IDAHO POWER CO - 10-Q Quarterly Report

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

				Three Months Ended September 30,
				2004		2003
				(thousands of dollars except for per
				share amounts)
OPERATING REVENUES:
	Electric utility:
		General business		$	186,687	$	188,247
		Off-system sales			34,969		16,442
		Other revenues			19,532		10,172
			Total electric utility revenues		241,188		214,861
	Energy marketing				(152)		17,193
	Other				5,641		7,174
		Total operating revenues			246,677		239,228

OPERATING EXPENSES:
	Electric utility:
		Purchased power			79,607		77,280
		Fuel expense			28,291		25,606
		Power cost adjustment			19,620		(9,787)
		Other operations and maintenance			63,243		54,276
		Depreciation			25,229		24,439
		Taxes other than income taxes			4,593		5,164
			Total electric utility expenses		220,583		176,978
	Energy marketing:
		Cost of revenues			(2)		(1,733)
		Selling, general and administrative			558		8,070
		Net gain on legal disputes			(3,150)		-
	Other				9,755		7,939
			Total operating expenses		227,744		191,254

OPERATING INCOME (LOSS):
	Electric utility				20,605		37,883
	Energy marketing				2,442		10,856
	Other				(4,114)		(765)
		Total operating income			18,933		47,974

OTHER INCOME					8,102		5,862

OTHER EXPENSES					4,075		3,731

INTEREST EXPENSE AND PREFERRED DIVIDENDS:
	Interest on long-term debt				14,061		14,571
	Other interest				602		407
	Preferred dividends of Idaho Power Company				3,116		847
		Total interest expense and preferred dividends			17,779		15,825

INCOME BEFORE INCOME TAXES					5,181		34,280

INCOME TAX BENEFIT					(20,886)		(12,495)

NET INCOME				$	26,067	$	46,775

AVERAGE COMMON SHARES OUTSTANDING (000's)					38,191		38,242
EARNINGS PER SHARE OF COMMON
	STOCK (basic and diluted)			$	0.68	$	1.22
DIVIDENDS PAID PER SHARE OF COMMON STOCK				$	0.30	$	0.46

The accompanying notes are an integral part of these statements.

IDACORP, Inc.
Consolidated Statements of Income
(unaudited)

				Nine Months Ended September 30,
				2004		2003
				(thousands of dollars except for per
				share amounts)
OPERATING REVENUES:
	Electric utility:
		General business		$	491,149	$	529,922
		Off-system sales			99,899		54,889
		Other revenues			40,653		31,100
			Total electric utility revenues		631,701		615,911
	Energy marketing				(76)		19,733
	Other				15,113		15,788
		Total operating revenues			646,738		651,432

OPERATING EXPENSES:
	Electric utility:
		Purchased power			162,877		122,904
		Fuel expense			77,364		75,052
		Power cost adjustment			30,438		67,443
		Other operations and maintenance			180,515		164,398
		Depreciation			75,459		72,853
		Taxes other than income taxes			15,536		15,572
		Impairment of assets			9,756		-
			Total electric utility expenses		551,945		518,222
	Energy marketing:
		Cost of revenues			(81)		1,972
		Selling, general and administrative			1,620		21,254
		Net (gain) loss on legal disputes			(4,798)		10,938
	Other				27,518		25,637
			Total operating expenses		576,204		578,023

OPERATING INCOME (LOSS):
	Electric utility				79,756		97,689
	Energy marketing				3,183		(14,431)
	Other				(12,405)		(9,849)
		Total operating income			70,534		73,409

OTHER INCOME					31,948		17,462

OTHER EXPENSES					15,253		11,330

INTEREST EXPENSE AND PREFERRED DIVIDENDS:
	Interest on long-term debt				40,628		44,213
	Other interest				2,641		2,418
	Preferred dividends of Idaho Power Company				4,823		2,581
		Total interest expense and preferred dividends			48,092		49,212

INCOME BEFORE INCOME TAXES					39,137		30,329

INCOME TAX BENEFIT					(19,580)		(12,495)

NET INCOME				$	58,717	$	42,824

AVERAGE COMMON SHARES OUTSTANDING (000's)					38,193		38,227
EARNINGS PER SHARE OF COMMON
	STOCK (basic and diluted)			$	1.54	$	1.12
DIVIDENDS PAID PER SHARE OF COMMON STOCK				$	0.90	$	1.39

The accompanying notes are an integral part of these statements.

IDACORP, Inc.
Consolidated Balance Sheets
(unaudited)

			September 30,		December 31,
			2004		2003
ASSETS			(thousands of dollars)

CURRENT ASSETS:
	Cash and cash equivalents		$	20,949	$	75,159
	Receivables:
		Customer		96,579		93,599
		Allowance for uncollectible accounts		(43,495)		(43,210)
		Employee notes		3,590		3,347
		Other		6,567		8,209
	Energy marketing assets			9,117		4,176
	Accrued unbilled revenues			31,269		30,869
	Materials and supplies (at average cost)			27,194		21,351
	Fuel stock (at average cost)			6,238		6,228
	Prepayments			27,753		27,779
	Regulatory assets			4,949		6,269
		Total current assets		190,710		233,776

INVESTMENTS				191,229		204,474

PROPERTY, PLANT AND EQUIPMENT:
	Utility plant in service			3,288,631		3,220,228
	Accumulated provision for depreciation			(1,310,332)		(1,239,604)
		Utility plant in service - net		1,978,299		1,980,624
	Construction work in progress			152,709		96,091
	Utility plant held for future use			2,540		2,438
	Other property, net of accumulated depreciation			44,016		9,166
		Property, plant and equipment - net		2,177,564		2,088,319

OTHER ASSETS:
	American Falls and Milner water rights			31,585		31,585
	Company-owned life insurance			36,003		35,624
	Energy marketing assets - long-term			17,123		14,358
	Regulatory assets			416,911		427,760
	Long-term receivables			3,106		3,106
	Employee notes			4,157		4,775
	Other			57,531		57,949
		Total other assets		566,416		575,157

		TOTAL	$	3,125,919	$	3,101,726

The accompanying notes are an integral part of these statements.

IDACORP, Inc.
Consolidated Balance Sheets
(unaudited)

				September 30,		December 31,
				2004		2003
LIABILITIES AND SHAREHOLDERS' EQUITY				(thousands of dollars)

CURRENT LIABILITIES:
	Current maturities of long-term debt			$	77,510	$	67,923
	Notes payable				82,135		93,650
	Accounts payable				56,121		60,916
	Energy marketing liabilities				9,278		4,317
	Taxes accrued				37,728		35,580
	Interest accrued				22,287		13,741
	Deferred income taxes				3,308		5,639
	Other				22,396		25,557
		Total current liabilities			310,763		307,323

OTHER LIABILITIES:
	Deferred income taxes				532,283		554,715
	Energy marketing liabilities - long-term				17,124		14,393
	Regulatory liabilities				279,894		258,524
	Other				113,226		104,290
		Total other liabilities			942,527		931,922

LONG-TERM DEBT					985,487		945,834

COMMITMENTS AND CONTINGENT LIABILITIES

PREFERRED STOCK OF IDAHO POWER COMPANY					-		52,366

SHAREHOLDERS' EQUITY:
	Common stock, no par value (shares authorized 120,000,000; 38,348,758
		and 38,341,358 shares issued, respectively)			474,666		472,902
	Retained earnings				421,504		397,167
	Accumulated other comprehensive loss				(3,525)		(2,630)
	Treasury stock (156,736 and 110,748 shares at cost, respectively)				(4,578)		(3,158)
	Unearned compensation				(925)		-
		Total shareholders' equity			887,142		864,281

			TOTAL	$	3,125,919	$	3,101,726

The accompanying notes are an integral part of these statements.

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

				Nine Months Ended
				September 30,
				2004		2003
				(thousands of dollars)
OPERATING ACTIVITIES:
	Net income			$	58,717	$	42,824
	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			262		(254)
		Impairment of assets			9,756		-
		Unrealized losses from energy marketing activities			-		42,517
		Depreciation and amortization			93,335		97,802
		Deferred taxes and investment tax credits			(25,918)		(71,466)
		Accrued power cost adjustment costs			29,100		65,446
		Gain on sale of non-utility assets			(4,557)		-
		Gain on extinguishment of debt			(7,188)		-
		Change in:
			Receivables and prepayments		(1,613)		71,248
			Accrued unbilled revenues		(401)		7,258
			Materials and supplies and fuel stock		(577)		3,773
			Accounts payable and other accrued liabilities		(6,800)		(71,355)
			Taxes receivable/accrued		2,148		49,453
			Other current liabilities		7,438		978
		Other assets			(9,283)		2,369
		Other liabilities			10,993		5,652
			Net cash provided by operating activities		155,412		257,183

INVESTING ACTIVITIES:
	Additions to property, plant and equipment				(145,061)		(97,567)
	Sale of non-utility assets				5,389		-
	Other assets				246		(3,198)
	Other liabilities				(1,552)		(581)
		Net cash used in investing activities			(140,978)		(101,346)

FINANCING ACTIVITIES:
	Issuance of first mortgage bonds				105,000		140,000
	Issuance of other long-term debt				-		65,492
	Retirement of first mortgage bonds				(50,000)		(160,000)
	Retirement of other long-term debt				(23,419)		(11,769)
	Retirement of preferred stock of Idaho Power Company				(52,220)		(909)
	Dividends on common stock				(34,224)		(53,260)
	Decrease in short-term borrowings				(12,385)		(151,175)
	Common stock issued				206		4,123
	Acquisition of treasury shares				(1,420)		(798)
	Other assets				-		(3,843)
	Other liabilities				(182)		(240)
		Net cash used in financing activities			(68,644)		(172,379)

Net decrease in cash and cash equivalents					(54,210)		(16,542)
Cash and cash equivalents beginning of period					75,159		42,736
Cash and cash equivalents end of period				$	20,949	$	26,194

SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION:
	Cash paid during the period for:
		Income taxes		$	8,948	$	15,677
		Interest (net of amount capitalized)		$	32,868	$	35,765

The accompanying notes are an integral part of these statements.

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

				Three Months Ended
				September 30,
				2004		2003
				(thousands of dollars)

NET INCOME				$	26,067	$	46,775

OTHER COMPREHENSIVE INCOME (LOSS):
	Unrealized gains (losses) on securities:
		Unrealized holding gains (losses) arising during the period,
			net of tax of ($302) and $296		(526)		521
		Reclassification adjustment for gains included
			in net income, net of tax of ($228) and ($111)		(355)		(172)
			Net unrealized gains (losses)		(881)		349

TOTAL COMPREHENSIVE INCOME				$	25,186	$	47,124

				Nine Months Ended
				September 30,
				2004		2003
				(thousands of dollars)

NET INCOME				$	58,717	$	42,824

OTHER COMPREHENSIVE INCOME (LOSS):
	Unrealized gains (losses) on securities:
		Unrealized holding gains (losses) arising during the period,
			net of tax of ($18) and $1,291		(56)		2,189
		Reclassification adjustment for (gains) losses included
			in net income, net of tax of ($609) and $120		(949)		186
			Net unrealized gains (losses)		(1,005)		2,375

TOTAL COMPREHENSIVE INCOME				$	57,712	$	45,199

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). IDACORP is exempt from registration as a public utility holding company pursuant to Section 3(a)(1) of the Public Utility Holding Company Act of 1935 (1935 Act). In addition, pursuant to Rule 2 of the General Rules and Regulations under the 1935 Act, IDACORP is exempt from all the provisions of the 1935 Act and rules thereunder, except for Section 9(a)(2) of the 1935 Act, which requires IDACORP to seek prior Securities and Exchange Commission approval to acquire securities of another public utility company.

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.

IDACORP's other operating subsidiaries include:

IdaTech - developer of integrated fuel cell systems;

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

IDACOMM - provider of telecommunications services and owner of Velocitus, a commercial and residential Internet service provider;

Ida-West Energy (Ida-West) - operator of independent power projects; and

IDACORP Energy (IE) - marketer of electricity and natural gas.

IE wound down its operations during 2003. Also in 2003, Ida-West discontinued its project development operations and is managing its independent power projects with a reduced workforce.

During the third quarter of 2004, IDACORP transferred its ownership of Rocky Mountain Communications Holdings and its subsidiary Velocitus to IDACOMM.

Principles of Consolidation
The consolidated financial statements of IDACORP and IPC include the accounts of each company and those variable interest entities (VIEs) for which the companies are the primary beneficiaries. All significant intercompany balances have been eliminated in consolidation. Investments in business entities in which IDACORP and IPC are not the primary beneficiaries, but have the ability to exercise significant influence over operating and financial policies, are accounted for using the equity method.

The entities that IDACORP and IPC consolidate consist primarily of wholly-owned or controlled subsidiaries. In addition, IDACORP consolidates the following VIEs:

Ida-West participates in Marysville Hydro Partners, a joint venture that owns a small hydroelectric project. Marysville has approximately $23 million of assets, primarily the hydroelectric plant, and approximately $18 million of intercompany long-term debt, which is eliminated in consolidation.

IFS is a limited partner in Empire Development Company, LLC (Empire), an entity that earns historic tax credits through the rehabilitation of the Empire Building in Boise, Idaho. Empire has approximately $9 million of assets, primarily real property, and $8 million of long-term debt. This debt is non-recourse to IDACORP, personally guaranteed by the general partner and collateralized by the property.

Through IFS, IDACORP also holds significant variable interests in VIEs for which it is not the primary beneficiary. These VIEs are historic rehabilitation and affordable housing developments in which IFS holds limited partnership interests ranging from five to 99 percent. These investments were acquired between 1996 and 2002. IFS's maximum exposure to loss in these developments totaled $106 million at September 30, 2004.

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 positions as of September 30, 2004, and consolidated results of operations for the three and nine months ended September 30, 2004 and 2003 and consolidated cash flows for the nine months ended September 30, 2004 and 2003. 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, 2003. 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. The diluted EPS computation excluded 823,000 common stock options for the three and nine months ended September 30, 2004, because the options' exercise prices were greater than the average market price of the common stock during the periods. For the same periods in 2003, 721,800 options were excluded from the diluted EPS calculation for the same reason. In total, 1,216,200 options were outstanding at September 30, 2004, with expiration dates between 2010 and 2014.

