for the nine months ended September 30, 2002 reflected a non-recurring tax benefit of $31 million related to a tax accounting method change adopted during the third quarter of 2002. Had the benefit been excluded, the tax rate would have been negative 28.8 percent. The negative tax rates, when adjusted to remove the non-recurring tax benefit related to the tax accounting method change of $31 million in 2002, for both nine month periods ended September 30 are primarily the result of the realization of low-income housing tax credits.

3. CAPITAL STOCK:

Common Stock
During the nine months ended September 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 38,851 treasury shares and issued 38,781 treasury shares for its Restricted Stock Plan and Directors' Stock Plan and to shareholders of Velocitus.

Preferred Stock of Idaho Power Company
During the nine months ended September 30, 2003, IPC reacquired and retired 9,091 shares of 4% preferred stock.

4. FINANCING:

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

			September 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				1,125		1,185

American Falls bond guarantee				19,885		19,885

Milner Dam note guarantee				11,700		11,700

Unamortized premium/discount - net				(2,257)		(2,405)

Debt related to investments in low-income housing				53,476		37,428

Tax credit notes				37,745		-

Other subsidiary debt				5		15
	Total			1,022,139		988,268
Current maturities of long-term debt				(70,183)		(89,592)

		Total long-term debt	$	951,956	$	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 September 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 September 30, 2003, $160 million remained available to be issued on this shelf registration statement.

IDACORP has a $175 million credit facility that expires on March 17, 2004, and a $140 million credit facility that expires on March 26, 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 September 30, 2003, IDACORP's short-term borrowings totaled $11 million.

At September 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 17, 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 September 30, 2003, IPC's short-term borrowings totaled $14 million.

On October 22, 2003, Humboldt County, Nevada issued, for the benefit of IPC, $49.8 million Pollution Control Revenue Refunding Bonds (Idaho Power Company Project) Series 2003 due December 1, 2024. IPC borrowed the proceeds from the issuance pursuant to a Loan Agreement with Humboldt County and is responsible for payment of principal, premium, if any, and interest on the bonds. The bonds are secured, as to principal and interest, by IPC first mortgage bonds and as to principal and interest when due, by an insurance policy issued by Ambac Assurance Corporation. The bonds were issued in an auction rate mode under which the interest rate is reset every 35 days. The initial auction rate was set at 0.95 percent. Proceeds from this issuance together with other funds provided by IPC will be used to redeem the outstanding $49.8 million Pollution Control Revenue Bonds (Idaho Power Company Project) 8.3% Series 1984 due 2014, which have been called for redemption on December 1, 2003, at 103%.

The following tax credit notes were 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, IFS borrowed $25 million from a corporate lender on July 25, 2003 at an interest rate of 3.65 percent. This debt matures from 2003-2008.

Proceeds from the issuance of these debt instruments were primarily used by IFS to pay intercompany notes to IDACORP, which then used the proceeds to reduce 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., an inactive 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 Co. in December 2000.

Under the terms of the contract, IDACORP Services Co. 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 Co. notified United Systems that IDACORP Services Co. 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 Co. 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 Co. On September 9, 2002, all defendants moved to bifurcate the piercing of the corporate veil claims from the remainder of plaintiff's claims. On October 4, 2002, United Systems filed a Motion for Partial Summary Judgment as to their damages. On July 9, 2003, the Court denied Plaintiff's Motion for Partial Summary Judgment and granted Defendants' Motion to Bifurcate. On October 29, 2003, IDACORP agreed to pay $712,500 to settle this dispute with United Systems in return for dismissal of the proceeding with prejudice. The settlement is expected to be final on or before November 28, 2003.

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 megawatt-hour (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 because the FERC has exclusive jurisdiction over wholesale power transactions and thus the matter is preempted under the Federal Power Act (FPA) and barred by the filed-rate doctrine. 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. Briefing on the appeal was completed in August 2003, but the court has yet to set a date for oral argument. 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 positions, 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. The AG's opening appeal brief was filed on August 13, 2003. IPC's brief was filed on October 14, 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 emerged 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 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. The appeal is not yet fully briefed and the court has yet to set oral argument. As a result of the various motions, no trial date is set. 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.

Class Action Complaint Relating to Trades on the New York Mercantile Exchange: On August 18, 2003, Cornerstone Propane Partners, L.P. (Cornerstone), on behalf of itself and others who allegedly purchased and sold natural gas futures and options contracts on the New York Mercantile Exchange from January 1, 2000 to December 31, 2002, filed a class action complaint in the United States District Court for the Southern District of New York against over 30 defendants, including IDACORP and IPC. The complaint claims that the defendants reported inaccurate trading information to various trade publications that compile and publish indices of natural gas prices and that defendants engaged in various improper trades on the Enron Online internet-based trading platform, the alleged purpose of which was to improperly inflate the prices of natural gas. Cornerstone has sought class action certification and damages for alleged violations of the Commodity Exchange Act and for aiding and abetting such violations.

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.

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. All defendants, including IPC and IDACORP, have moved to dismiss the complaint in lieu of answering it. The motions are all based on the ground that the complaint seeks in effect to set alternative electrical rates, which are exclusively within the jurisdiction of the FERC and are barred by the filed-rate doctrine. The motions to dismiss and all other aspects of the case have been stayed by the judge in the Western District of Washington, pending a decision by the Panel on Multiple District Litigation whether to transfer the case to one of several multidistrict actions currently pending in California. A number of defendants have proposed such a transfer while two defendants and the Port of Seattle oppose the transfer. IPC and IDACORP have taken no position with regard to the transfer. 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.

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 United States Bankruptcy Court, Central District of California.

In April 2001, PG&E filed for bankruptcy. The CalPX and the 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 the 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.

On March 20, 2002, the AG filed a complaint with the FERC against various sellers in the wholesale power market, including IE and IPC, alleging that the FERC's market-based rates violate the FPA, and, even if market-based rate requirements are valid, that the quarterly transaction reports filed by sellers do not contain the transaction-specific information mandated by the FPA and the FERC. The complaint stated that refunds for amounts charged between market-based rates and cost-based rates should be ordered. The FERC denied the challenge to market-based rates and refused to order refunds, but did require sellers, including IE and IPC, to refile their quarterly reports to include transaction-specific data. The AG appealed the FERC's decision to the United States Court of Appeals for the Ninth Circuit. The AG contends that the failure of all market-based rate authority sellers of power to have rates on file with the FERC in advance of sales is impermissible. The Ninth Circuit heard oral arguments on October 9, 2003, but has not specified the date on which it will issue a decision. The companies cannot predict the outcome of this matter.

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. The 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 the 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 the 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 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. On October 16, 2003, the FERC issued two orders denying rehearing of most contentions that had been advanced and directing the Cal ISO to prepare its compliance filing calculating revised MMCPs and refund amounts within five months. After that time the FERC will consider cost-based filings from sellers to reduce their refund exposure.

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 the Cal ISO were assigned from IPC to IE. At September 30, 2003, with respect to the CalPX chargeback and the California Refund proceedings discussed above, the CalPX and the 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 September 30, 2003, IDACORP believes that the future collectibility of these receivables or any potential refunds ordered by the FERC would not have a material adverse effect 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 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 the 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 was to respond explaining their trading practices within 45 days of receipt of the Cal ISO data. IPC submitted its responses to the show cause orders on September 2 and 4, 2003. On October 16, 2003, IPC reached agreement with the Staff on the two orders commonly referred to as the "gaming" and "partnership" show cause orders. Regarding the gaming order, the Staff determined it had no basis to proceed with allegations of false imports and paper trading and IPC agreed to pay $83,373 to settle allegations of circular scheduling. IPC believed that it had defenses to the circular scheduling allegation but determined that the cost of settlement was less than the cost of litigation. In the settlement, IPC did not admit any wrongdoing or violation of any law. With respect to the "partnership" order, the Staff agreed to submit a motion to the FERC to dismiss the proceeding because materials submitted by IPC demonstrated that IE did not use the "parking" and "lending" arrangement with Public Service Company of New Mexico to engage in gaming or anomalous market behavior. The "gaming" settlement must be certified by an ALJ and approved by the FERC and the motion to dismiss the "partnership" proceeding must be approved by the FERC before becoming final. Any final order will be subject to appeal by other parties in the proceeding. The California parties are attempting to persuade the FERC to delay these proceedings and consider requests for rehearing, which would expand the scope of the conduct under consideration.

On June 25, 2003, 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 the 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 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 received some information regarding these matters from the Cal ISO and on July 24, 2003, IPC responded to the FERC's data requests. 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 material adverse effect on their consolidated financial positions, 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. 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 proceeding, 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, IPC entered into two transactions under the Western Systems Power Pool (WSPP) Agreement whereby IPC agreed to deliver to Nevada Power Company (NPC) 25 MW during the third quarter of 2002. NPC agreed to pay IPC $250 per MWh for heavy load deliveries and $155 per MWh for light load deliveries. IPC assigned the contracts to IE with NPC's consent and the assignment was subsequently approved by the FERC. Based upon the uncertain financial condition of NPC, and pursuant to the terms of the WSPP Agreement, IE requested NPC to provide assurances of its 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 all WSPP Agreement transactions with NPC 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 against NPC on April 25, 2003, 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 things, that: the Idaho State District Court lacks jurisdiction over NPC; a separate complaint seeking declaratory judgment was filed in the United States District Court, District of Nevada 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 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 WSPP Agreement. NPC's motion to dismiss is scheduled to be heard on December 2, 2003. NPC has never served IE with the complaint for declaratory judgment filed in the United States District Court in Nevada.

On September 23, 2003, NPC filed and served IE, IPC, and IDACORP with a Declaratory Action filed with the Nevada State Court in and for the County of Clark concerning the same subject matter of the pending Idaho State District Court action filed by IE on April 25, 2003. NPC seeks declaratory judgment on the following issues: that the assignment of the February and April 2001 energy supply contracts from IPC to IE is void or voidable; that IE did not comply with the WSPP Agreement when requesting reasonable assurances; and that NPC is relieved of its obligations to pay under the contracts by reason of force majeure. IE filed a motion to dismiss NPC's Nevada State Court claims.

IE intends to vigorously prosecute the action it filed in Idaho State District Court. Furthermore, IPC, IE and IDACORP intend to vigorously defend against NPC's claims filed in the State of Nevada.

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

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 that were not properly filed with the FERC 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 for certain 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 order 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 were initiated. 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. The parties to the proceeding have reached a verbal agreement that an additional $5.5 million will be flowed through the PCA mechanism to the Idaho retail customers from April 2003 through December 2005. This agreement is subject to approval by the IPUC. The settlement should resolve all remaining compensation issues.

IDACORP and IPC do not believe that resolution of these transactions will have a material adverse effect on their consolidated financial positions, results of operations or cash flows.

Federal Energy Regulatory Commission
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 concluded their reviews.

Deferred Power Supply Costs
Idaho: IPC has a PCA mechanism that provides for annual adjustments to the rates charged to its Idaho retail customers. These adjustments, which historically have taken 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.

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 was the maximum annual rate of recovery allowed under Oregon state law at that time. These increases are recovering approximately $2 million annually. The Oregon deferred balance was $14 million as of September 30, 2003. During the 2003 Oregon legislative session, the maximum annual rate of recovery was raised to ten percent under certain circumstances. The higher recovery percentage may be requested by IPC in the spring of 2004.

IPC's deferred power supply costs consisted of the following at (in thousands of dollars):

			September 30,		December 31,
			2003		2002

Oregon deferral			$	13,752	$	14,172

Idaho PCA power supply cost deferrals:
	Deferral during the 2003-2004 rate year			35,006		-
	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			26,084		-

	Total deferral		$	74,842	$	140,288

7. DERIVATIVE FINANCIAL INSTRUMENTS:

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

			Three Months Ended				Nine Months Ended
			September 30,				September 30,
			2003		2002		2003		2002
Gross Margin:
	Realized or otherwise settled		$	49,752	$	(13,933)	$	60,278	$	37,371
	Unrealized gains (losses)			(30,826)		20,515		(42,517)		(37,325)
		Total	$	18,926	$	6,582	$	17,761	$	46

The 2003 gross margin reflects the effects of the wind down of IE's activities, including the sale of its forward book of electricity trading contracts in August 2003.

8. INDUSTRY SEGMENT INFORMATION:

IDACORP has identified two reportable 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
September 30, 2003:
		Revenues	$	214,861	$	17,193	$	7,174	$	-	$	239,228
		Net income		15,108		7,350		24,317		-		46,775

Total assets at September
	30, 2003		$	2,666,266	$	162,610	$	271,516	$	(152,225)	$	2,948,167

Three months ended
	September 30, 2002:
		Revenues	$	237,528	$	18,917	$	3,131	$	-	$	259,576
		Net income (loss)		38,436		495		(2,023)		-		36,908

Total assets at December
	31, 2002:		$	2,738,493	$	381,690	$	355,327	$	(226,016)	$	3,249,494

Nine months ended
	September 30, 2003:
		Revenues	$	615,911	$	19,733	$	15,788	$	-	$	651,432
		Net income (loss)		40,588		(7,432)		9,668		-		42,824

Nine months ended
	September 30, 2002:
		Revenues	$	662,209	$	36,848	$	9,944	$	-	$	709,001
		Net income (loss)		72,495		(7,054)		(760)		-		64,681

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 87 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. The Boise office should cease operations by the end of 2003.

In August 2003, IE sold its forward book of electricity trading contracts to Sempra Energy Trading (SET). This transaction was approved by the FERC on September 26, 2003. To date, all but three of IE's counterparties have consented to the assignment of their contracts to SET. For those that have not consented, IE still retains the credit risk. SET entered into transactions with IE that mirror the transactions of those entities that have not consented to the assignment. SET also agreed to service these remaining contracts for IE. The result of this agreement with SET is that IE will have no ongoing cash flow or earnings from these contracts and should be able to close down operations by the end of 2003.

As part of the sale of the forward book of electricity trading contracts, IE entered into an Indemnity Agreement with SET, guaranteeing the performance of one of the counterparties. The maximum amount payable by IE under the Indemnity Agreement is $20 million. The Indemnity Agreement has been accounted for in accordance with FIN 45, "Guarantor's Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others."

In 2002, IE incurred $5 million of involuntary termination benefit expenses and approximately $4 million of lease termination costs and other exit-related costs. As of December 31, 2002, IE paid $2 million of these costs with a remaining outstanding accrual of $7 million. During the three months ended September 30, 2003, $0.4 million of involuntary termination benefits, lease termination costs and other exit-related costs were paid for a total of $3.6 million for the nine months ended September 30, 2003. Also in the third quarter of 2003, $5 million of additional expenses were accrued, primarily termination benefits associated with the sale of the forward book of electricity trading contracts. Termination benefit expenses relate to the termination of 98 employees (primarily energy traders and administrative support positions), 93 of whom had been laid off by September 30, 2003. Of the 93 employees laid off, 19 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):

		Severance		Lease
		and Other		Termination
		Benefits		Costs		Other		Total

Balance at December 31, 2002		$	4,171	$	2,485	$	195	$	6,851
	Amounts paid		(2,912)		(548)		(103)		(3,563)
	Amounts reversed		(124)		-		-		(124)
	Additional amounts accrued		4,379		344		-		4,723
Balance at September 30, 2003		$	5,514	$	2,281	$	92	$	7,887

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 September 30, 2003, and the related consolidated statements of income and of comprehensive income for the three and nine month periods ended September 30, 2003 and 2002 and the consolidated statements of cash flows for the nine month periods ended September 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
November 5, 2003

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Idaho Power Company
Consolidated Statements of Income
(unaudited)

			Three Months Ended
			September 30,
			2003		2002
			(thousands of dollars)
OPERATING REVENUES:
	General business		$	188,247	$	216,452
	Off-system sales			16,442		10,859
	Other revenues			9,536		9,940
		Total operating revenues		214,225		237,251

OPERATING EXPENSES:
	Operation:
		Purchased power		77,280		50,240
		Fuel expense		25,606		26,529
		Power cost adjustment		(9,787)		57,153
		Other		37,746		38,308
	Maintenance			16,081		14,339
	Depreciation			24,439		23,577
	Taxes other than income taxes			5,164		5,069
		Total operating expenses		176,529		215,215

INCOME FROM OPERATIONS				37,696		22,036

OTHER INCOME (EXPENSE):
	Allowance for equity funds used during construction			941		(4)
	Other - net			2,074		410
		Total other income		3,015		406

INTEREST CHARGES:
	Interest on long-term debt			13,385		12,330
	Other interest			1,103		2,318
	Allowance for borrowed funds used during construction			(865)		(432)
		Total interest charges		13,623		14,216

INCOME BEFORE INCOME TAXES				27,088		8,226

INCOME TAX EXPENSE (BENEFIT)				11,133		(31,129)

NET INCOME				15,955		39,355

	Dividends on preferred stock			847		919

EARNINGS ON COMMON STOCK			$	15,108	$	38,436

The accompanying notes are an integral part of these statements.