Stock-Based Compensation
Stock-based employee compensation is 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 performance shares are reflected in net income based on the market value at the award date, or the period-end price for shares not yet vested. Grants of restricted stock are reflected in net income based on the market value on the grant date. No stock-based employee compensation cost is reflected in net income for stock options, as all options granted 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 IDACORP's 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,
			2004		2003		2004		2003

Net income, as reported			$	26,067	$	46,775	$	58,717	$	42,824
Add: Stock-based employee compensation
	expense included in reported net income,
	net of related tax effects			60		63		291		125
Deduct: Total stock-based employee
	compensation expense determined under
	fair value based method for all awards, net
	of related tax effects			207		384		864		801
		Pro forma net income	$	25,920	$	46,454	$	58,144	$	42,148
EPS of common stock:
	Basic and diluted - as reported		$	0.68	$	1.22	$	1.54	$	1.12
	Basic and diluted - pro forma			0.68		1.22		1.52		1.10

Adopted Accounting Pronouncements
FIN 46R: In January 2004, IDACORP and IPC adopted Financial Accounting Standards Board (FASB) Interpretation (FIN) 46R, "Consolidation of Variable Interest Entities - an interpretation of ARB No. 51," which addresses consolidation by business enterprises of VIEs, which have one or more of the following characteristics:

1. The equity investment at risk is not sufficient to permit the entity to finance its activities without additional subordinated financial support provided by any parties, including the equity holders.

2. The equity investors lack one or more of the following essential characteristics of a controlling financial interest:

a. The direct or indirect ability to make decisions about the entity's activities through voting rights or similar rights.

b. The obligation to absorb the expected losses of the entity.

c. The right to receive the expected residual returns of the entity.

3. The equity investors have voting rights that are not proportionate to their economic interests, and the activities of the entity involve or are conducted on behalf of an investor with a disproportionately small voting interest.

IDACORP and IPC evaluated their investments, contracts and other potential variable interests that would be subject to the provisions of FIN 46R, and IDACORP determined that it must consolidate two entities under those provisions. At adoption, total assets and liabilities each increased by $29 million and consisted primarily of property and long-term debt. Net income and cash flows were not affected by the adoption of the interpretation.

FSP FAS 106-2: See Note 9 - Benefit Plans for a discussion of this FASB Staff Position (FSP) with respect to postretirement benefit obligations.

Reclassifications
Certain items previously reported for periods prior to September 30, 2004 have been reclassified to conform to the current period's presentation. Net income and shareholders' equity were not affected by these reclassifications.

2. INCOME TAXES:

IDACORP uses an estimated annual effective tax rate for computing its provision for income taxes on an interim basis. The estimated effective tax rates for 2004 and 2003 were negative 50.0 percent and negative 41.2 percent, respectively. The 2004 negative estimated tax rate is due primarily to tax credits from IFS, which totaled approximately $15 million in the first nine months of 2004, and to the reversal of a $16 million regulatory tax liability as a result of Settlement No. 2, discussed in Note 6 - Regulatory Matters. In 2003, $15 million in tax credits from IFS during the first nine months, along with the favorable resolution of prior year tax audits, resulted in the negative estimated annual rate.

3. CAPITAL STOCK:

Common Stock
During the nine months ended September 30, 2004, IDACORP purchased 45,988 shares for its Restricted Stock Plan, issued 1,167 shares to shareholders of Rocky Mountain Communications Holdings, the parent company of Velocitus, and issued 7,400 shares pursuant to the exercise of stock options granted under the Long-Term Incentive and Compensation Plan.

Preferred Stock of IPC
On September 20, 2004, IPC redeemed all of its outstanding preferred stock for $54 million using proceeds from the issuance of first mortgage bonds. This amount includes $2 million of premium that was recorded as preferred dividends on the Consolidated Statements of Income. The redemption price was $104 per share for the 122,989 shares of 4% preferred stock, $103.18 per share for the 250,000 shares of 7.07% preferred stock and $102.97 per share for the 150,000 shares of 7.68% preferred stock, plus accumulated and unpaid dividends.

4. FINANCING:

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

			September 30,		December 31,
			2004		2003
First mortgage bonds:
	8 % Series due 2004		$	-	$	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		70,000
	6 % Series due 2032			100,000		100,000
	5.50% Series due 2033			70,000		70,000
	5.50% Series due 2034			50,000		-
	5.875% Series due 2034			55,000		-
		Total first mortgage bonds		785,000		730,000
Pollution control revenue bonds:
	Variable Auction Rate Series 2003 due 2024 (a)			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				-		1,105

American Falls bond guarantee				19,885		19,885

Milner Dam note guarantee				11,700		11,700

Unamortized premium/(discount) - net				(3,188)		(2,205)

Debt related to investments in affordable housing				71,115		82,715

Other subsidiary debt				8,025		97
	Total			1,062,997		1,013,757
Current maturities of long-term debt				(77,510)		(67,923)

		Total long-term debt	$	985,487	$	945,834

(a) Humboldt County Pollution Control Revenue bonds are secured by first mortgage bonds, bringing the total first mortgage
	bonds outstanding at September 30, 2004 to $834.8 million.

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, 2004, 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 in two series: $70 million First Mortgage Bonds 4.25% Series due 2013 and $70 million First Mortgage Bonds 5.50% Series due 2033. Proceeds were used to pay down IPC short-term borrowings incurred from the payment at maturity 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. On March 26, 2004, IPC issued $50 million First Mortgage Bonds 5.50% Series due 2034. Proceeds were used to reduce short-term borrowings and replace short-term investments, which were used on March 15, 2004 to pay at maturity the $50 million First Mortgage Bonds 8% Series due 2004. On August 16, 2004, IPC issued $55 million First Mortgage Bonds 5.875% Series due 2034. On September 20, 2004, the proceeds of this issuance were used to redeem all of the outstanding preferred stock of IPC. At September 30, 2004, $55 million remained available to be issued on this shelf registration statement.

On August 17, 2004, IPC redeemed all $1 million of its Rural Electrification Administration notes.

IDACORP has a $150 million credit facility that expires on March 16, 2007. Under this facility IDACORP pays a facility fee on the commitment, quarterly in arrears, based on its rating for senior unsecured long-term debt securities without third-party credit enhancement as provided by Moody's Investors Service (Moody's) and Standard & Poor's Ratings Services (S&P). Commercial paper may be issued up to the amounts supported by the bank credit facilities. At September 30, 2004, $60 million of commercial paper was outstanding.

At September 30, 2004, 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 16, 2007. Under this facility IPC pays a facility fee on the commitment, quarterly in arrears, based on its rating for senior unsecured long-term debt securities without third-party credit enhancement as provided by Moody's and S&P. IPC's commercial paper may be issued up to the amounts supported by the bank credit facilities. At September 30, 2004, $22 million of commercial paper was outstanding.

At September 30, 2004, IFS had $71 million of debt related to investments in affordable housing with interest rates ranging from 3.65 percent to 8.59 percent due between 2004 and 2010. The investments in affordable housing developments, which collateralize this debt, had a net book value of $107 million at September 30, 2004. IFS's $18 million Series 2003-1 tax credit note is non-recourse to both IFS and IDACORP. The $12 million Series 2003-2 tax credit note and $21 million of borrowings from a corporate lender are recourse only to IFS.

In June 2004, Ida-West purchased from a third party $18 million of debt issued by Marysville Hydro Partners, a 50-percent-owned, consolidated joint venture, for $11 million. This debt, previously consolidated under the provisions of FIN 46R, is now eliminated in consolidation. Ida-West borrowed $6 million from IDACORP for this transaction.

As a result of IDACORP's adoption of FIN 46R in January 2004, other subsidiary debt increased $8 million from December 31, 2003. This debt is non-recourse to IDACORP, personally guaranteed by the general partner and collateralized by property.

5. COMMITMENTS AND CONTINGENT LIABILITIES:

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

Legal Proceedings
Vierstra Dairy: On August 11, 2000, Mike and Susan Vierstra, dairy operators from Twin Falls, Idaho, brought suit against IPC in Idaho State District Court, Fifth Judicial District, Twin Falls County. The plaintiffs sought monetary damages of approximately $8 million for negligence and nuisance (allegedly allowing electrical current to flow in the earth and adversely affect the health of the plaintiffs' dairy cows) and punitive damages of approximately $40 million.

On February 10, 2004, a jury verdict was entered in favor of the plaintiffs, awarding approximately $7 million in compensatory damages and $10 million in punitive damages. In March 2004, IPC filed with the Idaho State District Court motions for new trial and for judgment notwithstanding the verdict. These motions were heard by the court on April 26, 2004. On June 7, 2004, the court denied the motions. IPC filed its notice of appeal of this decision with the Idaho Supreme Court on July 13, 2004, with an amended notice filed on July 15, 2004.

On September 17, 2004, the Idaho Supreme Court dismissed the appeal incident to a settlement of the matter among IPC, IPC's insurance carrier and the plaintiffs. The settlement, less a deductible, was covered by insurance and did not have a material effect on IPC's consolidated financial position, results of operations or cash flows.

Alves Dairy: On May 18, 2004, Herculano and Frances Alves, dairy operators from Twin Falls, Idaho, brought suit against IPC in Idaho State District Court, Fifth Judicial District, Twin Falls County. The plaintiffs seek unspecified monetary damages for negligence and nuisance (allegedly allowing electrical current to flow in the earth, injuring the plaintiffs' right to use and enjoy their property and adversely affecting their dairy herd). On July 16, 2004, IPC filed an answer to Mr. and Mrs. Alves's complaint, denying all liability to the plaintiffs, and asserting certain affirmative defenses. The parties have begun initial discovery in the case. No trial date has been scheduled.

IPC intends to vigorously defend its position in this proceeding and believes this matter, with insurance coverage, will not have a material adverse effect on its consolidated financial position, results of operations or cash flows.

Public Utility District No. 1 of Grays Harbor County, Washington: On October 15, 2002, Public Utility District No. 1 of Grays Harbor County, Washington (Grays Harbor) filed a lawsuit in the Superior Court of the State of Washington, for the County of Grays Harbor, against IDACORP, IPC and IE. On March 9, 2001, Grays Harbor entered into a 20 Megawatt (MW) purchase transaction with IPC for the purchase of electric power from October 1, 2001 through March 31, 2002, at a rate of $249 per 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 United States 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. On August 10, 2004, the Ninth Circuit affirmed the dismissal of Grays Harbor's complaint, finding that Grays Harbor's claims were preempted by federal law and were barred by the filed-rate doctrine. The court also remanded the case to allow Grays Harbor leave to amend its complaint to seek declaratory relief only as to contract formation, and held that Grays Harbor could seek monetary relief, if at all, only from FERC, and not from the courts. IDACORP, IPC and IE sought rehearing from the Ninth Circuit arguing that the court erred in granting leave to amend the complaint as such a declaratory relief claim would be preempted and would be barred by the filed-rate doctrine. The Ninth Circuit denied the rehearing request on October 25, 2004. The companies intend to vigorously defend their position on remand and believe this matter 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 laws and the Racketeer Influenced and Corrupt Organizations Act. On December 4, 2003, the Judicial Panel on Multidistrict Litigation transferred the case to the Southern District of California for inclusion with several similar multidistrict actions currently pending before the Honorable Robert H. Whaley.

All defendants, including IPC and IDACORP, moved to dismiss the complaint in lieu of answering it. The motions were based on the ground that the complaint seeks to set alternative electrical rates, which are exclusively within the jurisdiction of the FERC and are barred by the filed-rate doctrine. A hearing on the motion to dismiss was heard on March 26, 2004. On May 28, 2004, the court granted IPC and IDACORP's motion to dismiss. In June 2004, the Port of Seattle appealed the court's decision to the United States Court of Appeals for the Ninth Circuit. The parties have not yet completed the filing of all briefs on appeal, and the Ninth Circuit has not yet heard oral argument on appeal. 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.

Wah Chang: On May 5, 2004, Wah Chang, a division of TDY Industries, Inc., filed two lawsuits in the United States District Court for the District of Oregon against numerous defendants. IDACORP, IE and IPC are named as defendants in one of the lawsuits. The complaints allege violations of federal antitrust laws, violations of the Racketeer Influenced and Corrupt Organizations Act, violations of Oregon antitrust laws and wrongful interference with contracts. Wah Chang's complaint is based on allegations relating to the western energy situation. These allegations include bid rigging, falsely creating congestion and misrepresenting the source and destination of energy. The plaintiff seeks compensatory damages of $30 million and treble damages.

On September 8, 2004, this case was transferred and consolidated with other similar cases currently pending before the Honorable Robert H. Whaley, sitting by designation in the Southern District of California and presiding over Multidistrict Litigation Docket No. 1405, regarding California Wholesale Electricity Antitrust Litigation. IDACORP, IE and IPC have not answered the complaint as a response is not yet required. The companies plan to file a motion to dismiss the complaint and intend to vigorously defend their position in this proceeding and believe this matter will not have a material adverse effect on their consolidated financial positions, results of operations or cash flows.

City of Tacoma: On June 7, 2004, the City of Tacoma, Washington filed a lawsuit in the United States District Court for the Western District of Washington at Tacoma against numerous defendants including IDACORP, IE and IPC. The City of Tacoma's complaint alleges violations of the Sherman Antitrust Act. The claimed antitrust violations are based on allegations of energy market manipulation, false load scheduling and bid rigging and misrepresentation or withholding of energy supply. The plaintiff seeks compensatory damages of not less than $175 million.

On September 8, 2004, this case was transferred and consolidated with other similar cases currently pending before the Honorable Robert H. Whaley, sitting by designation in the Southern District of California and presiding over Multidistrict Litigation Docket No. 1405, regarding California Wholesale Electricity Antitrust Litigation. IDACORP, IE and IPC have not answered the complaint, as a response is not yet required. The companies plan to file a motion to dismiss the complaint and intend to vigorously defend their position in this proceeding 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, 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 and (2) charging unjust and unreasonable rates. 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 to the United States Court of Appeals for the Ninth Circuit, appealing the court's decision granting IPC's motion to dismiss. Briefing on the appeal was completed in October 2003. On October 12, 2004, the Ninth Circuit unanimously affirmed the order denying remand and dismissing all of the AG's actions, including the action against IPC. The AG did not file a petition for rehearing. IPC intends to continue to vigorously defend its position in this proceeding 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. 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 the California Antitrust Law (the Cartwright Act), Business and Professions Code Section 16720 and California's Unfair Competition Law, Business and Professions Code Section 17200. Among the acts complained of are bid rigging, information exchanges, withholding of power and 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 were filed, two of the original defendants, Duke and Reliant, filed separate cross-complaints against IPC and IE, and approximately 30 other cross-defendants. Duke and Reliant's cross-complaints seek indemnity from IPC, IE and the other cross-defendants for an unspecified share of any amounts they must pay in the underlying suits because, they allege, other market participants like IPC and IE engaged in the same conduct at issue in the PMC. Duke and Reliant also seek declaratory relief as to the respective liability and conduct of each of the cross-defendants in the actions alleged in the PMC. Reliant has also asserted a claim against IPC for alleged violations of the California Unfair Competition Law, Business and Professions Code Section 17200. 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, have 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 United States 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 United States Court of Appeals for the Ninth Circuit has granted certain Defendants and Cross-Defendants' Motions to Stay the Remand Order while they appeal the order. The briefing on the appeal was completed in December 2003. The court heard oral argument on the remand issue on June 14, 2004, but has yet to issue a ruling. The trial court has yet to rule on the companies' motion to dismiss, and no trial date is set. The companies believe these matters will not have a material adverse effect on their consolidated financial positions, results of operations or cash flow.