Idaho Power Company
Consolidated Statements of Income
(unaudited)

			Nine Months Ended
			September 30,
			2003		2002
			(thousands of dollars)
OPERATING REVENUES:
	General business		$	529,922	$	590,136
	Off-system sales			54,889		41,994
	Other revenues			29,670		28,775
		Total operating revenues		614,481		660,905

OPERATING EXPENSES:
	Operation:
		Purchased power		122,904		111,614
		Fuel expense		75,052		76,165
		Power cost adjustment		67,443		133,378
		Other		115,832		111,991
	Maintenance			47,456		42,500
	Depreciation			72,853		69,932
	Taxes other than income taxes			15,572		15,415
		Total operating expenses		517,112		560,995

INCOME FROM OPERATIONS				97,369		99,910

OTHER INCOME:
	Allowance for equity funds used during construction			2,433		40
	Other - net			7,537		11,373
		Total other income		9,970		11,413

INTEREST CHARGES:
	Interest on long-term debt			41,438		37,884
	Other interest			3,690		7,293
	Allowance for borrowed funds used during construction			(2,441)		(1,753)
		Total interest charges		42,687		43,424

INCOME BEFORE INCOME TAXES				64,652		67,899

INCOME TAX EXPENSE (BENEFIT)				21,483		(8,175)

NET INCOME				43,169		76,074

	Dividends on preferred stock			2,581		3,579

EARNINGS ON COMMON STOCK			$	40,588	$	72,495

The accompanying notes are an integral part of these statements.

Idaho Power Company
Consolidated Balance Sheets
(unaudited)

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

ELECTRIC PLANT:
	In service (at original cost)			$	3,164,212	$	3,086,965
	Accumulated provision for depreciation				(1,363,765)		(1,294,961)
		In service - Net			1,800,447		1,792,004
	Construction work in progress				106,930		92,481
	Held for future use				2,705		2,335

			Electric plant - Net		1,910,082		1,886,820

INVESTMENTS AND OTHER PROPERTY					42,406		42,272

CURRENT ASSETS:
	Cash and cash equivalents				5,253		12,699
	Receivables:
		Customer			49,832		56,947
		Allowance for uncollectible accounts			(1,312)		(1,566)
		Notes			4,908		4,992
		Employee notes			8,113		7,646
		Related parties			24,565		27,905
		Other			1,273		2,702
	Accrued unbilled revenues				28,456		35,714
	Materials and supplies (at average cost)				20,626		21,458
	Fuel stock (at average cost)				4,387		6,943
	Prepayments				28,488		32,818
	Regulatory assets				7,017		17,147

			Total current assets		181,606		225,405


DEFERRED DEBITS:
	American Falls and Milner water rights				31,585		31,585
	Company-owned life insurance				35,748		35,299
	Regulatory assets				424,961		482,159
	Other				39,878		34,953

			Total deferred debits		532,172		583,996


	TOTAL			$	2,666,266	$	2,738,493

The accompanying notes are an integral part of these statements.

Idaho Power Company
Consolidated Balance Sheets
(unaudited)

				September 30,		December 31,
				2003		2002
CAPITALIZATION AND LIABILITIES				(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			362,058		361,948
		Capital stock expense			(2,689)		(2,710)
		Retained earnings			317,628		330,300
		Accumulated other comprehensive income (loss)			(4,734)		(7,109)

			Total common stock equity		766,294		776,460

	Preferred stock				52,484		53,393

	Long-term debt				880,836		870,741

			Total capitalization		1,699,614		1,700,594

CURRENT LIABILITIES:
	Long-term debt due within one year				50,077		80,084
	Notes payable				14,000		10,500
	Accounts payable				38,382		52,728
	Taxes accrued				97,563		89,090
	Interest accrued				21,571		12,399
	Deferred income taxes				6,785		17,056
	Other				16,756		22,906

			Total current liabilities		245,134		284,763

DEFERRED CREDITS:
	Deferred income taxes				530,018		574,233
	Regulatory liabilities				114,126		114,247
	Other				77,374		64,656

			Total deferred credits		721,518		753,136


COMMITMENTS AND CONTINGENT LIABILITIES

			TOTAL	$	2,666,266	$	2,738,493

The accompanying notes are an integral part of these statements.

Idaho Power Company
Consolidated Statements of Capitalization
(unaudited)

				September 30,				December 31,
				2003		%		2002		%
				(thousands of dollars)
COMMON STOCK EQUITY:
	Common stock			$	94,031			$	94,031
	Premium on capital stock				362,058				361,948
	Capital stock expense				(2,689)				(2,710)
	Retained earnings				317,628				330,300
	Accumulated other comprehensive income (loss)				(4,734)				(7,109)
		Total common stock equity			766,294		45		776,460		46

PREFERRED STOCK:
	4% preferred stock				12,484				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			52,484		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				1,125				1,185
		Amount due within one year			(77)				(84)
			Net REA notes		1,048				1,101

	American Falls bond guarantee				19,885				19,885

	Milner Dam note guarantee				11,700				11,700

	Unamortized premium/discount - net				(2,257)				(2,405)

			Total long-term debt		880,836		52		870,741		51

TOTAL CAPITALIZATION				$	1,699,614		100	$	1,700,594		100

The accompanying notes are an integral part of these statements.

Idaho Power Company
Consolidated Statements of Cash Flows
(unaudited)

				Nine Months Ended
				September 30,
				2003		2002
				(thousands of dollars)
OPERATING ACTIVITIES:
	Net income			$	43,169	$	76,074
	Adjustments to reconcile net income to net cash provided by
		operating activities:
		Allowance for uncollectible accounts			(254)		17
		Depreciation and amortization			82,369		79,560
		Deferred taxes and investment tax credits			(52,773)		(64,131)
		Accrued PCA costs			65,446		128,215
		Change in:
			Accounts receivable and prepayments		16,181		(12,138)
			Accrued unbilled revenue		7,258		8,658
			Materials and supplies and fuel stock		3,389		(1,483)
			Accounts payable		(14,367)		(37,560)
			Taxes receivable/accrued		8,473		50,127
			Other current assets and liabilities		2,974		12,673
		Other - net			4,094		5,973
			Net cash provided by operating activities		165,959		245,985

INVESTING ACTIVITIES:
	Additions to utility plant				(96,956)		(81,157)
	Note receivable payment from (advance to) parent				(415)		15,315
	Other - net				247		(796)
		Net cash used in investing activities			(97,124)		(66,638)

FINANCING ACTIVITIES:
	Issuance of first mortgage bonds				140,000		-
	Retirement of first mortgage bonds				(160,000)		(50,000)
	Retirement of preferred stock				(909)		(50,402)
	Dividends on common stock				(53,260)		(52,545)
	Dividends on preferred stock				(2,581)		(3,579)
	Change in short-term borrowings				3,500		(48,517)
	Other - net				(3,031)		(2,138)
		Net cash used in financing activities			(76,281)		(207,181)

Net decrease in cash and cash equivalents					(7,446)		(27,834)

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

Cash and cash equivalents end of period				$	5,253	$	15,206

SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION:
	Cash paid during the period for:
		Income taxes		$	71,325	$	11,512
		Interest (net of amount capitalized)		$	31,723	$	35,017

The accompanying notes are an integral part of these statements.