Western 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 defaulted on a payment, the other participants were required to pay their allocated share of the default amount to the CalPX. 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 its participation agreement with the CalPX. 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 8 invoice. The CalPX later reversed IPC's payment of the January 18, 2001 invoice, but on June 20, 2001 invoiced IPC for an additional $2 million which the CalPX has not reversed. The CalPX owes IPC $14 million for power sold in November and December including $2 million associated with the default share invoice dated June 20, 2001. 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 chargeback methodology and provide for further oversight in the CalPX's implementation of its default mitigation procedures.

A preliminary injunction was granted by a federal judge in the United States 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 the issuance of that order, 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 a 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 (Refund Period).

This case had been complicated by an August 13, 2002 FERC 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 FERC 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. The FERC 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 FERC 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 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. However, as to potential refunds, if any, IE believes its exposure is likely to be offset by amounts due from California entities.

IE, along with a number of other parties, filed an application with the FERC on April 25, 2003 seeking rehearing 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. The Cal ISO has since requested additional time to complete its compliance filings. By order of February 3, 2004, the FERC granted additional time. In a February 10, 2004 report to the FERC, the Cal ISO asserted its belief that it would complete re-running the data and financial clearing of amounts due by August 2004, subject to a number of events that must occur in the interim, including FERC disposition of a number of pending issues. This Cal ISO compliance filing has since been delayed until at least December 2004. The Cal ISO is required to update the FERC on its progress monthly. After receipt of the compliance filing, the FERC will consider cost-based filings from sellers to reduce their refund exposure.

On December 2, 2003, IE petitioned the United States Court of Appeals for the Ninth Circuit for review of the FERC's orders, and since that time, dozens of other petitions for review have been filed. The Ninth Circuit consolidated IE's and the other parties' petitions with the petitions for review arising from earlier FERC orders in this proceeding, bringing the total number of consolidated petitions to more than 80. The Ninth Circuit held the appeals in abeyance pending the disposition of the market manipulation claims discussed below and the development of a comprehensive plan to brief this complicated case. Certain parties also sought further rehearing and clarification before the FERC. On September 21, 2004, the Ninth Circuit convened the first of its case management proceedings, a procedure reserved to help organize complex cases. A briefing schedule has been established for a portion of these cases. A second conference in the case management proceeding is scheduled for November 9, 2004.

On May 12, 2004, the FERC issued an order clarifying portions of its earlier refund orders and, among other things, denying a proposal made by Duke Energy North America and Duke Energy Trading and Marketing (and supported by IE) to lodge as evidence a contested settlement in a separate complaint proceeding, California Public Utilities Commission (CPUC) v. El Paso et al. The CPUC's complaint alleged that the El Paso companies manipulated California energy markets by withholding pipeline transportation capacity into California in order to drive up natural gas prices immediately before and during the California energy crisis in 2000-2001. The settlement will result in the payment by El Paso of some $1.69 billion. Duke claimed that the relief afforded by the settlement was duplicative of the remedies imposed by the FERC in its March 26, 2003 order changing the gas cost component of its refund calculation methodology. IE, along with other parties, has sought rehearing of the May 12, 2004 order. These latter applications remain pending before the FERC.

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, 2004, 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, 2004, 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.

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 rate requirements violate the FPA, and, even if the 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 issued its decision on September 9, 2004, concluding that market-based tariffs are permissible under the FPA, but remanded the matter to the FERC to consider whether the FERC should exercise remedial power (including some form of refunds) when a market participant failed to submit reports that the FERC relies on to confirm the justness and reasonableness of rates charged. Certain parties to the litigation have sought rehearing. The companies cannot predict whether rehearing will be granted or what action the FERC might take if the matter is remanded.

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 (certain investor owned utilities, the California AG, the California Electricity Oversight Board and the CPUC) 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 with the overwhelming majority of the claims of the California Parties relating to the conduct of other parties.

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 with an MMCP, seeking approximately $8 billion in refunds to the Cal ISO and the CalPX. On March 20, 2003, numerous parties, including IE and IPC, submitted briefs and responsive testimony.

In its March 26, 2003 order, discussed above in "California Refund," 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 FERC Staff on the two orders commonly referred to as the "gaming" and "partnership" show cause orders. Regarding the gaming order, the FERC 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 FERC Staff submitted a motion to the FERC to dismiss the proceeding because materials submitted by IPC demonstrated that IPC did not use its "parking" and "lending" arrangement with Public Service Company of New Mexico to engage in "gaming" or anomalous market behavior ("partnership"). The "gaming" settlement was approved by the FERC on March 3, 2004. Eight parties have requested rehearing of the FERC's March 3, 2004 order, but the FERC has not yet acted on those requests. The motion to dismiss the "partnership" proceeding was approved by the FERC in an order issued January 23, 2004 and rehearing of that order was not sought within the time allowed by statute. Some of the California Parties and other parties have petitioned the United States Court of Appeals for the Ninth Circuit and the District of Columbia Circuit for review of the FERC's orders initiating the show cause proceedings. Some of the parties contend that the scope of the proceedings initiated by the FERC was too narrow. Other parties contend that the orders initiating the show cause proceedings were impermissible. Under the rules for multidistrict litigation, a lottery was held and, subject to motions by adversely affected parties, these cases are to be considered in the District of Columbia Circuit. The FERC has moved the District of Columbia Circuit to dismiss these petitions on the grounds of prematurity and lack of ripeness and finality. The District of Columbia Circuit has not yet ruled on the FERC's motion and a briefing schedule has not yet been set. The company is not able to predict the outcome of the judicial determination of these issues.

On June 25, 2003, the FERC also issued an order instituting an investigation of anomalous bidding behavior and practices in the western wholesale power markets. In this investigation, the FERC was to review evidence of alleged economic withholding of generation. The FERC 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 would be considered prima facie evidence of economic withholding. The FERC Staff issued data requests in this investigation to over 60 market participants including IPC. IPC responded to the FERC's data requests. In a letter dated May 12, 2004, the FERC's Office of Market Oversight and Investigations advised that it was terminating the investigation as to IPC.

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 submitted comments to the FERC with respect to 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 are discussed above, 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 requested refunds from IPC of $5 million. Grays Harbor did not suggest that there was any misconduct by IPC or IE. The companies submitted responsive testimony defending vigorously against Grays Harbor's refund claims.

In addition, the Port of Seattle, the City of Tacoma and the City of Seattle 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 improperly having received 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 denied claims that refunds should be paid. The FERC denied rehearing on November 10, 2003. The Port of Seattle, the City of Tacoma, the City of Seattle, the California AG, the CPUC and Puget Sound Energy Inc. filed petitions for review in the United States Court of Appeals for the Ninth Circuit. However, during the time when petitions for review were permitted to be filed, the California AG also sought further rehearing before the FERC. The FERC denied the second request for rehearing of the California AG on February 9, 2004 and the California AG then filed for review in the Ninth Circuit. These petitions have not yet been consolidated. Grays Harbor did not file a petition for review, although it has sought to intervene in the proceedings initiated by others. The FERC has certified the record to the Ninth Circuit, which has established a briefing schedule for the case under which briefing would be completed by January 10, 2005. A date for argument has not yet been set. On July 21, 2004, the City of Seattle submitted to the Ninth Circuit in the Pacific Northwest refund petition a motion requesting leave to offer additional evidence before the FERC in order to try to secure another opportunity for reconsideration by the FERC of its earlier rulings. The evidence that the City of Seattle seeks to introduce before the FERC consists of audio tapes of what purports to be Enron trader conversations containing inflammatory language that have been the subject of recent coverage in the press. Under Section 313(b) of the FPA, a court is empowered to direct the introduction of additional evidence if it is material and could not have been introduced during the underlying proceeding. The City of Seattle also requested that the current briefing schedule, which required briefs to be filed by August 5, 2004, be delayed. On September 29, 2004, the Ninth Circuit Court of Appeals denied the City of Seattle's motion for leave to adduce evidence, without prejudice to renewing the request for remand in the briefing and set the briefing schedule with final briefs due March 2, 2005.

The companies are unable to predict the outcome of these matters.

On July 21, 2004, Californians for Renewable Energy, Inc. (CARE) filed a motion with the FERC in connection with the California Refund proceedings, the Pacific Northwest refund proceedings and the show cause proceedings, both gaming and partnership, including those in which IPC was the respondent. CARE has participated in many of the FERC proceedings dealing with California energy matters, having appointed itself as a representative of low-income communities and other groups that it claims are otherwise not represented. The FERC permitted CARE to participate in the cases as an intervenor. In its current motion, CARE requests that the FERC radically restructure its approach to the California and western energy proceedings involving the events of 2000 and 2001 by revoking market-based rate authority from the date of their approvals, replacing market-based rates with cost-of-service rates by requiring refunds back to the date of the orders granting market-based rate authority, revising long-term energy contracts negotiated during 2000 and 2001 (it appears that the contracts that CARE identified do not include any to which IPC is a party), deferring further refund settlements, establishing a direct pass-through refund mechanism for California consumers and having "previously executed settlement agreements rejected." CARE also requested that the FERC revoke market-based rates for those entities identified in the June 25, 2003 show cause orders, which would include IPC. IPC defended its position in response to this motion and is unable to predict how the FERC will respond to CARE's motion.

Shareholder Lawsuits: On May 26, 2004 and June 22, 2004, respectively, two shareholder lawsuits were filed against IDACORP and certain of its directors and officers. The lawsuits, captioned Powell, et al. v. IDACORP, Inc., et al. and Shorthouse, et al. v. IDACORP, Inc., et al., raise largely similar allegations. The lawsuits are putative class actions brought on behalf of purchasers of IDACORP stock between February 1, 2002 and June 4, 2002, and were filed in the United States District Court for the District of Idaho. The named defendants in each suit, in addition to IDACORP, are Jon H. Miller, Jan B. Packwood, J. LaMont Keen and Darrel T. Anderson.

The complaints allege that, during the purported class period, IDACORP and/or certain of its officers and/or directors made materially false and misleading statements or omissions about the company's financial outlook in violation of Sections 10(b) and 20(a) of the Securities Exchange Act of 1934, as amended, and Rule 10b-5, thereby causing investors to purchase the company's common stock at artificially inflated prices. More specifically, the complaints allege that IDACORP failed to disclose and misrepresented the following material adverse facts which were known to defendants or recklessly disregarded by them: (1) IDACORP failed to appreciate the negative impact that lower volatility and reduced pricing spreads in the western wholesale energy market would have on its marketing subsidiary, IE; (2) IDACORP would be forced to limit its origination activities to shorter-term transactions due to increasing regulatory uncertainty and continued deterioration of creditworthy counterparties; (3) IDACORP failed to discount for the fact that IPC may not recover from the lingering effects of the prior year's regional drought and (4) as a result of the foregoing, defendants lacked a reasonable basis for their positive statements about IDACORP and their earnings projections. The Powell complaint also alleges that the defendants' conduct artificially inflated the price of the company's common stock. The actions seek an unspecified amount of damages, as well as other forms of relief. By order dated August 31, 2004, the court consolidated the Powell and Shorthouse cases for pretrial purposes, and ordered the plaintiffs to file a consolidated complaint within 60 days. On November 1, 2004, IDACORP and the directors and officers named above were served with a purported consolidated complaint captioned Powell et al. v. IDACORP, Inc. et al., which was filed in the United States District Court for the District of Idaho.

The new complaint alleges that during the purported class period (February 1, 2002 to June 4, 2002) the defendants engaged in a scheme to inflate IDACORP's financial results, including engaging in improper energy trading practices from 2000 to 2002, and made materially false and misleading statements or omissions about the company's financial outlook, and that the defendants' conduct caused investors to purchase the company's common stock at artificially inflated prices, in violation of Sections 10(b) and 20(a) of the Securities Exchange Act of 1934, as amended, and Rule 10b-5. IDACORP and the other defendants have 45 days to file their motions to dismiss.

IDACORP and the other defendants intend to defend themselves vigorously against the allegations. The company cannot, however, predict the outcome of these matters.

Powerex: On August 31, 2004, Powerex Corp., the wholly owned power marketing subsidiary of BC Hydro, a Crown Corporation of the province of British Columbia, Canada, filed a lawsuit against IE and IDACORP in the United States District Court for the District of Idaho. Powerex Corp. alleges that IE breached an oral and written contract regarding the assignment of transmission capacity for electric power by IE to Powerex Corp. for a fourteen-month period and for intentional interference with Powerex Corp.'s alleged contract with IE. Powerex Corp. seeks unspecified general and special damages. This complaint has not yet been served on IE and IDACORP. The companies intend to vigorously defend their position in this proceeding but cannot predict the outcome of this matter.

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' (Tribes) Fort Hall Indian Reservation near the city of Pocatello in southeastern Idaho. IPC has been working since 1996 to renew four of the right-of-way permits (for five of the transmission lines), which have stated permit expiration dates between 1996 and 2003. IPC filed applications with the United States Department of the Interior, Bureau of Indian Affairs, to renew the four 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 and allottees have demanded substantially greater payments for the permit renewals, 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. Due to the lack of definitive legal guidelines for valuation of the permit renewals, IPC is in the process of negotiating mutually acceptable renewal terms with the Tribes and allottees. The parties are pursuing a possible 23-year renewal of the permits (including all pre-renewal periods) for a total payment of approximately $7 million to the Tribes and allottees. IPC plans to obtain IPUC approval for the recovery of any renewal payment in its utility rates as a prerequisite to any settlement of the right-of-way renewals with the Tribes.

6. REGULATORY MATTERS:

General Rate Case
Idaho: IPC filed its Idaho general rate case with the IPUC on October 16, 2003. IPC originally requested approximately $86 million annually in additional revenue, an average 17.7 percent increase to base rates. On rebuttal, IPC lowered its overall requested increase to $70 million annually, an average of 14.5 percent. The IPUC conducted formal hearings on the matter from March 29, 2004 through April 5, 2004. The IPUC approved an increase of $25 million in IPC's electric rates, an average of 5.2 percent, in an order issued on May 25, 2004. The rate increase became effective on June 1, 2004.

In the order, the IPUC approved a return on equity of 10.25 percent, compared to the 11.2 percent IPC requested, an overall rate of return of 7.9 percent, compared to the 8.3 percent requested by IPC. The IPUC reduced the $1.55 billion in rate base requested for IPC's Idaho jurisdiction to $1.52 billion.

Additionally, the IPUC approved higher rates for residential and small-commercial customers during the summer months to encourage conservation. The 12.6 percent higher summer rate applies to monthly usage over 300 kilowatt-hours. The IPUC also ordered time-of-use rates to be phased in for industrial customers, asked IPC to submit a proposal for a conservation program for industrial customers and ordered increased low-income weatherization funding of $1 million annually.