Idaho Power Company
Consolidated Statements of Comprehensive Income
(unaudited)

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

NET INCOME				$	15,955	$	39,355

OTHER COMPREHENSIVE INCOME (LOSS):
	Unrealized gains (losses) on securities:
		Unrealized holding gains (losses) arising during the period,
			net of tax of $296 and ($1,212)		521		(1,865)
		Reclassification adjustment for (gains) losses included
			in net income, net of tax of ($111) and $553		(172)		851
			Net unrealized gains (losses)		349		(1,014)

TOTAL COMPREHENSIVE INCOME				$	16,304	$	38,341

				Nine Months Ended
				September 30,
				2003		2002
				(thousands of dollars)

NET INCOME				$	43,169	$	76,074

OTHER COMPREHENSIVE INCOME (LOSS):
	Unrealized gains (losses) on securities:
		Unrealized holding gains (losses) arising during the period,
			net of tax of $1,291 and ($1,968)		2,189		(3,088)
		Reclassification adjustment for losses included in net income,
			net of tax of $120 and $538		186		827
			Net unrealized gains (losses)		2,375		(2,261)

TOTAL COMPREHENSIVE INCOME				$	45,544	$	73,813

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				Nine months ended
			September 30,				September 30,
			2003		2002		2003		2002

Net income, as reported			$	15,955	$	39,355	$	43,169	$	76,074
Add: Stock-based employee compensation expense included
	in reported net income, net of related tax effects			50		16		104		13
Deduct: Total stock-based employee compensation expense
	determined under fair value based method for all awards,
	net of related tax effects			302		438		651		1,311
		Pro forma net income	$	15,703	$	38,933	$	42,622	$	74,776

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 nine months ended September 30, 2003 was 33.2 percent, compared with an effective tax rate of negative 12.0 percent for the nine months ended September 30, 2002. The increase in the 2003 estimated tax rate, compared with 2002, is due primarily to the adoption of a tax accounting method change during the third quarter of 2002 that provided a decrease to income tax expense of $31 million. Had this benefit been excluded, the tax rate for the nine months ended September 30, 2002 would have been 33.6 percent.

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 represented 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 balance of this note at September 30, 2003 was approximately $20 million, including accrued interest. On October 3, 2003, IDACORP repaid this note in its entirety.

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

	Three Months Ended				Nine Months Ended
	September 30,				September 30,
	2003		2002		2003		2002

Sales to IE	$	71	$	2,208	$	2,268	$	21,891
Purchases from IE		-		4,002		-		13,282

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 September 30, 2003, and the related consolidated statements of income and of comprehensive income for the three and nine month periods ended September 30, 2003 and 2002 and the consolidated statements of cash flows for the nine month periods ended September 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
November 5, 2003

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

(Dollar amounts are in thousands unless otherwise indicated. Megawatt hours (MWh) are 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 (collectively, IDACORP) and Idaho Power Company and its subsidiary (collectively, 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 operating subsidiaries include:

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 the companies' 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, relicensing of hydroelectric projects, recovery of purchased power, recovery of 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;

changes in operating expenses and capital expenditures;

capital market conditions;

rating actions by Moody's, Standard & Poor's (S&P) 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;

increasing health care costs and the resulting effect on health insurance premiums paid for employees and on the obligation to provide postretirement health care benefits;

increasing costs of insurance, changes in coverage terms and the ability to obtain insurance;

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 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. The recovery is less than the full amount of the increased costs.

Changes in temperature can reduce power sales and affect operating results. IPC experienced warmer than usual temperatures in its service territory in the first quarter of 2003, which reduced sales. Temperatures in the second and third quarters of 2003 have been warmer than normal resulting in increased sales. Warmer than normal winters or cooler than normal summers will reduce retail 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 2004. 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. Conditions with respect to environmental, operating and other matters that may be imposed by the FERC in connection with the renewal of these licenses could have a negative effect 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 could be negatively affected. IPC filed a general rate case with the IPUC on October 16, 2003. The rate case was 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. If the requested rate relief is not granted, IPC's earnings and cash flow could be negatively affected.

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 that were not properly filed with the FERC 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 for certain transactions between the affiliates. The parties to the proceeding have reached a verbal agreement that an additional $5.5 million will be flowed through the PCA mechanism to the Idaho retail customers from April 2003 through December 2005. This agreement is subject to approval by the IPUC. The settlement should resolve all remaining compensation issues. It is possible that other proceedings may be commenced against IPC or IE in connection with energy marketing.

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. 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 at the FERC that consider whether certain trading practices constituted gaming or acting in concert in furtherance of a gaming strategy. It is possible that additional proceedings related to the California energy crisis may be filed in the future against IDACORP, IE or IPC.

Increased capital expenditures can significantly affect liquidity. Increases in both the number of customers and the 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.

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 THIRD QUARTER 2003 AND FUTURE OUTLOOK:

Overall Results
IDACORP's earnings per share (EPS) was $1.22 in the third quarter of 2003, an increase of $0.24 per share compared to the third quarter of 2002. The increase is due principally to recognition of income tax benefits related to low-income housing tax credits, profit on the sale of the forward book of electricity trading contracts at IE and a contract settled at IdaTech, offset by decreased earnings at IPC.

Accounting principles generally accepted in the United States of America (GAAP) require companies to apply the estimated annual effective tax rate in computing the provision for income taxes for interim reporting periods. For 2003, IDACORP has projected annual pre-tax book 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 credits. Because IDACORP had pre-tax losses in the first two quarters of 2003, it did not apply the negative estimated annual effective tax rate to these pre-tax loss periods. IDACORP recognized tax benefits in the third quarter based on its forecasted annual pre-tax income.

IPC's EPS contribution in the third quarter was $0.40, a $0.62 per share decrease compared to the third quarter of 2002. In 2002, IPC changed its tax accounting method for capitalized overhead costs, and settled other tax matters, which created a tax benefit of $0.96 per share. Also in 2002, $12 million ($0.19 per share) of deferred amounts that were not approved for recovery in the PCA filing was expensed. Both years' results reflect the continued impact of below normal water conditions.

IE reported EPS of $0.19 for the third quarter of 2003, a $0.17 per share improvement from the third quarter of 2002. IE's 2003 results include earnings from the August sale of its forward book of electricity trading contracts of $0.26 per share. This sale was the last major step in the wind down of energy marketing that began in 2002.

Below Normal Water Conditions
The Snake River Basin above Brownlee Dam experienced below average precipitation for the recently completed 2003 water year (October 1, 2002 - September 30, 2003) making this the fourth consecutive year of below normal water conditions for the Snake River. The Northwest River Forecast Center (NWRFC) records indicate inflow to Brownlee Reservoir during the April-July period was 56 percent of normal and 59 percent of normal for the entire water year. These statistics are based on NWRFC records from 1971 through 2000.

Across the Snake River Basin, reservoir storage is low. Reservoir storage in the Upper Snake River system above Milner Dam is the second lowest on record. Below normal reservoir storage, combined with dry soil conditions in the Snake River Basin above Brownlee Dam, mean that higher than normal winter precipitation is necessary for flow in the Snake River to return to normal in the year ahead.

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.

In February 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. As a result of this process, IPC selected Mountain View Power as the successful bidder for the construction of the Bennett Mountain Power Plant (BMPP), a 160-MW gas-fired generating plant near Mountain Home, Idaho.

General Rate Case
IPC filed an application with the IPUC on October 16, 2003 to increase its general rates an average of 17.7 percent. If approved, IPC's revenues would increase $86 million annually based on the proposed 11.2 percent return on equity. An additional component of the filing was a request for interim rate relief of $20 million. The interim rate request represents a portion of the general rate request. If approved, IPC could begin to collect a 4.2 percent uniform interim rate increase within 30 days of the filing. Oral arguments from intervening parties on the interim increase are scheduled to be heard on November 13, 2003. The success of this rate case is dependent on the IPUC review and approval, which could take up to seven months from the filing date, and IPC is unable to predict what rate relief, if any, the IPUC will grant.

Relicensing of Hydroelectric Projects
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 multi-year 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 and IPC are 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 United States 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. On October 16, 2003, IPC reached agreement with the FERC Staff (Staff) on the show cause orders. The "gaming" settlement must be certified by an Administrative Law Judge (ALJ) and approved by the FERC and the motion to dismiss the "partnership" proceeding must be approved by the FERC before becoming final. 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 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 while stating that IPC violated Section 203 of the FPA. On May 16, 2003, the FERC issued an 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 that were not properly filed with the FERC 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 for certain transactions between the affiliates. The parties to the proceeding have reached a verbal agreement that an additional $5.5 million will be flowed through the PCA mechanism to the Idaho retail customers from April 2003 through December 2005. This agreement is subject to approval by the IPUC. The settlement should resolve all remaining compensation issues.