The IPUC also noted two other issues to be addressed in separate proceedings and potentially handled in workshops instead of formal hearings. These issues are: (1) investigating approaches to removing financial disincentives to IPC for investing in cost effective energy efficiency and clean distributed generation and (2) investigating various cost of service issues raised in the general rate case, including those associated with load growth. Intial workshops were held on August 24, 2004 and September 24, 2004 on the financial disincentives issue. The next workshop is scheduled for November 8, 2004. The first workshop for the cost of service issue was held on November 3, 2004.

The IPUC disallowed several costs in the Idaho general rate case order, including $12 million annually related to the determination of IPC's income tax expense, $8 million of incentive payments capitalized in prior years and $2 million of capitalized pension expense. On June 15, 2004, IPC filed with the IPUC a petition for reconsideration of these and other items. On July 13, 2004, the IPUC granted this petition in part, agreeing to reconsider the issue relating to the determination of IPC's income tax expense and, in light of the IPUC Staff's computational errors, ordering rates increased by approximately $3 million on or before August 1, 2004. IPC recorded an impairment of assets of $10 million in the second quarter related to the disallowed incentive payments and the disallowed capitalized pension expenses.

On September 28, 2004, the IPUC issued separate orders approving two Settlement Agreements entered into on August 16, 2004 between IPC and the IPUC Staff.

Settlement No. 1, approved by the IPUC in Order No. 29601, relates to the calculation of IPC's taxes for purposes of test year income tax expense. In the Idaho general rate case order, the IPUC adopted the use of a historic five-year average income tax rate to calculate IPC's income tax expense. Settlement No. 1 approved the modification of the general rate case order to utilize IPC's statutory income tax rates to compute test year income tax expense. As a result, IPC will compute and record monthly during the period June 1, 2004 through May 31, 2005 a regulatory asset (with interest accrued at a rate of one percent per annum) of approximately $12 million. Rates will increase on June 1, 2005 to reflect the ongoing impact of the tax expense. Approximately $4 million of this amount was recorded in the third quarter of 2004 as other operating revenue. The remaining balance will be deferred monthly from October 2004 through May 2005 and the total will be included for recovery during IPC's annual Power Cost Adjustment (PCA) process in the spring of 2005. Settlement No. 1 allows IPC to continue its compliance with the normalization provisions of the Internal Revenue Code of 1986, as amended, and associated Treasury Regulations, and will allow IPC to continue to receive the benefits of accelerated depreciation.

Settlement No. 2, approved by the IPUC in Order No. 29600, resolved outstanding issues related to (1) an unplanned outage at one of the two units of the North Valmy Steam Electric Generating Plant in the summer of 2003, (2) a matter relating to the expense adjustment rate for growth component of the PCA and (3) regulatory accounting issues related to a tax accounting method change in 2002. In Settlement No. 2, IPC and the IPUC Staff agreed that the IPUC will not examine the cost of replacement power and a possible PCA adjustment resulting from the Valmy outage, and the expense adjustment rate for growth component of the PCA will continue at its existing value until IPC's next general rate case. In September 2004, as a result of the order, IPC established a regulatory liability of $19 million with a charge to PCA expense. A monthly credit of approximately $804,000 will be included in the PCA from June 2004 through May 2006, which will reduce this regulatory liability. Also in September 2004, IPC reversed a $16 million regulatory tax liability by reducing income tax expense. This regulatory tax liability was established in 2002 when IPC adopted a tax accounting method change for capitalized overhead costs.

The effect on third quarter 2004 earnings from these two agreements was to record an increase in net income of approximately $8 million.

The final result of IPC's general rate case was a $40 million increase to the base Idaho jurisdictional revenue requirement, comprised of $25 million in the initial order, $3 million related to computational errors and $12 million in the order approving Settlement No. 1.

Oregon: On September 21, 2004, IPC filed an application with the Oregon Public Utility Commission (OPUC) to increase general rates an average of 17.5 percent or approximately $4 million annually. On October 19, 2004, the OPUC suspended IPC's request for a period of time not to exceed nine months from October 20, 2004 to investigate the propriety and reasonableness of the request. A pre-hearing conference and public meeting are scheduled for November 18, 2004. IPC is unable to predict what rate relief, if any, the OPUC will grant.

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

		September 30,		December 31,
		2004		2003
Oregon deferral		$	12,484	$	13,620
Idaho PCA current year power supply cost deferrals:
	Deferral for 2004-2005 rate year		-		44,664
	Deferral for 2005-2006 rate year		23,219		-
Idaho PCA true-up awaiting recovery:
	Remaining true-up authorized May 2003		-		13,646
	Remaining true-up authorized May 2004		21,535		-
	Total deferral	$	57,238	$	71,930

Idaho: IPC has a PCA mechanism that provides for annual adjustments to the rates charged to its Idaho retail customers. These adjustments are based on forecasts of net power supply costs (fuel and purchased power less off-system sales) 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 the true-up for the current year's portion and the true-up of the true-up for the prior years' portions, is then included in the calculation of the next year's PCA.

On April 15, 2004, IPC filed its 2004-2005 PCA with the IPUC requesting recovery of $71 million above base rates and a proposed effective date of June 1, 2004 for new PCA rates. On May 25, 2004, the IPUC issued Order No. 29506 approving IPC's filing with additional instructions for IPC and the IPUC Staff to examine the cost of replacement power attributable to the unplanned outage at the Valmy Plant in 2003. Based on the order approving Settlement No. 2, discussed above, the IPUC will not examine the costs related to this outage.

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 were adjusted to collect $81 million above 1993 base rates.

On April 15, 2002, the IPUC issued Order No. 28992 disallowing recovery of $12 million of lost revenues resulting from the Irrigation Load Reduction Program that was in place in 2001. IPC believed that this IPUC order was inconsistent with Order No. 28699, dated May 25, 2001, that allowed recovery of such costs, and IPC filed a Petition for Reconsideration on May 2, 2002. On August 29, 2002, the IPUC issued Order No. 29103 denying the Petition for Reconsideration. As a result of this order, approximately $12 million was expensed in September 2002. IPC believed it was entitled to recover this amount and argued its position before the Idaho Supreme Court on December 5, 2003. On March 30, 2004, the Supreme Court set aside the IPUC denial of the recovery of lost revenues and remanded the matter to the IPUC to determine the amount of lost revenues to be recovered. The IPUC petitioned for reconsideration on April 20, 2004. On May 27, 2004, the IPUC petition was denied and the IPUC is proceeding under Modified Procedure, which allows the case to be handled through written public comments rather than by public hearing. Public comments are due to the IPUC by November 5, 2004. IPC submitted its calculation of lost revenues of $12 million in the earlier IPUC proceeding. If settled, IPC expects to recognize benefits from this case in the fourth quarter of 2004.

Oregon: IPC is also recovering calendar year 2001 excess 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 were recovering approximately $2 million annually. During the 2003 Oregon legislative session, the maximum annual rate of recovery was raised to ten percent under certain circumstances. IPC requested and received authority to increase the surcharge to ten percent. As a result of the increased recovery rate, which became effective on April 9, 2004, IPC will recover approximately $3 million annually.

Following IPC's settlement with the IPUC on issues related to IPC's past relationship with IE, IPC approached the OPUC to settle the issue of the proper amount of fair compensation to Oregon customers related to the terminated Electricity Supply Management Services Agreement between IPC and IE, as well as any other issues relating to transactions between IPC and IE. On October 4, 2004, IPC filed a petition with the OPUC requesting an accounting order approving a settlement stipulation and authorizing IPC to credit its existing deferral balance of excess power supply costs. In the proposed settlement, IPC agrees to continue the $7,700 monthly credit to customers, that began in July 2001, through December 2005, and to reduce the existing excess power supply cost deferral balance by a one time credit of $100,000 on January 1, 2005. The proposed settlement is intended to resolve all outstanding compensation issues arising out of the terminated agreement. The OPUC is currently evaluating the proposed settlement. IPC cannot predict the outcome of this issue.

7. INDUSTRY SEGMENT INFORMATION:

IDACORP has identified three reportable segments: utility operations, energy marketing and IFS.

The utility operations segment has two primary sources of revenue: the regulated operations of IPC and income from Bridger Coal Company, an unconsolidated joint venture also subject to regulation. IPC's regulated operations include the generation, transmission, distribution, purchase and sale of electricity.

The energy marketing segment reflects the results of IE's electricity and natural gas marketing operations. See Note 8 - Restructuring Costs for a discussion on the wind down of energy marketing.

IFS represents that subsidiary's investments in affordable housing developments and historic rehabilitation projects.

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

			Utility		Energy								Consolidated
			Operations		Marketing		IFS		Other		Eliminations		Total
Three months ended
September 30, 2004:
		Revenues	$	241,188	$	(152)	$	1,006	$	4,635	$	-	$	246,677
		Net income (loss)		23,879		1,566		2,679		(2,057)		-		26,067

Total assets at September 30,
	2004		$	2,872,165	$	58,272	$	150,587	$	132,369	$	(87,474)	$	3,125,919

Three months ended
	September 30, 2003:
		Revenues	$	214,861	$	17,193	$	-	$	7,174	$	-	$	239,228
		Net income		15,108		7,350		2,586		21,731		-		46,775

Total assets at December
	31, 2003:		$	2,820,711	$	50,802	$	141,286	$	158,547	$	(69,620)	$	3,101,726

Nine months ended
September 30, 2004:
		Revenues	$	631,701	$	(76)	$	1,006	$	14,107	$	-	$	646,738
		Net income (loss)		51,226		2,145		9,829		(4,483)		-		58,717

Nine months ended
	September 30, 2003:
		Revenues	$	615,911	$	19,733	$	-	$	15,788	$	-	$	651,432
		Net income (loss)		40,588		(7,432)		7,629		2,039		-		42,824

8. RESTRUCTURING COSTS:

IE wound down its power marketing operations, closed its business locations and sold its forward book of electricity trading contracts to Sempra Energy Trading in 2003. As part of the sale of the forward book of electricity trading contracts, IE entered into an Indemnity Agreement with Sempra Energy Trading, 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" and did not have a material effect on IDACORP's financial statements.

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, 2003		$	1,807	$	2,022	$	33	$	3,862
	Amounts reversed		-		-		(33)		(33)
	Amounts paid		(1,531)		(541)		-		(2,072)
Balance at September 30, 2004		$	276	$	1,481	$	-	$	1,757

The remaining involuntary employee termination benefit accrual will be paid out in 2004 and the remaining lease termination accrual will be paid out through 2008. Restructuring accruals are presented as Other Liabilities on IDACORP's Consolidated Balance Sheets.

9. BENEFIT PLANS

The following table shows the components of net periodic benefit cost for the three months ended September 30 (in thousands of dollars):

						Deferred				Other
		Pension Plan				Compensation Plan				Benefits
		2004		2003		2004		2003		2004		2003
Service cost		$	2,950	$	2,550	$	340	$	303	$	354	$	302
Interest cost			5,105		4,878		578		604		1,005		1,004
Expected return on plan assets			(6,978)		(5,876)		-		-		(580)		(482)
Amortization of net obligation
	at transition		(66)		(66)		153		153		516		510
Amortization of prior service
	cost		193		183		(90)		(86)		(133)		(141)
Amortization of net loss			-		90		219		186		377		350
Net periodic benefit cost		$	1,204	$	1,759	$	1,200	$	1,160	$	1,539	$	1,543

The following table shows the components of net periodic benefit cost for the nine months ended September 30 (in thousands of dollars):

						Deferred				Other
		Pension Plan				Compensation Plan				Benefits
		2004		2003		2004		2003		2004		2003
Service cost		$	8,858	$	7,624	$	1,019	$	909	$	1,046	$	829
Interest cost			15,331		14,585		1,734		1,811		2,969		2,758
Expected return on plan assets			(20,956)		(17,569)		-		-		(1,714)		(1,325)
Amortization of net obligation
	at transition		(197)		(197)		460		460		1,524		1,401
Amortization of prior service
	cost		578		546		(271)		(259)		(391)		(387)
Amortization of net loss			-		270		658		558		1,113		963
Net periodic benefit cost		$	3,614	$	5,259	$	3,600	$	3,479	$	4,547	$	4,239

As previously disclosed in their consolidated financial statements for the year ended December 31, 2003, IDACORP and IPC do not expect to contribute to their pension plan in 2004. As of September 30, 2004, no contributions have been made.

FSP FAS 106-1 and FSP FAS 106-2
In January and May 2004, the FASB released FSP FAS 106-1 and FSP FAS 106-2, "Accounting and Disclosure Requirements Related to the Medicare Prescription Drug, Improvement and Modernization Act of 2003."

The Medicare Prescription Drug, Improvement and Modernization Act of 2003 (Medicare Act) was signed into law in December 2003 and establishes a prescription drug benefit, as well as a federal subsidy to sponsors of retiree health care benefit plans that provide a prescription drug benefit that is at least actuarially equivalent to Medicare's prescription drug coverage.

FSP FAS 106-2 provides guidance on accounting for the effects of the Medicare Act for employers that sponsor postretirement health care plans that provide prescription drug benefits and requires those employers to provide certain disclosures regarding the effect of the federal subsidy provided by the Medicare Act. Under FSP FAS 106-1, IDACORP and IPC elected to defer accounting for the effects of the Medicare Act. This deferral remains in effect until the appropriate effective date of FSP FAS 106-2. FSP FAS 106-2 is effective for the first interim or annual period beginning after June 15, 2004. However, for entities that will not recognize a significant impact, delayed recognition of the effects of the Medicare Act until the next regularly scheduled measurement date following the issuance of FSP FAS 106-2 is required.

The measures of accumulated postretirement benefit obligation and net periodic benefit cost do not reflect any amount associated with the subsidy because IDACORP and IPC have not yet determined the extent to which the benefits provided by the plan are actuarially equivalent to Medicare. IDACORP and IPC expect that the effect of the Medicare Act will not be material.

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

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, 2004, and the related consolidated statements of income and of comprehensive income for the three and nine month periods ended September 30, 2004 and 2003 and the consolidated statements of cash flows for the nine month periods ended September 30, 2004 and 2003. These interim financial statements are the responsibility of the Corporation's management.

We conducted our review in accordance with standards of the Public Company Accounting Oversight Board (United States). A review of interim financial information consists principally of applying analytical procedures and making inquiries of persons responsible for financial and accounting matters. It is substantially less in scope than an audit conducted in accordance with standards of the Public Company Accounting Oversight Board (United States), 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 interim 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 standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheet of IDACORP, Inc. and subsidiaries as of December 31, 2003, 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 27, 2004, 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, 2003 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 3, 2004

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Idaho Power Company
Consolidated Statements of Income
(unaudited)

			Three Months Ended
			September 30,
			2004		2003
			(thousands of dollars)
OPERATING REVENUES:
	General business		$	186,687	$	188,247
	Off-system sales			34,969		16,442
	Other revenues			18,563		9,536
		Total operating revenues		240,219		214,225

OPERATING EXPENSES:
	Operation:
		Purchased power		79,607		77,280
		Fuel expense		28,291		25,606
		Power cost adjustment		19,620		(9,787)
		Other		48,147		37,746
	Maintenance			14,336		16,081
	Depreciation			25,229		24,439
	Taxes other than income taxes			4,593		5,164
		Total operating expenses		219,823		176,529

INCOME FROM OPERATIONS				20,396		37,696

OTHER INCOME (EXPENSE):
	Allowance for equity funds used during construction			912		941
	Other income			6,822		3,657
	Other expense			(2,203)		(1,583)
		Total other income (expense)		5,531		3,015

INTEREST CHARGES:
	Interest on long-term debt			12,640		13,385
	Other interest			930		1,103
	Allowance for borrowed funds used during construction			(657)		(865)
		Total interest charges		12,913		13,623

INCOME BEFORE INCOME TAXES				13,014		27,088

INCOME TAX EXPENSE (BENEFIT)				(13,981)		11,133

NET INCOME				26,995		15,955

DIVIDENDS ON PREFERRED STOCK				3,116		847

EARNINGS ON COMMON STOCK			$	23,879	$	15,108

The accompanying notes are an integral part of these statements.

Idaho Power Company
Consolidated Statements of Income
(unaudited)

			Nine Months Ended
			September 30,
			2004		2003
			(thousands of dollars)
OPERATING REVENUES:
	General business		$	491,149	$	529,922
	Off-system sales			99,899		54,889
	Other revenues			38,191		29,670
		Total operating revenues		629,239		614,481

OPERATING EXPENSES:
	Operation:
		Purchased power		162,877		122,904
		Fuel expense		77,364		75,052
		Power cost adjustment		30,438		67,443
		Other		132,687		115,832
	Maintenance			45,459		47,456
	Depreciation			75,459		72,853
	Taxes other than income taxes			15,536		15,572
	Impairment of assets			9,756		-
		Total operating expenses		549,576		517,112

INCOME FROM OPERATIONS				79,663		97,369

OTHER INCOME (EXPENSE):
	Allowance for equity funds used during construction			2,938		2,433
	Other income			17,136		12,936
	Other expense			(6,308)		(5,399)
		Total other income (expense)		13,766		9,970

INTEREST CHARGES:
	Interest on long-term debt			37,173		41,438
	Other interest			2,866		3,690
	Allowance for borrowed funds used during construction			(2,119)		(2,441)
		Total interest charges		37,920		42,687

INCOME BEFORE INCOME TAXES				55,509		64,652

INCOME TAX EXPENSE (BENEFIT)				(540)		21,483

NET INCOME				56,049		43,169

DIVIDENDS ON PREFERRED STOCK				4,823		2,581

EARNINGS ON COMMON STOCK			$	51,226	$	40,588

The accompanying notes are an integral part of these statements.

Idaho Power Company
Consolidated Balance Sheets
(unaudited)

				September 30,		December 31,
				2004		2003
ASSETS				(thousands of dollars)

ELECTRIC PLANT:
	In service (at original cost)			$	3,288,631	$	3,220,228
	Accumulated provision for depreciation				(1,310,332)		(1,239,604)
		In service - Net			1,978,299		1,980,624
	Construction work in progress				150,411		96,086
	Held for future use				2,540		2,438

			Electric plant - Net		2,131,250		2,079,148

INVESTMENTS AND OTHER PROPERTY					52,143		49,739

CURRENT ASSETS:
	Cash and cash equivalents				5,466		4,031
	Receivables:
		Customer			50,553		43,694
		Allowance for uncollectible accounts			(1,750)		(1,466)
		Notes			2,778		3,186
		Employee notes			3,590		3,347
		Related parties			332		1,143
		Other			3,610		4,848
	Accrued unbilled revenues				31,269		30,869
	Materials and supplies (at average cost)				24,763		19,755
	Fuel stock (at average cost)				6,238		6,228
	Prepayments				26,178		26,835
	Regulatory assets				4,949		6,269

			Total current assets		157,976		148,739


DEFERRED DEBITS:
	American Falls and Milner water rights				31,585		31,585
	Company-owned life insurance				36,003		35,624
	Regulatory assets				416,911		427,760
	Employee notes				4,157		4,775
	Other				42,140		43,341

			Total deferred debits		530,796		543,085

	TOTAL			$	2,872,165	$	2,820,711

The accompanying notes are an integral part of these statements.

Idaho Power Company
Consolidated Balance Sheets
(unaudited)

				September 30,		December 31,
				2004		2003
CAPITALIZATION AND LIABILITIES				(thousands of dollars)

CAPITALIZATION:
	Common stock equity:
		Common stock, $2.50 par value (50,000,000 shares
			authorized; 39,150,812 shares outstanding)	$	97,877	$	97,877
		Premium on capital stock			397,788		398,231
		Capital stock expense			(2,097)		(2,686)
		Retained earnings			337,293		320,735
		Accumulated other comprehensive loss			(3,525)		(2,630)

			Total common stock equity		827,336		811,527

	Preferred stock				-		52,366

	Long-term debt				923,857		880,868

			Total capitalization		1,751,193		1,744,761

CURRENT LIABILITIES:
	Long-term debt due within one year				60,000		50,077
	Notes payable				21,600		-
	Accounts payable				51,901		45,529
	Notes and accounts payable to related parties				353		75
	Taxes accrued				48,786		55,383
	Interest accrued				21,388		12,893
	Deferred income taxes				4,319		6,179
	Other				18,986		20,985

			Total current liabilities		227,333		191,121

DEFERRED CREDITS:
	Deferred income taxes				520,627		546,205
	Regulatory liabilities				279,894		258,524
	Other				93,118		80,100

			Total deferred credits		893,639		884,829


COMMITMENTS AND CONTINGENT LIABILITIES

			TOTAL	$	2,872,165	$	2,820,711

The accompanying notes are an integral part of these statements.

Idaho Power Company
Consolidated Statements of Capitalization
(unaudited)

				September 30,				December 31,
				2004		%		2003		%
				(thousands of dollars)
COMMON STOCK EQUITY:
	Common stock			$	97,877			$	97,877
	Premium on capital stock				397,788				398,231
	Capital stock expense				(2,097)				(2,686)
	Retained earnings				337,293				320,735
	Accumulated other comprehensive loss				(3,525)				(2,630)
		Total common stock equity			827,336		47		811,527		47

PREFERRED STOCK:
	4% preferred stock				-				12,366
	7.68% Series, serial preferred stock				-				15,000
	7.07% Series, serial preferred stock				-				25,000
		Total preferred stock			-		0		52,366		3

LONG-TERM DEBT:
	First mortgage bonds:
		8 % Series due 2004			-				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				70,000
		6 % Series due 2032			100,000				100,000
		5.50% Series due 2033			70,000				70,000
		5.50% Series due 2034			50,000				-
		5.875% Series due 2034			55,000				-
			Total first mortgage bonds		785,000				730,000
		Amount due within one year			(60,000)				(50,000)
			Net first mortgage bonds		725,000				680,000

	Pollution control revenue bonds:
		Variable Auction Rate Series 2003 due 2024			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				-				1,105
		Amount due within one year			-				(77)
			Net REA notes		-				1,028

	American Falls bond guarantee				19,885				19,885

	Milner Dam note guarantee				11,700				11,700

	Unamortized premium/discount - net				(3,188)				(2,205)

			Total long-term debt		923,857		53		880,868		50

TOTAL CAPITALIZATION				$	1,751,193		100	$	1,744,761		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,
				2004		2003
				(thousands of dollars)
OPERATING ACTIVITIES:
	Net income			$	56,049	$	43,169
	Adjustments to reconcile net income to net cash provided by
		operating activities:
		Allowance for uncollectible accounts			262		(254)
		Impairment of assets			9,756		-
		Depreciation and amortization			83,455		82,369
		Deferred taxes and investment tax credits			(28,593)		(52,773)
		Accrued power costs adjustment costs			29,100		65,446
		Change in:
			Receivables and prepayments		(3,876)		16,181
			Accrued unbilled revenue		(401)		7,258
			Materials and supplies and fuel stock		258		3,389
			Accounts payable		6,371		(14,367)
			Taxes receivable/accrued		(6,596)		8,473
			Other current liabilities		6,587		2,974
		Other assets			(8,605)		(1,968)
		Other liabilities			9,761		6,062
			Net cash provided by operating activities		153,528		165,959

INVESTING ACTIVITIES:
	Additions to utility plant				(136,660)		(96,956)
	Note receivable advance to parent				-		(415)
	Other assets				783		247
		Net cash used in investing activities			(135,877)		(97,124)

FINANCING ACTIVITIES:
	Issuance of first mortgage bonds				105,000		140,000
	Retirement of first mortgage bonds				(50,000)		(160,000)
	Retirement of preferred stock				(52,220)		(909)
	Retirement of other notes				(1,105)		-
	Dividends on common stock				(34,668)		(53,260)
	Dividends on preferred stock				(4,823)		(2,581)
	Increase in short-term borrowings				21,600		3,500
	Other assets				-		(2,972)
	Other liabilities				-		(59)
		Net cash used in financing activities			(16,216)		(76,281)

Net increase (decrease) in cash and cash equivalents					1,435		(7,446)

Cash and cash equivalents at beginning of period					4,031		12,699

Cash and cash equivalents at end of period				$	5,466	$	5,253

SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION:
	Cash paid during the period for:
		Income taxes paid to parent		$	39,816	$	71,325
		Interest (net of amount capitalized)		$	27,640	$	31,723

The accompanying notes are an integral part of these statements.

Idaho Power Company
Consolidated Statements of Comprehensive Income
(unaudited)

				Three Months Ended
				September 30,
				2004		2003
				(thousands of dollars)

NET INCOME				$	26,995	$	15,955

OTHER COMPREHENSIVE INCOME (LOSS):
	Unrealized gains (losses) on securities:
		Unrealized holding gains (losses) arising during the period,
			net of tax of ($302) and $296		(526)		521
		Reclassification adjustment for gains included
			in net income, net of tax of ($228) and ($111)		(355)		(172)
			Net unrealized gains (losses)		(881)		349

TOTAL COMPREHENSIVE INCOME				$	26,114	$	16,304

				Nine Months Ended
				September 30,
				2004		2003
				(thousands of dollars)

NET INCOME				$	56,049	$	43,169

OTHER COMPREHENSIVE INCOME (LOSS):
	Unrealized gains (losses) on securities:
		Unrealized holding gains (losses) arising during the period,
			net of tax of ($18) and $1,291		(56)		2,189
		Reclassification adjustment for (gains) losses included
			in net income, net of tax of ($609) and $120		(949)		186
			Net unrealized gains (losses)		(1,005)		2,375

TOTAL COMPREHENSIVE INCOME				$	55,044	$	45,544

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
Note 9 - Benefit Plans

1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES:

Stock-Based Compensation
The following table illustrates the effect on IPC's 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,
			2004		2003		2004		2003

Net income, as reported			$	26,995	$	15,955	$	56,049	$	43,169
Add: Stock-based employee compensation
	expense included in reported net income,
	net of related tax effects			34		50		217		104
Deduct: Total stock-based employee
	compensation expense determined under
	fair value based method for all awards, net
	of related tax effects			190		302		733		651
		Pro forma net income	$	26,839	$	15,703	$	55,533	$	42,622

2. INCOME TAXES:

IPC uses an estimated annual effective tax rate for computing its provision for income taxes on an interim basis. The estimated effective tax rate for 2004 was negative 1.0 percent. The 2004 negative estimated tax rate is due primarily to the reversal of a $16 million regulatory tax liability as a result of Settlement No. 2, discussed in Note 6 - Regulatory Matters.

4. FINANCING:

IPC's $49.8 million Humboldt County Pollution Control Revenue bonds are secured by first mortgage bonds, bringing the total first mortgage bonds outstanding at September 30, 2004 to $834.8 million.

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

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 subsidiary as of September 30, 2004, and the related consolidated statements of income and of comprehensive income for the three and nine month periods ended September 30, 2004 and 2003 and the consolidated statements of cash flows for the nine month periods ended September 30, 2004 and 2003. These interim financial statements are the responsibility of the Company's management.

We have previously audited, in accordance with standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheet and statement of capitalization of Idaho Power Company and subsidiary as of December 31, 2003, 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 27, 2004, 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, 2003 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 3, 2004

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 whose principal operating subsidiary is IPC. IDACORP is exempt from registration as a public utility holding company pursuant to Section 3(a)(1) of the Public Utility Holding Company Act of 1935 (1935 Act). In addition, pursuant to Rule 2 of the General Rules and Regulations under the 1935 Act, IDACORP is exempt from all the provisions of the 1935 Act and rules thereunder, except for Section 9(a)(2) of the 1935 Act, which requires IDACORP to seek prior Securities and Exchange Commission approval to acquire securities of another public utility company.

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.

IDACORP's other operating subsidiaries include:

IdaTech - developer of integrated fuel cell systems;

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

IDACOMM - provider of telecommunications services and owner of Velocitus, a commercial and residential Internet service provider;

Ida-West Energy (Ida-West) - operator of independent power projects; and

IDACORP Energy (IE) - marketer of electricity and natural gas.

IE wound down its operations during 2003. Also in 2003, Ida-West discontinued its project development operations and is managing its independent power projects with a reduced workforce. See further discussions in "RESULTS OF OPERATIONS - Energy Marketing" and "OTHER MATTERS - Ida-West" later in the MD&A.

During the third quarter of 2004, IDACORP transferred its ownership of Rocky Mountain Communications Holdings and its subsidiary Velocitus to IDACOMM.

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, 2003 and the Quarterly Reports on Forms 10-Q for the quarters ended March 31, 2004 and June 30, 2004 and should be read in conjunction with the discussions in those reports.