Liquidity
IDACORP's and IPC's operating cash flows were $257 million and $166 million, respectively, for the nine months ended September 30, 2003. IDACORP's cash flows include cash received by IE on contracts realized or otherwise settled, including the sale of its forward book of electricity trading contracts. IPC's operating cash flows 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 $247 million, which is an increase from the June 30, 2003 estimate of $218 million, but is still below the original forecast. IPC is forecasting that net cash provided by operating activities will be approximately $185 million for the year ending 2003 compared to its June 30, 2003 estimate of $176 million. IPC's current estimate is also below its original forecast.

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.

At September 30, 2003, IDACORP had approximately $11 million in commercial paper outstanding against its $315 million available bank credit facility. IPC had approximately $14 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 September 30, 2003, IDACORP's and IPC's leverage ratios were 53 percent and 54 percent, respectively. IDACORP is also required to maintain an interest coverage ratio of at least 2.75 to 1. At September 30, 2003, IDACORP's interest coverage ratio was in compliance with this requirement.

Capital Expenditures: Capital expenditures at IPC are expected to come slightly under the budgeted levels of $150 million for the year. The combined 2004 through 2006 capital needs of the utility are expected to be approximately $675 million. Variation in the estimate is dependent on the ongoing analysis of the timing of spending for relicensing, load growth and other resource acquisition needs. The construction of the BMPP is included in these estimates.

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 through 2006 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: In September 2003, the Board of Directors of IDACORP reduced the annual dividend on common stock from $1.86 per share to $1.20 per share. The change took effect with the dividend for the quarter ended October 31, 2003, which the board declared at $0.30 per share. The dividend will be paid December 1, 2003 to common shareholders of record on November 5, 2003. This action was taken to strengthen IDACORP's financial position and its ability to fund IPC's $675 million three-year capital expenditure program.

Financing Activities
During July 2003, IFS issued $40 million in debt. Proceeds were used by IFS to pay intercompany notes to IDACORP, which then used the proceeds to reduce short-term borrowings.

On October 22, 2003, Humboldt County, Nevada issued, for the benefit of IPC, $49.8 million Pollution Control Revenue Refunding Bonds (Idaho Power Company Project) Series 2003 due December 1, 2024. The bonds were issued in an auction rate mode under which the interest rate is reset every 35 days. The initial auction rate was set at 0.95 percent.

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 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, contingencies, litigation, income taxes, restructuring costs, asset impairments, 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 for the three and nine months ended September 30, 2003 and 2002 are compared, beginning with a general overview. A more detailed discussion of the electric utility and energy marketing segments then follows.

			Three Months Ended				Nine Months Ended
			September 30,				September 30,
			2003		2002		2003		2002
Earnings (loss) per share of common stock
	Electric utility (IPC)		$	0.40	$	1.02	$	1.06	$	1.93
	Energy marketing (IE)			0.19		0.02		(0.19)		(0.19)
	Other			0.63		(0.06)		0.25		(0.02)
		Total	$	1.22	$	0.98	$	1.12	$	1.72

IPC's 2002 third quarter and year-to-date results include a $0.96 per share benefit from a change in the tax accounting method used for capitalized overhead costs, and for the settlement of other tax matters. Also in the third quarter of 2002, $12 million ($0.19 per share) of deferred amounts that were not approved for recovery in the PCA filing was expensed. Both years' results reflect the continued impact of below normal water conditions.

IE's results include earnings from the sale of its forward book of electricity trading contracts in August 2003 of $0.26 per share, and the continued wind down of energy marketing activities. 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 the estimated annual effective tax rate in computing the provision for income taxes for interim reporting periods. For 2003, IDACORP has projected annual pre-tax book 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 credits. Because IDACORP had pre-tax losses in the first two quarters of 2003, it did not apply the negative estimated annual effective tax rate to these pre-tax loss periods. IDACORP recognized the tax benefit in the third quarter based on its forecasted annual pre-tax income. The effect of this adjustment is included in the table above in "Other."

Excluding the tax adjustment discussed above, combined EPS from IDACORP's other subsidiaries increased for both the three and nine months ended September 30, 2003, principally due to improvement at IdaTech, which in August 2003 recorded a $4 million gain from the settlement of a contract regarding the design, production and delivery of fuel cell systems.

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 nine months ended September 30:

		Three Months Ended September 30,						Nine Months Ended September 30,
		Revenue				MWh		Revenue				MWh
		2003		2002		2003	2002	2003		2002		2003	2002

Residential		$	63,903	$	68,098	1,113	966	$	208,142	$	223,200	3,250	3,209
Commercial			43,099		50,030	968	878		133,958		146,479	2,632	2,592
Industrial			28,841		45,888	849	848		100,761		132,537	2,377	2,412
Irrigation			52,404		52,436	1,044	1,047		87,061		87,920	1,720	1,717
	Total	$	188,247	$	216,452	3,974	3,739	$	529,922	$	590,136	9,979	9,930

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 reduced revenues approximately $35 million and $45 million, respectively, for the three and nine months ended September 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 $4 million and $14 million increases in revenues for the three and nine months ended September 30, 2003, respectively.

Weather and other usage factors increased revenues $11 million and decreased revenues $9 million for the three and nine months ended September 30, 2003, respectively. The three-month increase is the result of warmer summer temperatures. Cooling degree-days in the quarter were 33 percent greater than in 2002. The nine-month decrease is attributed to warmer weather in the first quarter of 2003, as measured by a 19 percent decrease in heating degree-days. Heating degree-days and cooling degree-days are common measures used in the utility industry to analyze the demand for electricity, and indicate when a customer would use electricity for heating or air-conditioning.

The remaining change represents 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 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 nine months ended September 30:

	Three Months Ended				Nine Months Ended
	September 30,				September 30,
	2003		2002		2003		2002

Off-system sales	$	16,442	$	10,859	$	54,889	$	41,994
MWh sold		411		388		1,393		1,641
Revenue per MWh	$	40.02	$	28.02	$	39.41	$	25.60

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

		Three Months Ended				Nine Months Ended
		September 30,				September 30,
		2003		2002		2003		2002
Purchased Power:
	Purchases	$	77,280	$	34,771	$	119,775	$	71,283
	Load reduction costs	$	-	$	15,469	$	3,129	$	40,331

MWh purchased			1,716		1,132		2,730		2,435
Cost per MWh purchased		$	45.03	$	30.72	$	43.87	$	29.27

The increases in purchased power volumes were necessitated by unscheduled outages at IPC's thermal plants in 2003, including an eleven-week outage at one of the generating units at the Valmy thermal plant, which required power to be purchased on the open market. 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 nine months ended September 30:

	Three Months Ended				Nine Months Ended
	September 30,				September 30,
	2003		2002		2003		2002

Fuel expense	$	25,606	$	26,529	$	75,052	$	76,165
Thermal MWh generated		1,635		1,900		4,946		5,312
Cost per MWh	$	15.66	$	13.96	$	15.17	$	14.34

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 nine months ended September 30:

		Three Months Ended				Nine Months Ended
		September 30,				September 30,
		2003		2002		2003		2002

Power supply costs accrual (deferral)		$	(31,581)	$	(3,273)	$	(34,744)	$	1,296
FMC/Astaris program costs deferral			-		(12,334)		(2,245)		(31,353)
Amortization of prior year authorized balances			21,794		60,640		104,384		149,855
Write-off of disallowed costs			-		12,120		48		13,580
	Total power cost adjustment	$	(9,787)	$	57,153	$	67,443	$	133,378

Other Operations and Maintenance Expenses: Other operations and maintenance expenses have increased $9 million for the nine months ended September 30, 2003. This increase is primarily due to pension expense, which increased $5 million and thermal plant expenses, which increased $3 million. 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 primarily to transmission of purchased power into IPC's service territory.

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 87 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. The Boise office should cease operations by the end of 2003.

In 2002, IE incurred $5 million of involuntary termination benefit expenses and approximately $4 million of lease termination costs and other exit-related costs. As of December 31, 2002, IE paid $2 million of these costs with a remaining outstanding accrual of $7 million. During the three months ended September 30, 2003, $0.4 million of involuntary termination benefits, lease termination costs and other exit related costs were paid, for a total of $3.6 million for the nine months ended September 30, 2003. Also in the third quarter of 2003, $5 million of additional expenses were accrued, primarily termination benefits associated with the sale of the forward book of electricity trading contracts. Termination benefit expenses relate to the termination of 98 employees (primarily energy traders and administrative support positions), 93 of whom had been laid off by September 30, 2003. Of the 93 employees laid off, 19 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 and the parties to the IPUC proceeding have reached a verbal agreement, which is subject to approval by the IPUC. These matters are discussed in more detail in Note 6 to the Consolidated Financial Statements.

For the three months ended September 30, 2003 and 2002, IE reported operating income of $11 million and $1 million, respectively. IE recognized earnings of approximately $10 million or $0.26 per share in the third quarter of 2003 from the sale of its forward book of electricity trading contracts. This income was reduced for the quarter by ongoing legal and other administrative expenses associated with the wind down of operations, including $5 million of additional restructuring costs.

Operating losses were $14 million for both the nine-month periods ending September 30, 2003 and 2002. An $18 million increase in gross margins in 2003, due primarily to the sale of the forward book of electricity trading contracts, was offset by a $13 million increase in net losses related to the settlement of legal disputes, and $5 million of restructuring costs recorded in 2003.

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 nine months ended September 30:

			Three Months Ended				Nine Months Ended
			September 30,				September 30,
			2003		2002		2003		2002

Net operating revenues:
	Electricity		$	16,650	$	19,903	$	19,084	$	32,573
	Gas			543		(986)		649		4,275
		Total operating revenues	$	17,193	$	18,917	$	19,733	$	36,848

Operating volumes (settled):
	Electricity (MWh)			2,895,808		7,807,395		11,052,039		34,327,433
	Gas (MMbtu)			-		7,941,126		2,255,881		31,821,727

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.

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 nine months ended September 30:

			Three Months Ended				Nine Months Ended
			September 30,				September 30,
			2003		2002		2003		2002
Gross Margin:
	Realized or otherwise settled		$	49,752	$	(13,933)	$	60,278	$	37,371
	Unrealized gains (losses)			(30,826)		20,515		(42,517)		(37,325)
		Total	$	18,926	$	6,582	$	17,761	$	46

The change in net fair value (energy marketing assets less energy marketing liabilities) between year-end 2002 and September 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			(60,278)
Changes in net fair value attributable to market prices and other market changes			18,999
	Net fair value of contracts outstanding as of 9/30/2003	$	(3,086)

The net fair value of contracts outstanding as of September 30, 2003 of $(3.1) million reflects $(3) million of refundable margin deposits from counterparties. These margin deposits are for contracts that have been assigned to SET, but as of September 30, 2003, the margin deposits had not yet been returned to the counterparties. These margin deposits have subsequently been returned to the respective counterparties and IE no longer holds any margin deposits for any counterparties, nor does IE have any margin on deposit with any counterparty. The additional $(0.1) million of net fair value reflects a credit reserve associated with the three counterparties that as of September 30, 2003, had not consented to the assignment of transactions from IE to SET.

For those that have not consented, IE still retains the credit risk. SET has entered into transactions with IE that mirror the transactions with those entities. SET also agreed to service these remaining contracts for IE. The result of this agreement with SET is that IE will have no ongoing cash flow or earnings from these contracts and should be able to close down operations by the end of 2003.

LIQUIDITY AND CAPITAL RESOURCES:

Operating Cash Flows
IDACORP's operating cash flows for the nine months ended September 30, 2003 were $257 million, compared to $243 million for the same period in 2002. The change is attributable to increased net inflows at IE of $68 million, principally due to the receipt of $40 million from the sale of the forward book of electricity trading contracts, and also to other contracts being realized or otherwise settled. That increase was offset by decreased cash inflows at IPC, related primarily to the timing of income tax payments and refunds and to decreased PCA rates.

IPC's operating cash flows for the nine months ended September 30, 2003 decreased to $166 million, compared to $246 million for the same period in 2002, related primarily to the timing of income tax payments and refunds and to decreased PCA rates.

For the 2003 calendar year, net cash provided by operating activities at IDACORP is forecasted to be $247 million, which is up from the June 30, 2003 estimate of $218 million, but is still below the original forecast. IPC is forecasting that net cash provided by operating activities will be approximately $185 million for the year ending 2003 compared to its June 30, 2003 estimate of $176 million. IPC's current estimate is also below its original forecast. The increase in forecasted operating cash flows from the June 30, 2003 estimate at IDACORP is attributable to increased IPC revenues resulting from warmer than expected summer weather conditions, income tax refunds, the sale of IE's forward book of electricity trading contracts, and the timing of payments of certain working capital amounts.

Working Capital
Proceeds from long-term notes issued by IFS totaling $65 million were 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, the wind down of energy marketing and settled legal disputes with Truckee-Donner Public Utility District, Enron Power Marketing, Inc. and Enron North America Corp.

The increase in taxes accrued reflects amounts payable due to the sale of the forward book of electricity trading contracts and increased current taxable income.

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 September 30, 2003 is a reflection of the wind down and the sale of IE's book of electricity trading contracts.

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		$	19	$	50,077	$	60,079	$	82	$	81,228	$	739,428
Other long-term debt			6,634		18,601		17,682		16,148		13,723		18,438
IPC fuel supply			8,598		30,970		27,466		27,300		9,266		22,856
IPC power purchase
	agreement		-		3,613		4,610		4,610		4,610		9,159

Credit Ratings
On October 3, 2003, S&P changed its rating outlook for IDACORP and IPC to stable from positive. S&P stated that the stable rating outlook reflected the belief that overall financial ratios will only meet expectations for an A- rating over the next two to three years. S&P also changed the IDACORP business profile to a 4 from a 5 on a 10-point scale, where 1 is the least risky. IPC's business profile remains a 4.

Access to capital markets at a reasonable cost is determined in large part by credit quality. The following outlines the current S&P, Moody's and Fitch ratings of IDACORP's and IPC's securities:

Standard and Poor's

Moody's

Fitch

IPC

IDACORP

IPC

IDACORP

IPC

IDACORP

Corporate Credit Rating

A-

Baa 1

None

Senior Secured Debt

None

Senior Unsecured Debt

BBB+

Baa 1

A-

BBB+

Preferred Stock

BBB

Baa 2

None

BBB+

None

Trust Preferred Stock

None

BBB

None

Baa 2

None

BBB

Commercial Paper

A-2

P-1

P-2

F-1

F-2

Rating Outlook

Stable

Negative

Stable

These security ratings reflect the views of the rating agencies. An explanation of the significance of these ratings may be obtained from each rating agency. Such ratings are not a recommendation to buy, sell or hold securities. Any rating can be revised upward or downward or withdrawn at any time by a rating agency if it decides that the circumstances warrant the change. Each rating should be evaluated independently of any other rating.

Pension Expense and Contributions
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.

Based on the 2003 actuarial valuation, pension expense for the qualified plan is expected to increase from approximately $0 in 2002 to approximately $7 million during 2003. For the nine months ended September 30, 2003, pension expense of approximately $5 million was recorded. Of these amounts, approximately 70-75 percent impact IPC's operations and maintenance expenses. Based on market conditions at October 31, 2003, pension expense is expected to be approximately $7 million in 2004. Cash contributions during 2003 and 2004 are not expected.

Insurance Expenses
IPC's medical expenses for current and retired employees are expected to increase approximately $3 million from 2002 to 2003. This increase reflects the overall trends in health care costs and resulting health insurance premiums. In addition, IPC's property and liability insurance expense is expected to increase approximately $2 million from 2002 to 2003, reflecting higher premiums to insure power plants and other utility property. IPC forecasts that its 2004 insurance costs will continue to increase, but more moderately than in 2003.