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 IDACORP's or IPC's 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, present or prospective wholesale and retail competition (including but not limited to retail wheeling and transmission costs) and other refund proceedings;

Litigation and regulatory proceedings resulting from the energy situation in the western United States;

Economic, geographic and political factors and risks;

Changes in and compliance with environmental, endangered species and safety laws and policies;

Weather variations affecting hydroelectric generating conditions and customer energy usage;

Construction of power generating facilities including inability to obtain required governmental permits and approvals, and risks related to contracting, construction and start-up;

Operation of power generating facilities including breakdown or failure of equipment, performance below expected levels, competition, fuel supply and transmission;

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, fuel availability and prices;

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

Performance of the stock market and the changing interest rate environment, which affect the amount of required contributions to IDACORP's and IPC's pension plans, as well as the reported costs of providing pension and other postretirement benefits;

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 Investors Service (Moody's), Standard & Poor's Ratings Services (S&P) and Fitch, Inc. (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;

Homeland security, natural disasters, acts of war or terrorism;

Fluctuations in sources and uses of cash;

Impacts from the potential formation of a Regional Transmission Organization (RTO);

Increasing health care costs and the resulting effect on health insurance premiums paid for employees;

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

Technological developments that could affect the operations and prospects of IDACORP's subsidiaries or their competitors;

Over appropriation of surface and groundwater in the Snake River Basin resulting in reduced generation at hydroelectric facilities;

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 important factors that could have a significant impact on the operations and financial results of IDACORP, Inc. and Idaho Power Company and could cause actual results or outcomes to differ materially from those discussed in any forward-looking statements:

Reduced hydroelectric generation can reduce revenues and increase costs. Idaho Power Company has a predominately hydroelectric generating base. Because of Idaho Power Company's heavy reliance on hydroelectric generation, the weather can significantly affect Idaho Power Company's operations. Idaho Power Company is experiencing its fifth consecutive year of below normal water conditions. When hydroelectric generation is reduced, Idaho Power Company must increase its use of more expensive thermal generating resources and purchased power. Through its power cost adjustment in Idaho, Idaho Power Company can expect to recover approximately 90 percent of the increase in its Idaho jurisdictional net power supply costs, which are fuel and purchased power less off-system sales, above the level included in its base rates. The power cost adjustment recovery includes both a forecast and deferrals that are subject to the regulatory process. The non-Idaho power supply costs, which are fuel and purchased power less off-system sales, are subject to periodic recovery from its Oregon and Federal Energy Regulatory Commission jurisdictional customers.

Changes in temperature can reduce power sales and revenues. Warmer than normal winters or cooler than normal summers will reduce retail revenues from power sales.

The Idaho Public Utilities Commission's grant of less rate relief than requested will reduce Idaho Power Company's projected earnings and cash flows. Because the Idaho Public Utilities Commission did not grant the full amount of rate relief requested, Idaho Power Company's projected earnings and cash flows will be reduced and its credit ratings may be downgraded.

A downgrade in IDACORP, Inc. and Idaho Power Company's credit ratings could negatively affect the companies' ability to access capital. During the second quarter of 2004, Moody's Investors Service, Standard & Poor's Ratings Services and Fitch, Inc. placed certain of IDACORP, Inc. and Idaho Power Company's ratings under review for possible downgrade. If the ratings agencies were to downgrade any credit ratings of IDACORP, Inc. or Idaho Power Company, the companies' ability to access the capital markets, including the commercial paper markets, could be hindered. In addition, IDACORP, Inc. and Idaho Power Company would likely be required to pay a higher interest rate on existing variable rate debt and in future financings.

Conditions that may be imposed in connection with hydroelectric license renewals may require large capital expenditures and reduce earnings and cash flows. Idaho Power Company is currently involved in renewing federal licenses for several of its hydroelectric projects. Conditions with respect to environmental, operating and other matters that the Federal Energy Regulatory Commission may impose in connection with the renewal of Idaho Power Company's licenses could have a negative effect on Idaho Power Company's operations, require large capital expenditures and reduce earnings and cash flows.

The cost of complying with environmental regulations can harm cash flows and earnings. IDACORP, Inc. and Idaho Power Company 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. Compliance with these environmental statutes, rules and regulations involves significant capital, operating and other costs, and those costs could be even more significant in the future as a result of changes in legislation and enforcement policies and additional requirements imposed in connection with the relicensing of Idaho Power Company's hydroelectric projects.

Terrorist threats and activities could result in lost revenues and increased costs. IDACORP, Inc. and Idaho Power Company are subject to direct and indirect effects of terrorist threats and activities. Potential targets include generation and transmission facilities. The effects of terrorist threats and activities could prevent Idaho Power Company from purchasing, generating or transmitting power and result in lost revenues and increased costs.

IDACORP, Inc., IDACORP Energy and Idaho Power Company are subject to costs and other effects of legal and regulatory proceedings, settlements, investigations and claims, including those that have arisen out of the western energy situation. IDACORP, Inc., IDACORP Energy and Idaho Power Company 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 Federal Energy Regulatory Commission. Other cases that are the direct or indirect result of the western energy situation include a refund proceeding affecting sellers of wholesale power in the spot market in the Pacific Northwest, in which the Federal Energy Regulatory Commission directed that no refunds be paid, but which is now pending on appeal before the United States Court of Appeals for the Ninth Circuit; efforts by certain public parties to reform or terminate contracts for the purchase of power from IDACORP Energy or claiming violations of state and federal antitrust acts and dysfunctional energy markets as the result of market manipulation; show cause proceedings at the Federal Energy Regulatory Commission, which have been settled but are the subject of motions for rehearing or have been appealed and efforts by the California Attorney General to secure a reversal from the United States Court of Appeals for the Ninth Circuit of Federal Energy Regulatory Commission rulings that market-based sellers' transactional reports satisfy the Federal Energy Regulatory Commission's filed-rate doctrine requirements as a means of expanding refunds from all sellers of wholesale power. To the extent the companies are required to make payments, earnings will be negatively affected. It is possible that additional proceedings related to the western energy situation may be filed in the future against IDACORP, Inc., IDACORP Energy or Idaho Power Company.

Pending shareholder litigation could be costly, time consuming and, if adversely decided, result in substantial liabilities. Two securities shareholder lawsuits consolidated by order dated August 31, 2004 have been filed against IDACORP, Inc. and certain of its officers and directors. Securities litigation can be costly, time-consuming and disruptive to normal business operations. Certain costs below a self-insured retention are not covered by insurance policies. While IDACORP, Inc. cannot predict the outcome of these matters and these matters will take time to resolve, damages arising from these lawsuits if resolved against IDACORP, Inc. or in connection with any settlement, absent insurance coverage or damages in excess of insurance coverage, could have a material adverse effect on the financial position, results of operations or cash flows of IDACORP, Inc.

Litigation relating to stray voltage, if adversely decided, could result in liabilities, reducing earnings, and encourage the commencement of additional lawsuits. In three instances, dairy farmers have brought actions against Idaho Power Company claiming loss of milk production and other damages to livestock due to stray voltage from Idaho Power Company's electrical system. In the first proceeding, the jury ruled in Idaho Power Company's favor. In the second proceeding, a jury verdict was entered in favor of the plaintiffs. A third is in the early stages of discovery. Adverse court rulings in such proceedings could increase the number of future claims. The costs of defending these lawsuits could be significant, and certain costs, such as those below a deductible amount, are not covered by insurance policies.

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. Because the Idaho Public Utilities Commission did not grant the full amount of rate relief Idaho Power Company requested, Idaho Power Company will have to rely more on external financing for its planned utility construction expenditures in the 2004 through 2006 period; these large planned expenditures may weaken the consolidated financial profile of Idaho Power Company and IDACORP, Inc. Additionally, a significant portion of Idaho Power Company'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 Idaho Power Company's systems could potentially increase repair and maintenance expenses, purchased power expenses and capital expenditures.

If IDACORP, Inc. and Idaho Power Company are unable to complete their assessment as to the adequacy of their internal control over financial reporting as required by Section 404 of the Sarbanes-Oxley Act of 2002, or if the companies complete the assessment and identify and report material weaknesses, investors could lose confidence in the reliability of the companies' financial statements, which could decrease the value of IDACORP, Inc.'s common stock. As directed by Section 404 of the Sarbanes-Oxley Act of 2002, the Securities and Exchange Commission has adopted rules requiring public companies to include a report of management on the company's internal control over financial reporting in their annual reports on Form 10-K. This report is required to contain management's assessment of the effectiveness of the company's internal control over financial reporting as of the end of the most recent fiscal year. In addition, the independent registered public accounting firm auditing a public company's financial statements must also attest to and report on management's assessment of the effectiveness of the company's internal control over financial reporting. IDACORP, Inc. and Idaho Power Company have expended significant resources in developing and implementing the testing procedures and documentation required by Section 404. Effective internal controls are necessary for the companies to provide reliable financial reports and to prevent and detect fraud. If the companies fail to have an effectively designed and operating system of internal control over financial reporting, they will be unable to comply with the requirements of Section 404 in a timely manner. The companies' failure to complete their assessment or design internal controls effectively could preclude the independent registered public accounting firm from issuing an unqualified opinion on the effectiveness of the companies' internal controls. This could result in decreased confidence in the reliability of the companies' financial statements, which could cause the market price of IDACORP, Inc.'s common stock to decline.

SUMMARY OF THIRD QUARTER 2004 AND OUTLOOK:

This section presents an overview of what management believes are the most critical issues that IDACORP and IPC are facing and the significant items that affected IDACORP's and IPC's third quarter 2004 operating results.

Financial Results
IDACORP's basic and diluted earnings per share (EPS) for the quarter of $0.68 was a $0.54 per share decline from 2003's third quarter results of $1.22 per share. Last year's third quarter results were unusually high due to the recognition of income tax benefits related to affordable housing tax credits, profit on the sale of the forward book of electricity trading contracts at IE and a contract settlement at IdaTech. IDACORP's 2004 third quarter results include a $0.04 per share contribution from IE due to the settlement of a legal dispute and $0.63 per share from IPC.

IPC's earnings of $0.63 per share for the three months ended September 30, 2004 is a $0.23 per share increase from the third quarter last year. IPC's net power supply costs (fuel and purchased power less off-system sales) decreased $14 million from the prior year mainly due to increased off-system sales. IPC's other operating revenue increased $9 million primarily as a result of recording $4 million related to Settlement No. 1, discussed later, regarding the calculation of IPC's income taxes, and recording $4 million from an agreement with the Bonneville Power Administration (BPA) for the release of water from Brownlee Reservoir. The BPA agreement is included in IPC's Power Cost Adjustment (PCA). PCA expense increased $29 million principally due to Settlement No. 2, discussed later, which calls for IPC to provide a revenue credit to its Idaho customers over a two-year period, commencing with the 2005-2006 PCA year, in the amount of $19 million.

IPC's other operations expenses are $10 million greater than last year mainly due to a $4 million increase in payroll expenses associated with an employee incentive program and a $4 million increase in expenses at some of IPC's thermal plants. Other income at IPC increased $3 million due to improved income from increased coal sales at its joint venture with Bridger Coal Company. IPC's dividends on preferred stock increased $2 million due to premium on the redemption of its preferred stock. IPC's income tax expense decreased $25 million largely due to Settlement No. 2. A regulatory tax liability of $16 million established in 2002 was reversed as part of this settlement, creating a tax benefit for IPC.

IPC's future operating results are largely dependent upon weather conditions, hydroelectric generating conditions and decisions made by regulatory agencies. IDACORP and IPC are going through their annual long-term planning process and will prioritize capital expenditures while considering the effects of the outcome of IPC's general rate case, the need for additional resources in order for IPC to supply power to a growing number of customers and the maintenance of corporate credit ratings. IPC is currently awaiting a decision from the IPUC regarding the irrigation lost revenue case and expects to recognize benefits in the fourth quarter, if this case is settled. If settled, IPC expects to accrue additional incentive pay for 2004.

IPUC Matters
General Rate Case: IPC filed its Idaho general rate case with the IPUC on October 16, 2003. The IPUC approved an increase of $25 million in IPC's electric rates, an average of 5.2 percent, in an order issued on May 25, 2004. The rate increase became effective on June 1, 2004.

The IPUC also disallowed several costs in the order, including $12 million annually related to the determination of IPC's income tax expense, $8 million of incentive payments capitalized in prior years and $2 million of capitalized pension expense. On June 15, 2004, IPC filed with the IPUC a petition for reconsideration of these and other items. On July 13, 2004, the IPUC granted this petition in part, agreeing to reconsider the issue relating to the determination of IPC's income tax expense and, in light of the IPUC Staff's computational errors, ordering rates increased by approximately $3 million on or before August 1, 2004. IPC recorded an impairment of assets of $10 million in the second quarter related to the disallowed incentive payments and the disallowed capitalized pension expenses.

The final result of IPC's Idaho general rate case was a $40 million increase to the base Idaho jurisdictional revenue requirement, comprised of $25 million in the initial order, $3 million related to computational errors and $12 million in the order approving Settlement No. 1 discussed below.

Settlement Agreements: On September 28, 2004, the IPUC issued separate orders approving two Settlement Agreements entered into on August 16, 2004 between IPC and the IPUC Staff. Settlement No. 1 relates to the calculation of IPC's taxes for purposes of test year income tax expense. As a result of Settlement No. 1, IPC will compute and record monthly during the period June 1, 2004 through May 31, 2005 a regulatory asset of approximately $12 million. Approximately $4 million of this amount was recorded in September 2004 as other operating revenue.

Settlement No. 2 resolved outstanding issues related to an unplanned outage of one of the two units of the North Valmy Steam Electric Generating Plant in the summer of 2003, a matter relating to the expense adjustment rate for growth component of the PCA and regulatory accounting issues related to a tax accounting method change in 2002. As a result of Settlement No. 2, IPC established a regulatory liability of $19 million with a charge to PCA expense. Also, IPC reversed a $16 million regulatory tax liability by reducing income tax expense.

The effect on third quarter 2004 earnings from these two agreements was to record an increase in net income of approximately $8 million.

Irrigation Lost Revenues: IPC filed a Petition for Reconsideration with the IPUC in May 2002 regarding the disallowance of $12 million of lost revenues from the Irrigation Load Reduction Program that was in place in 2001. The IPUC denied this petition in August 2002 and IPC argued its position before the Idaho Supreme Court in December 2003. On March 30, 2004, the Idaho Supreme Court set aside the IPUC denial and remanded the matter to the IPUC to determine the amount of lost revenues to be recovered. The IPUC petitioned the Supreme Court for reconsideration on April 20, 2004. The IPUC petition was denied and the IPUC is proceeding under Modified Procedure, which allows the case to be handled through written public comments rather than by public hearing. Public comments are due to the IPUC by November 5, 2004. IPC submitted its calculation of lost revenues of $12 million in the earlier IPUC proceeding. If settled, IPC expects to recognize benefits from this case in the fourth quarter of 2004.

Relicensing
For several years, IPC has been actively pursuing the relicensing of some of its hydroelectric projects. On July 28, 2004, the FERC announced that it had granted new 30-year licenses for each of IPC's five hydroelectric projects on the middle Snake River. IPC received these license orders on August 4, 2004.

The most significant ongoing relicensing effort is the Hells Canyon Complex (HCC), which provides approximately two-thirds of IPC's hydroelectric generating capacity and 40 percent of its total generating capacity. The current license expires in July 2005 and IPC filed the relicensing application in July 2003.