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 $93 million for the nine months ended September 30, 2003 compared to $76 million for the same period in 2002. IPC expects 2003 construction expenditures to be less than the 2003 budget of $150 million and the 2004 through 2006 construction expenditures to total approximately $675 million. The combined 2004 through 2006 construction expenditures are expected to be allocated to thermal generation (20 percent), hydro generation (10 percent), relicensing and mitigation (10 percent), transmission (20 percent), distribution (30 percent) and general plant (10 percent). With respect to thermal generation, IPC's coal-fired plants are approaching their fourth decade of service and plant utilization has increased due to load growth and reduced hydro generation because of below normal water conditions, all resulting in increased upgrade and replacement requirements and plant additions such as the BMPP, which is currently estimated to cost $61 million. IPC's aging hydro facilities require continuing upgrade and replacement needs in addition to costs related to relicensing the majority of its hydroelectric facilities including the HCC which comprises 40 percent of IPC's total generating capacity. Regarding transmission and distribution facilities, continuing load growth requires that IPC upgrade its system to maintain reliability. Variations in these estimates are dependent on the ongoing analysis of the timing of spending for relicensing, load growth and other resource acquisition needs.

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. As a result of this process, IPC selected Mountain View Power as the successful bidder for the construction of the BMPP, a 160-MW gas-fired generating plant near Mountain Home, Idaho. Mountain View Power has contracted with Siemens Westinghouse Power Corporation to furnish all of the labor, equipment and materials and to perform all of the engineering and construction of the plant. The project cost - including plant construction and associated transmission system upgrades - - is $61 million. IPC will take ownership of the plant once it is fully tested and operational. Resource acquisitions in connection with the construction of this project have been included in the 2004 through 2006 estimate of $675 million.

IPC filed an application with the IPUC on September 26, 2003 for a Certificate of Public Convenience and Necessity for the BMPP. On October 30, 2003, the IPUC issued Order No. 29370 placing the case on Modified Procedure. The IPUC determined that public interest is not served by public hearing and that any person wanting to state a position may file written comments with the IPUC no later than December 15, 2003.

The construction of the BMPP will be funded through IPC's normal financing of construction expenditures, which may include funds generated from operations, 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 due to changing economic, regulatory, environmental and conservation factors.

Other Capital Requirements: Capital requirements at IDACORP's other subsidiaries were $5 million for the nine months ended September 30, 2003 compared to $54 million for the same period in 2002. The decline in 2003 capital investment was attributable to a decision to reduce new investments in low-income housing projects in 2003.

IDACORP forecasts indicate that internal cash generation after dividends is expected to provide approximately 120 percent of total capital requirements in 2003. IDACORP forecasts indicate that internal cash generation after dividends is expected to provide less than 100 percent of total capital requirements for 2004 through 2006. 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 increased from the 97 percent reported in the Annual Report on Form 10-K for the year ended December 31, 2002 due to lower than expected IPC construction expenditures and the reduction of IDACORP's 2003 fourth quarter dividend.

Dividends
In September 2003, the Board of Directors of IDACORP reduced the annual dividend on common stock from $1.86 per share to $1.20 per share. The change took effect with the dividend for the quarter ended October 31, 2003, which the board declared at $0.30 per share. The dividend will be paid December 1, 2003 to common shareholders of record on November 5, 2003. This action was taken to strengthen IDACORP's financial position and its ability to fund IPC's $675 million three-year capital expenditure program.

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. IDACORP's Board of Directors will continue to evaluate these and other factors in determining the appropriate and sustainable level of payout to IDACORP's shareholders going forward.

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 $53 million for both the nine months ended September 30, 2003 and 2002.

Financing Programs
Credit facilities: IDACORP has a $175 million credit facility that expires on March 17, 2004, and a $140 million credit facility that expires on March 26, 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 credit facility that expires on March 17, 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 September 30, 2003, IPC had regulatory authority to incur up to $250 million of short-term indebtedness.

Short-term financings: At September 30, 2003, IDACORP's short-term borrowings totaled $11 million, compared to $166 million at December 31, 2002. At September 30, 2003, IPC's short-term borrowings totaled $14 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 September 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 using open market shares for the Dividend Reinvestment Plan and the Employee Savings 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.

The following tax credit notes were 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, IFS borrowed $25 million from a corporate lender on July 25, 2003 at an interest rate of 3.65 percent. This debt matures from 2003-2008.

Proceeds from the issuance of these debt instruments were primarily used by IFS to pay intercompany notes to IDACORP, which then used these proceeds to reduce 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.

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 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. On October 16, 2003, the FERC issued two orders denying rehearing of most contentions that had been advanced and directing the Cal ISO to prepare its compliance filing calculating revised Mitigated Market Clearing Prices (MMCPs) and refund amounts within five months. After that time the FERC will consider cost-based filings from sellers to reduce their refund exposure.

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 June 25, 2003, 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 the 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 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 received some information regarding these matters from the Cal ISO and on July 24, 2003, IPC responded to the FERC's data requests. 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 material adverse effect on their consolidated financial positions, 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.

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. The conclusions reached by the FERC Staff regarding the responses to the FERC's data requests were embodied in a "Final Staff Report on Price Manipulation in Western Markets" issued in March 2003, which was incorporated in the FERC show cause orders discussed above in Market Manipulation in connection with the company's settlement of the gaming practices and partnership orders.

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.

Other Legal Issues
Idaho Power Company Transmission Line Rights-of-Way Across Fort Hall Indian Reservation: IPC has multiple transmission lines that cross the Shoshone-Bannock Tribes' Fort Hall Indian Reservation near the city of Pocatello in southeastern Idaho. IPC has been working since 1996 to renew five of the right-of-way permits for the transmission lines, which have stated permit expiration dates between 1996 and 2003. IPC has filed applications with the United States Department of the Interior, Bureau of Indian Affairs, to renew the five rights-of-way for 25 years, including payment of the independently appraised value of the rights-of-way to the Tribes (and the Tribal allottees who own portions of the rights-of-way). The Tribes have not agreed to renew the rights-of-way and have demanded a substantially greater payment of $19 million, including an up-front payment of $4 million with the remainder to be paid over the 25 year term of the permits, or in the alternative $11 million including an up-front payment of $4 million with the remainder paid over the first three years of the permit. This is based on an "opportunity cost" methodology, which calculates the value of the rights-of-way as a percentage of the cost to IPC of relocating the transmission lines off the Reservation. Both parties have discussed potential legal action regarding renewal of the rights-of-way, but no such action has been taken to date.

Environmental Issues
Threatened and Endangered Snails: In December 1992, the United States 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. Due to 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. On October 17, 2003, IPC provided the FERC and the USFWS with revised annual reports for 1995-2000. The 2001 revised report is in the process of being finalized and will be sent to the FERC and USFWS upon completion.

By letters dated August 5, 2003, IPC and the USFWS advised the FERC that they initiated efforts to reach a cooperative resolution of outstanding fish and wildlife issues associated with the relicensing of the Mid-Snake and CJ Strike projects, including issues relating to threatened and endangered snails. IPC and the USFWS advised the FERC that they hoped to complete these efforts within 90 days of August 5, 2003. On August 14, 2003, the FERC responded to IPC advising they would not take action on the licenses prior to the expiration of the 90 day period. IPC and the USFWS efforts in this regard continue and IPC and the USFWS jointly reported to the FERC as to their progress on November 5, 2003.

REGULATORY ISSUES:

Lost Revenue
In the IPUC's 2002 order related to IPC's 2002-2003 PCA, the IPUC disallowed recovery of $12 million in lost revenues resulting from the irrigation load reduction program. IPC believes that the IPUC's order is inconsistent with an earlier order that allowed recovery of such costs, and IPC filed a Petition for Reconsideration on May 2, 2002. On August 29, 2002, the IPUC denied the Petition for Reconsideration. As a result of this order the $12 million was expensed in September 2002. IPC still believes it should be entitled to receive recovery of this amount and asked the Idaho Supreme Court to review the IPUC's decision. Oral argument for this case is set for December 5, 2003. If successful, IPC would record any amount recovered as revenue.

IPC's deferred power supply costs consisted of the following at:

			September 30,		December 31,
			2003		2002

Oregon deferral			$	13,752	$	14,172

Idaho PCA power supply cost deferrals:
	Deferral during the 2003-2004 rate year			35,006		-
	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			26,084		-

	Total deferral		$	74,842	$	140,288

General Rate Case
IPC filed an application with the IPUC on October 16, 2003 to increase its general rates an average of 17.7 percent. If approved, IPC's revenues would increase $86 million annually based on the proposed 11.2 percent return on equity. An additional component of the filing was a request for interim rate relief of $20 million. The interim rate request represents a portion of the general rate request. If approved, IPC could begin to collect a 4.2 percent uniform interim rate increase within 30 days of the filing. Oral arguments from intervening parties on the interim increase are scheduled to be heard on November 13, 2003.
In addition, IPC proposed a seasonal rate schedule. If approved, the price IPC charges its customers from June to August would reflect IPC's seasonably higher costs of producing or purchasing power. The change would result in summer and non-summer base rates.

IPC's proposal requests 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, which could take up to seven months from the filing date. IPC is unable to predict what rate relief, if any, the IPUC will grant.

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.

PPL Montana Power Purchase Agreement: During May 2003, IPC and PPL Montana, LLC (PPLM) entered into a firm wholesale Purchase Power Adjustment (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.

Bennett Mountain Power Plant: 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. As a result of this process, IPC selected Mountain View Power as the successful bidder for the construction of the BMPP, a 160-MW gas-fired generating plant near Mountain Home, Idaho. Mountain View Power has contracted with Siemens Westinghouse Power Corporation to furnish all of the labor, equipment and materials and to perform all of the engineering and construction of the plant. The project cost - including plant construction and associated transmission system upgrades - is $61 million. IPC will take ownership of the plant once it is fully tested and operational.

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. On October 24, 2003, the IPUC issued Order No. 29362 which directs IPC to collaboratively develop and submit a Phase One AMR Implementation Plan to replace current residential meters with advanced meters in selected service areas. The plan must be filed within 60 days of the service date of the order. The IPUC also directed IPC to complete Phase One AMR installation by December 31, 2004, and to file an AMR Phase One implementation status report no later than the end of 2005. Should IPC be directed to fully implement an AMR system, a four-year implementation commencing with Phase One 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 multi-year license. Three more of IPC's 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 multi-year license. Final Environmental Impact Statements have been
	issued. FERC licenses anticipated in 2004.

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 multi-year 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 September 30, 2003, $57 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 multi-year 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. The court granted IPC intervention and set the matter for oral argument on March 16, 2004.

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. RTOs, or Independent Transmission Providers would administer the market. 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.

OTHER MATTERS:

IdaTech's Department of Energy Development Program
On September 18, 2003, IdaTech was awarded a development program of $9.6 million by the United States Department of Energy for the development of a 50-kilowatt proton exchange membrane (PEM) fuel cell system suitable for providing grid-independent energy sources for large facilities. This is a three-year, cost-shared cooperative agreement between IdaTech and other technology, utility and hotel companies.

The fully integrated PEM fuel cell system will combine IdaTech's patented multi-fuel fuel processing technology with another company's fuel cell power module and will deliver both electricity and thermal energy to hotel systems.

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: The sale of IE's forward book of electricity trading contracts to SET has eliminated the energy trading commodity price risk.

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 Risk Management Committee (RMC) 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 September 30, 2003, 70 percent of the credit exposure related to IE's unrealized positions was with investment grade counterparties, less than one percent was with non-investment grade counterparties and the remaining 29 percent was with non-rated counterparties. The majority of the non-rated entities are municipalities, public utility districts and electric cooperatives. The following table presents the maturity of credit risk exposure for energy marketing at September 30, 2003:

		Less than		2-5		More than
		2 Years		Years		5 Years			Total
Investment Grade		$	16,094	$	-	$		-	$	16,094
Non-Investment Grade			8		-			-		8
No External Ratings			6,743		-			-		6,743
	Total	$	22,845	$	-		$	-	$	22,845

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 September 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 September 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 to the Quarterly Reports on Forms 10-Q for the quarters ended March 31, 2003 and June 30, 2003.

ITEM 5. OTHER INFORMATION

Marlene K. Williams, Vice President - Human Resources of IDACORP, Inc. and Idaho Power Company resigned in October 2003. Ms. Williams served in this position for Idaho Power Company since 1999 and IDACORP, Inc. since 2002.

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

	1-3198 Form 10-Q for 6/30/03	4(a)(iii)	Thirty-eighth	May 15, 2003

4(a)(iii)			Thirty-ninth	October 1, 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)(i)	33-65720	4(f)	Agreement of IPC to furnish certain debt instruments.

4(c)(ii)			Agreement of IDACORP, Inc. 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.


1 Compensatory plan
*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.

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

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

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

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

*10(k)	1-3198 Form 10-Q for 6/30/03	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.)


1 Compensatory plan
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.

99			Earnings press release for third quarter 2003.

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

Items Reported	Date of Report	Filed by
Item 12 - Results of Operations and
Financial Condition	August 7, 2003	IDACORP, Inc. and Idaho Power Company
Item 5 - Other Events and Regulation FD Disclosure	August 14, 2003	IDACORP, Inc.
Item 5 - Other Events and Regulation FD Disclosure	August 18, 2003	IDACORP, Inc. and Idaho Power Company
Item 5 - Other Events and Regulation FD Disclosure	September 18, 2003	IDACORP, Inc. and Idaho Power Company

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	November 6, 2003	By:	/s/	Jan B. Packwood
				Jan B. Packwood
				President and Chief Executive Officer
				and Director

Date	November 6, 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	November 6, 2003	By:	/s/	J. LaMont Keen
				J. LaMont Keen
				President and Chief Operating Officer

Date	November 6, 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

IDACORP, Inc.:	38,206,621
Idaho Power Company:	37,612,351 all held by IDACORP, Inc.

Page

Part I. Financial Information:
	Item 1. Financial Statements (unaudited)
		IDACORP, Inc.:
			Consolidated Statements of Income	1-2
			Consolidated Balance Sheets	3-4
			Consolidated Statements of Cash Flows	5
			Consolidated Statements of Comprehensive Income	6
			Notes to Consolidated Financial Statements	7-24
			Independent Accountants' Report	25
		Idaho Power Company:
			Consolidated Statements of Income	27-28
			Consolidated Balance Sheets	29-30
			Consolidated Statements of Capitalization	31
			Consolidated Statements of Cash Flows	32
			Consolidated Statements of Comprehensive Income	33
			Notes to Consolidated Financial Statements	34-35
			Independent Accountants' Report	36

	Item 2. Management's Discussion and Analysis of Financial
		Condition and Results of Operations		37-62

	Item 3. Quantitative and Qualitative Disclosures about Market Risk			62-63

	Item 4. Controls and Procedures			63-64

Part II. Other Information:

	Item 1. Legal Proceedings			64

	Item 5. Other Information			64

	Item 6. Exhibits and Reports on Form 8-K			64-69

Signatures				70-71

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

COMMONLY USED TERMS

AG	-	California Attorney General
ALJ	-	Administrative Law Judge
ARO	-	Asset Retirement Obligation
BMPP	-	Bennett Mountain Power Plant
Cal ISO	-	California Independent System Operator
CalPX	-	California Power Exchange
EPS	-	Earnings per share
FASB	-	Financial Accounting Standards Board
FERC	-	Federal Energy Regulatory Commission
FIN	-	FASB Interpretation
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
MD&A	-	Management's Discussion and Analysis
MMbtu	-	Million British Thermal Units
MMCP	-	Mitigated Market Clearing Price
MW	-	Megawatt
MWh	-	Megawatt-hour
NPC	-	Nevada Power Company
OPUC	-	Oregon Public Utility Commission
PCA	-	Power Cost Adjustment
PM&E	-	Protection, Mitigation and Enhancement
PMC	-	Plaintiffs' Master Complaint
PPA	-	Power Purchase Agreement
PPLM	-	PPL Montana, LLC
REA	-	Rural Electrification Administration
RFP	-	Request for Proposal
RMC	-	Risk Management Committee
RTOs	-	Regional Transmission Organizations
S&P	-	Standard & Poor's
SCE	-	Southern California Edison
SET	-	Sempra Energy Trading
SFAS	-	Statement of Financial Accounting Standards
WSPP	-	Western Systems Power Pool

Three Months Ended

Nine Months Ended

Three Months Ended

Nine Months Ended

Date of Report

Filed by