The FERC received a number of additional study requests (ASRs) from intervenors in the HCC relicensing process and on May 4, 2004 issued additional information requests (AIRs) to IPC. On June 8, 2004, IPC filed a letter with the FERC objecting to certain of the AIRs and also requesting clarification, modification or extensions of time as to others. On June 29, 2004, the FERC Staff denied IPC's objections to the AIRs but did grant extensions of time and provided clarification for certain AIRs. On July 29, 2004, IPC filed a petition for rehearing with the FERC contesting the FERC Staff's decision denying IPC's objections to the AIRs.

In connection with the relicensing of the HCC, IPC is also engaged with the FERC and relevant federal and state agencies on the effects, if any, of the relicensing of the project on species listed as threatened or endangered under the Endangered Species Act (ESA). The parties have held discussions related to a Hells Canyon ESA Consultation/Settlement Process.

Hydroelectric Generation and Power Supply Costs
IPC relies on low-cost hydroelectric generation for a significant portion of its power supply. Because below normal hydroelectric generating conditions are continuing for the fifth consecutive year, IPC has increased its reliance on higher-cost thermal generation and purchased power. IPC expects power supply costs will remain high as long as below normal water conditions persist.

Capital Requirements
IDACORP expects internal cash generation after dividends will provide less than the full amount of total capital requirements for 2004 through 2006. Current forecasts indicate total utility construction expenditures to be $643 million, excluding Allowance for Funds Used During Construction (AFDC), for 2004 through 2006. IDACORP and IPC are going through the annual long-term planning process and will prioritize capital expenditures while considering the effects of the outcome of IPC's Idaho general rate case, the need for additional resources in order for IPC to supply power to a growing number of customers and the maintenance of corporate credit ratings. IDACORP and IPC expect to continue financing the utility construction program and other capital requirements with internally generated funds and with increased reliance on externally financed capital.

In connection with IPC's 2002 Integrated Resource Plan (IRP) and the identification of the need for additional resources, the 162-megawatt (MW) gas-fired Bennett Mountain Power Plant is currently under construction. As of September 30, 2004, $34 million of construction costs were included in Construction Work in Progress. Total project costs are expected to be $61 million.

IPC filed its 2004 IRP with the IPUC and the OPUC in August 2004. The 2004 IRP includes several elements that may require significant capital expenditures in the future. IPC plans to begin issuing requests for proposals (RFPs) related to the 2004 IRP later in 2004.

Legal Issues and Regulatory Matters
Vierstra Dairy: In February 2004, Vierstra Dairy was awarded approximately $17 million in damages for the alleged effect of electrical current on the health of Vierstra's dairy cows. During September 2004, a settlement of the matter was reached among IPC, IPC's insurance carrier and the plaintiffs. The settlement, less a deductible, was covered by insurance and did not have a material effect on IPC's consolidated financial position, results of operations or cash flows.

Western Energy Proceedings: IE and IPC are involved in a number of FERC proceedings in connection with the western energy situation and claims that dysfunctions in the organized California markets contributed to or caused unjust and unreasonable prices in Pacific Northwest spot markets, and may have been the result of manipulations of gas or electric power markets. They include proceedings involving (1) the chargeback provisions of the California Power Exchange (CalPX) participation agreement triggered by a certain participant's default on payments to the CalPX; (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; (3) the Pacific Northwest refund proceedings where it was alleged that the spot market in the Pacific Northwest was affected by the dysfunction in the California market and (4) two cases that result from a ruling of the United States Court of Appeals for the Ninth Circuit requiring the FERC to permit the California parties in the California refund proceeding to submit materials to the FERC demonstrating market manipulation by various sellers of electricity into California.

Strategy
IDACORP continues to focus on a strategy called "Electricity Plus," a back-to-basics strategy that emphasizes IPC as IDACORP's core business. IPC continues to experience strong customer growth in its service area and this revised corporate strategy recognizes that IPC must make substantial investments in infrastructure to ensure adequate supply and reliable service. The "Plus" recognizes that through modest investments in IdaTech and IDACOMM, IDACORP can preserve the potential for additional growth in shareowner value. IFS, with its affordable housing and historic rehabilitation portfolio, remains a key component of the revised corporate strategy.

Inflation
IDACORP and IPC believe that inflation has caused and will continue to cause increases in certain operating expenses and has required and will continue to require assets to be replaced at higher costs. Inflation affects the cost of labor, products and services required for operations, maintenance and capital improvements. While inflation has not had a significant impact on IDACORP's or IPC's operations, costs for products and services are subject to fluctuations. IPC is subject to rate-of-return regulation and the impact of inflation on the level of cost recovery under regulation. Increases in other utility costs and expenses not otherwise offset by increases in revenues or reductions in other expenses could have an adverse effect on earnings due to the time lag associated with obtaining regulatory approval to recover such increased costs and expenses.

CRITICAL ACCOUNTING POLICIES:

IDACORP's and IPC's discussion and analysis of their financial condition and results of operations are based upon their consolidated financial statements, which have been prepared in accordance with accounting principles generally accepted in the United States of America (GAAP). The preparation of these financial statements requires IDACORP and IPC to make estimates and judgments that affect the reported amounts of assets, liabilities, revenues and expenses and related disclosure of contingent assets and liabilities. On an ongoing basis, IDACORP and IPC evaluate these estimates, including those related to rate regulation, benefit costs, contingencies, litigation, impairment of assets, income taxes, restructuring costs and bad debt. 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, 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, 2003 and have not changed materially from that discussion.

RESULTS OF OPERATIONS:

This section of the MD&A takes a closer look at the significant factors that affected IDACORP's and IPC's earnings during the three and nine months ended September 30, 2004 and 2003. In this analysis, the results for 2004 are compared to 2003. The analysis is organized by IDACORP's reportable segments, which are Utility Operations, Energy Marketing and IFS. The following table presents EPS for each reportable segment as well as for the holding company and its other subsidiaries combined for the three and nine months ended September 30:

EPS of common stock	Three months ended				Nine months ended
	September 30,				September 30,
	2004		2003		2004		2003
Utility operations	$	0.63	$	0.40	$	1.34	$	1.06
Energy marketing		0.04		0.19		0.06		(0.19)
IFS		0.07		0.07		0.26		0.20
Other		(0.06)		0.56		(0.12)		0.05
Total EPS	$	0.68	$	1.22	$	1.54	$	1.12

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.

Generation: IPC relies on its hydroelectric plants for a significant portion of its power supply. The availability of hydroelectric generation can significantly affect the amount IPC incurs for net power supply costs (fuel and purchased power less off-system sales). Most, but not all, of the power supply costs are recovered through the rates charged to customers. Generally, lower hydroelectric generation increases power supply costs, thereby increasing the amount of these costs that IPC must absorb.

IPC's system is dual peaking, with the larger peak demand generally occurring in the summer. IPC's record system peak of 2,963 MW occurred on July 12, 2002. Peak demand so far in 2004 was 2,843 MW on June 24, 2004. IPC was able to meet system load requirements and off-system sales requirements and had sufficient system reserves in place. IPC's 2004 IRP reports that customers' use of electricity continues to grow during the summer months. IPC projects that summer peaks could grow by an average of 2.5 percent per year over the ten-year IRP planning period.

On June 23, 2004, two downed transmission lines in the Hells Canyon area caused IPC to shed 157 MW of electrical load and declare a Stage Three Power Emergency. The Stage Three Emergency lasted approximately 90 minutes and IPC employed all of its available generation resources during this time and purchased power from the wholesale markets. IPC shed 100 MW for the entire 90 minutes and an additional 57 MW for 30 of the 90 minutes. This occurrence did not have a significant impact on IPC's financial results.

The following table presents IPC's system generation for the three and nine months ended September 30:

		Three months ended September 30,				Nine months ended September 30,
				% of Total				% of Total
		MWh		Generation		MWh		Generation
		2004	2003	2004	2003	2004	2003	2004	2003
Hydroelectric		1,407	1,430	42%	47%	4,777	4,954	47%	50%
Thermal		1,950	1,635	58%	53%	5,359	4,946	53%	50%
	Total system generation	3,357	3,065	100%	100%	10,136	9,900	100%	100%

Streamflow conditions have remained below average in 2004. July through September inflow into Brownlee Reservoir was 74 percent of average while the January through September inflow was 57 percent of average, making this the fifth consecutive year of below average inflow. Precipitation in the Snake River basin was above normal in July, but below normal in August and September. Carryover storage in reservoirs upstream of Brownlee Reservoir was 47 percent of average at the end of September.

The continuing below average hydrologic conditions are expected to reduce IPC's hydroelectric generation and require it to use wholesale purchases from the energy markets and higher-cost thermal generation, when necessary, to meet its energy needs through 2004. Generation from IPC's hydroelectric facilities is currently expected to be 6.2 million MWh in 2004, which matches 2003 generation but is less than normal generation of 9.3 million MWh and IPC's earlier projection of 6.4 million MWh.

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
		2004		2003		2004	2003	2004		2003		2004	2003
Residential		$	67,869	$	63,903	1,067	1,113	$	199,878	$	208,142	3,325	3,250
Commercial			45,293		43,099	932	968		124,128		133,958	2,655	2,632
Industrial			29,212		28,841	860	849		84,275		100,761	2,475	2,377
Irrigation			44,313		52,404	917	1,044		82,868		87,061	1,682	1,720
	Total	$	186,687	$	188,247	3,776	3,974	$	491,149	$	529,922	10,137	9,979

Rates: New base rates in effect for all of the current quarter caused a $9 million increase in general business revenue over the same quarter last year. Year-to-date general business revenue decreased $38 million mainly due to decreased average rates resulting from the 2002-2003 and 2003-2004 PCAs. The general rate case and the PCA are discussed in more detail below in "REGULATORY ISSUES - General Rate Case" and "REGULATORY ISSUES - Deferred Power Supply Costs";

Usage: Revenues decreased approximately $17 million and $13 million for the three and nine months ended September 30, 2004 due in large part to cooler weather in the third quarter of 2004. Cooling degree-days during this time were 21 percent less than the unusually hot third quarter of 2003. Cooling degree-days are a common measure used in the utility industry to analyze the demand for electricity and indicate when a customer would use electricity for air conditioning;

Contract Expiration: The expiration in March 2003 of a take-or-pay contract with FMC/Astaris caused a $9 million decrease in revenues for the nine months ended September 30, 2004. FMC/Astaris, formerly IPC's largest volume customer, closed its plants late in 2001 but was required under the contract to pay IPC for generation capacity regardless of delivery; and

Customers: An increase in general business customers improved revenue $7 million and $21 million for the three and nine months ended September 30, 2004. IPC is experiencing strong customer growth in its service territory, adding more than 13,000 general business customers in the last 12 months. IPC anticipates adding approximately 10,000 customers each year for the next three years.

Off-system sales: Off-system sales consist primarily of long-term sales contracts and opportunity sales of surplus system energy. The following table presents IPC's off-system sales for the three and nine months ended September 30:

	Three months ended				Nine months ended
	September 30,				September 30,
	2004			2003		2004	2003

Revenue	$	34,969	$	16,442	$	99,899	$	54,889
MWh sold		791		411		2,439		1,393
Revenue per MWh	$	44.23	$	40.02	$	40.95	$	39.41

Quarterly and year-to-date revenues from off-system sales increased significantly from last year's results due to 92 percent and 75 percent increases in energy sales volumes, respectively, and 11 percent and four percent increases in average price per MWh sold, respectively. Overall thermal plant performance and output was better than last year's third quarter, contributing to the increased volumes sold. Increased year-to-date sales volumes are mainly a result of power supply hedge activity in late spring based on temporarily improved hydroelectric generation. Although overall hydroelectric generating conditions continue to be below normal, May 2004 precipitation was above normal and reservoir storage space was limited. Consequently, IPC generated more hydroelectric power than previously planned for May and June 2004. Earlier hedge purchase activity combined with increased hydroelectric generation resulted in surplus energy.

Other revenues: IPC recognized approximately $4 million of revenue due to the IPUC order approving Settlement No. 1, which relates to the calculation of IPC's taxes for purposes of test year income tax expense in the Idaho general rate case. As a result of this settlement, IPC is recording monthly for the period June 1, 2004 through May 31, 2005, a regulatory asset of approximately $12 million. IPC will begin collecting this amount beginning in June 2005 with an adjustment to rates. In July 2004, IPC recognized $4 million of revenue from an agreement with BPA for the release of 100,000 acre-feet of storage water from Brownlee Reservoir. This amount has been included in the PCA and will result in a benefit to IPC's Idaho customers in the next PCA year.

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,
		2004		2003		2004		2003
Purchased power:
	Purchases	$	79,607	$	77,280	$	162,877	$	119,775
	Load reduction costs		-		-		-		3,129

MWh purchased			1,677		1,716		3,625		2,730
Cost per MWh purchased		$	47.47	$	45.03	$	44.93	$	43.87

Purchased power expense was slightly higher for the quarter due to a five percent increase in average price per MWh purchased offset by a two percent decrease in energy volumes purchased. The year-to-date increase is mostly due to a 33 percent increase in volumes purchased. The increased volumes purchased are a result of power supply hedge activity in early spring based on expectations of reduced hydroelectric generation due to continued below normal water conditions. Load reduction costs decreased from $3 million to zero due to the expiration of the take-or-pay contract with FMC/Astaris in March 2003.

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,
	2004			2003		2004	2003

Fuel expense	$	28,291	$	25,606	$	77,364	$	75,052
Thermal MWh generated		1,950		1,635		5,359		4,946
Cost per MWh	$	14.50	$	15.66	$	14.44	$	15.17

PCA: PCA expense represents the effect of IPC's PCA regulatory mechanism, which is discussed in more detail below in "REGULATORY ISSUES - Deferred Power Supply Costs." In 2004 and 2003, net power supply costs (fuel and purchased power less off-system sales) exceeded those anticipated in the annual PCA forecast, resulting in the deferral of a portion of those costs to subsequent years when they are to be recovered in rates. As the revenues are being recovered, the deferred balances are amortized.

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

		Three months ended				Nine months ended
		September 30,				September 30,
		2004			2003		2004	2003
Current year power supply cost deferral		$	(13,782)	$	(31,581)	$	(27,197)	$	(34,744)
FMC/Astaris and irrigation program cost deferral			-		-		-		(2,245)
Amortization of prior year authorized balances			14,102		21,794		38,335		104,384
Write-off of disallowed costs			-		-		-		48
Settlement agreement			19,300		-		19,300		-
	Total power cost adjustment	$	19,620	$	(9,787)	$	30,438	$	67,443

PCA expense increased $29 million over third quarter last year principally due to the IPUC order approving Settlement No. 2, which resulted in IPC recording a regulatory liability of $19 million with a charge to PCA expense. This $19 million will be credited to IPC's Idaho customers over a two-year period commencing with the 2005-2006 PCA year. Also, current year deferred power supply costs (fuel and purchased power less off-system sales) are $18 million less than last year mainly due to increased off-system sales and the BPA agreement. These two PCA items are partially offset by an $8 million decrease in amortization of prior year deferred costs. In 2003, high power supply costs incurred during the western energy situation of 2002 were being amortized.

Year-to-date PCA expense decreased $37 million as a result of reduced amortization of prior year deferred costs of $66 million, partially offset by the $19 million regulatory liability discussed above, an $8 million decrease in the amount of current year power supply costs deferred and the end of the FMC/Astaris and irrigation program cost deferral, which was $2 million in 2003. Amortization in 2003 related mainly to deferred power supply costs incurred during the western energy situation of 2002.

Impairment of assets: In the second quarter of 2004, IPC recorded $10 million of asset impairments relating to disallowed items in the Idaho general rate case. The IPUC disallowed several items in the rate case, including $8 million of incentive payments capitalized in prior years and $2 million of capitalized pension expense. On June 15, 2004, IPC filed with the IPUC a petition for reconsideration of these and other items. On July 13, 2004, the IPUC issued an order denying reconsideration of the capitalized incentive payments and the capitalized pension expense, resulting in the impairments.

Other operations expense: Other operations expense increased $10 million for the quarter mainly due to a $4 million increase in payroll expenses associated with an employee incentive program and a $4 million increase in operations expenses at some of IPC's thermal plants. In 2003, some of these plants experienced outages during the third quarter and were not fully operational. The year-to-date increase of $17 million is primarily related to a $4 million increase in transmission expense, the incentive program and a $5 million rise in operations expense at IPC's thermal and hydroelectric plants.

Dividends on preferred stock: On September 20, 2004, IPC redeemed all of its outstanding preferred stock. Included in the redemption was a premium of $2 million.

Income tax benefit: Income tax expense for the three and nine months ended September 30, 2004 decreased $25 million and $22 million largely due to the IPUC order approving Settlement No. 2. As a result of the IPUC order approving this settlement, a regulatory tax liability of $16 million established in 2002 was reversed, creating a tax benefit for IPC.

Energy Marketing
IE wound down its power marketing operations, closed its business locations and sold its forward book of electricity trading contracts to Sempra Energy Trading in 2003. As part of the sale of the forward book of electricity trading contracts, IE entered into an Indemnity Agreement with Sempra Energy Trading, 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 Financial Accounting Standards Board Interpretation (FIN) 45, "Guarantor's Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others" and did not have a material effect on IDACORP's financial statements.

At December 31, 2003, IE had accrued $2 million of involuntary employee termination benefit expenses and $2 million of lease termination and other exit-related costs. In the third quarter of 2004, IE paid $0.4 million of involuntary employee termination benefits and $0.1 million of lease termination and other exit-related costs. The remaining employee termination benefit accrual will be paid out in 2004 and the remaining lease termination accrual will be paid out through 2008. Restructuring accruals are presented as Other liabilities on IDACORP's Consolidated Balance Sheets.

Quarterly net income from Energy Marketing decreased $6 million from the third quarter of 2003. In the third quarter of 2003, IE had operating revenues of $17 million, offset by $6 million of operating expenses, mainly related to termination benefits associated with the sale of the forward book of electricity trading contracts, and $4 million of income tax expense. During this year's third quarter, IE recorded an approximate $3 million gain on the settlement of a legal dispute offset by $1 million of income tax expense related to the gain.

Year-to-date net income from IE increased $10 million from a net loss of $7 million in 2003. Operating revenue decreased $20 million and general and administrative expenses decreased $20 million as a result of the wind down of IE's operations. In 2003, IE incurred a net $11 million loss on the settlement of legal disputes with Truckee-Donner Public Utility District, Overton Power District No. 5 and Enron compared to approximately $5 million of gains from the settlements of legal disputes this year. IE's income tax expense increased $7 million due to moving from a negative tax expense associated with 2003's loss to positive income tax in the current year.

IFS
IFS contributed $0.07 per share for the quarter, principally from the generation of federal income tax credits and tax depreciation benefits. IFS's year-to-date results include a gain on the sale of its investment in the El Cortez Hotel in San Diego, California. In June 2000, IFS invested $4 million to assist in the renovation of the historic El Cortez into upscale apartment units. Upon exiting the investment on April 22, 2004, IFS recognized a gain on sale of $5 million, income taxes of $3 million and a net gain of $2 million. The gain is included in Other Income on IDACORP's Consolidated Statements of Income.

IFS generates federal income tax credits and accelerated tax depreciation benefits related to its investments in affordable housing and historic rehabilitation developments. Generation of IFS tax credits was approximately the same for 2004 and 2003, $5 million and $15 million for the three and nine months ended both September 30, 2004 and 2003. IFS is expected to continue generating tax benefits near current levels.

INCOME TAXES:

IDACORP's effective tax rate was negative 50.0 percent for the nine months ended September 30, 2004, compared to an effective tax rate of negative 41.2 percent for the same period last year. The current year negative tax rate is due primarily to tax credits from IFS, which totaled approximately $15 million in the first nine months of 2004, and to the reversal of a $16 million regulatory tax liability in the third quarter. In 2003, $15 million in tax credits from IFS during the first nine months, along with the favorable resolution of prior year tax audits, resulted in the negative estimated annual rate.

Federal Legislation
On October 22, 2004, the President signed into law the American Jobs Creation Act of 2004, which enacted a series of business-based income tax provisions. IDACORP and IPC are in the process of evaluating the act's provisions as they relate to their operations.

LIQUIDITY AND CAPITAL RESOURCES:

Operating Cash Flows
IDACORP's operating cash flows for the nine months ended September 30, 2004 were $157 million compared to $257 million for the nine months ended September 30, 2003. The decrease is a result of a $54 million decrease in receipts from IPC's general business customers and a $40 million decrease as a result of the 2003 sale of IE's forward book of electricity trading contracts.

IPC's operating cash flows for the nine months ended September 30, 2004 were $154 million compared to $166 million for the nine months ended September 30, 2003. The decrease is a result of reduced receipts from general business customers of $54 million, which was partially offset by a $32 million decrease in income taxes paid to IDACORP during the period.

For the year ending December 31, 2004, net cash provided by operating activities will be driven by IPC where general business revenues and the costs to supply power to general business customers have the greatest impact on operating cash flows. The costs to supply IPC's customers are expected to be greater than originally planned in 2004 as a result of the fifth consecutive year of below normal water conditions. While a significant portion of the deferred power supply costs is expected to be recovered through IPC's PCA mechanism, recovery will not take place until the 2005-2006 PCA year. The revenues received from IPC's general business customers are expected to be less than the amounts initially forecast due to the IPUC granting less than the requested rate relief in the 2003 Idaho general rate case. Additionally, IPC's 2004-2005 PCA is $10 million less than the 2003-2004 PCA. As a result of these items, IDACORP and IPC expect to incur more short-term debt during 2004 than previously anticipated.

Working Capital
The changes in working capital are due primarily to timing and normal business activity.

Insurance Expenses
IPC forecasts that its 2005 medical, property and liability insurance costs will increase to approximately $17 million, $2 million above 2004 forecasted and 2003 actual amounts. Rising health care costs are the principal contributor to this increase.

Pension Expense and Contributions
Based on current market trends, the discount rate used to calculate 2005 pension expense is currently projected to be 5.75 percent, a decrease from the 6.15 percent used in 2004. Along with lower than expected returns on plan assets so far in 2004, the decrease in discount rate is expected to increase 2005 pension plan expenses for IPC's qualified retirement plan to $9 million, a $4 million increase over 2004. This projection does not factor in changes to any other assumptions, or any of the underlying data used to develop the 2004 expense. A 0.25 percent increase/decrease in the discount rate used would reduce/increase the projected expense by approximately $1.5 million. Contributions to this plan are still expected to be zero in 2004 and 2005.

Dividend Reduction
In September 2003, IDACORP's annual dividend was reduced to $1.20 per share from $1.86 per share. This action was taken in order to strengthen IDACORP's financial position and its ability to fund IPC's growing capital expenditure needs. IPC's construction program is discussed below in "Capital Requirements." The dividend reduction was also made to improve cash flows and help maintain credit ratings. During the nine months ended September 30, 2004, IDACORP paid dividends on common stock of $34 million compared to $53 million during the same period in 2003.

Contractual Obligations
IDACORP's contractual cash obligations have increased from $2.0 billion at December 31, 2003 to $2.1 billion at September 30, 2004. This change is primarily due to an increase in IPC's contractual cash obligations, which increased from $1.9 billion at December 31, 2003 to $2.1 billion at September 30, 2004. The most significant changes for IPC include long-term debt, which increased from $931 million to $987 million, cogeneration and small power production obligations, which increased from $635 million to $707 million, fuel supply agreements, which decreased from $128 million to $105 million, purchased power and transmission, which increased from $40 million to $67 million, maintenance and service agreements, which increased from $49 million to $88 million, and other purchase obligations, which decreased from $110 million to $91 million.

Off-Balance Sheet Arrangements
The federal Surface Mining Control and Reclamation Act of 1977 and similar state statutes establish operational, reclamation and closure standards that must be met during and upon completion of mining activities. These obligations mandate that mine property be restored consistent with specific standards and the approved reclamation plan. The mining operations at the Bridger Coal Company are subject to these reclamation and closure requirements.

IPC has guaranteed the performance of coal mine reclamation activities of its Bridger Coal Company joint venture. This guarantee, which is renewed each December, was $60 million at September 30, 2004. Bridger Coal has a reclamation trust fund set aside specifically for the purpose of paying these reclamation costs and expects that the fund will be sufficient to cover all such costs. Because of the existence of the fund, the estimated fair value as well as the impact on the consolidated financial statements of this guarantee was minimal.

In August 2003, IE sold its forward book of electricity trading contracts to Sempra Energy Trading. As part of the sale of the forward book of electricity trading contracts IE entered into an Indemnity Agreement with Sempra Energy Trading, guaranteeing the performance of one of the counterparties. The maximum amount payable by IE under the Indemnity Agreement is $20 million. The impact of this guarantee on the consolidated financial statements was minimal.

Credit Ratings
In June 2004, Moody's, S&P and Fitch placed certain of IDACORP's and IPC's ratings under review for possible downgrade. Any downgrade would be expected to increase the cost of new debt and other issued securities going forward.

Moody's: On June 8, 2004, Moody's placed the long-term ratings of IDACORP and the long-term and short-term ratings of IPC under review for possible downgrade. IDACORP's commercial paper rating was affirmed at P-2.

Moody's stated that its review of the ratings reflected concerns about (1) the lower than expected rate increase granted in IPC's general rate case, (2) potentially higher external funding for IPC's estimated capital expenditures of $643 million over the next three years and (3) the fifth year of drought conditions and resulting higher costs of power supply.

S&P: On June 2, 2004, S&P assigned new business profile scores and revised the financial guidelines for U.S. utility and power companies. As a result, S&P changed IDACORP and IPC's business risk profile to a 5 from a 4 on a 10-point scale, where 1 is the least risky. The new business scores and financial guidelines did not represent a change in S&P's ratings criteria or methodology, and IDACORP and IPC's ratings remained unchanged.

On June 15, 2004, S&P announced that it had placed the corporate credit rating and long-term ratings of IDACORP and IPC on CreditWatch with negative implications. IDACORP's and IPC's commercial paper rating was affirmed at A-2.

S&P stated that its decision was prompted by the IPUC order issued May 25, 2004 authorizing only a $25 million (5.2 percent) increase in base rates. In S&P's view, the IPUC order gave rise to the following credit issues: (1) the order likely reflects pressure on the IPUC to moderate rate increases given the rate hikes of the past few years and the regional economic conditions, (2) IPC will have to rely more on external debt funding for its approximately $640 million in planned capital expenditures in the 2004-06 period, (3) the drought in the region continues for the fifth consecutive year, raising costs for customers, (4) income tax issues related to the order could potentially lead to issues with deferred federal taxes because of violation of accelerated depreciation rules since the IPUC ordered the benefit of tax refunds to go to ratepayers and (5) the order, coupled with large planned capital expenditures, will weaken IDACORP's consolidated financial profile, with forecast funds from operations coverage of debt below 20 percent and total debt to capitalization at about 55 percent or higher.

S&P stated that it would resolve its CreditWatch listing following the final resolution of the IPUC's response to IPC's petition for reconsideration of this ruling and that IDACORP would also have the opportunity to put in place cost reduction or make other changes to its financial plan to mitigate the impact of the ruling.

Fitch: On June 22, 2004, Fitch announced that it had placed the corporate credit ratings and long-term ratings of IDACORP and IPC on Rating Watch Negative. IDACORP's commercial paper rating was affirmed at F-2.

Fitch stated that the Rating Watch Negative status related to the adverse effect of the IPUC's general rate case order. Fitch indicated that additional items of concern were the fifth consecutive year of drought and its effects on the expenses associated with lower amounts of water for generation, the duration of the drought and its negative effect on IPC 's financial trends, particularly IPC's debt burden over the last five years.

Fitch stated that in resolving IPC's Rating Watch Negative status, it will also consider whether the IPUC order signals a deteriorating Idaho regulatory environment, at a time when IPC faces meaningful capital spending increases to maintain reliability and service quality, and the regional drought. The review will also consider IDACORP's improved business risk profile given its exit from the energy marketing and trading operation and wind-down of Ida-West.

Summary: The following chart outlines the current S&P, Moody's and Fitch ratings of IDACORP's and IPC's securities, with the ratings currently under review marked with an asterisk:

		S&P		Moody's		Fitch
		IPC	IDACORP	IPC	IDACORP	IPC	IDACORP
Corporate Credit Rating		A-*	A-*	A3*	Baa1*	None	None
Senior Secured Debt		A*	None	A2*	None	A*	None
Senior Unsecured Debt		BBB+*	BBB+*	A3*	Baa1*	A-*	BBB+*
Preferred Stock		BBB*	None	Baa2*	None	BBB+*	None
Trust Preferred Stock		None	BBB*	None	Baa2*	None	BBB*
Short-Term Tax-Exempt		BBB+/	None	A3/	None	None	None
	Debt	A-2		VMIG-1*
Commercial Paper		A-2	A-2	P-1*	P-2	F-1*	F-2
Rating Outlook		Negative	Negative	Negative	Negative	Negative	Negative

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.

Capital Requirements
IDACORP's forecasts indicate that internal cash generation after dividends is expected to provide less than the full amount of total capital requirements for 2004 through 2006. IDACORP's internal cash generation is dependent primarily on the contribution of IPC's cash flows from operations, which are subject to risks and uncertainties relating to weather and water conditions and the results of regulatory processes. IPC is in its fifth consecutive year of below normal water conditions and must rely more on higher-cost thermal generation and purchased power during these conditions.

IDACORP's internally generated cash after dividends is expected to provide 51 percent of 2004 capital requirements, where capital requirements are defined as utility construction expenditures, excluding AFDC, plus other regulated and non-regulated investments. This excludes mandatory or optional principal payments on debt obligations. IPC's construction expenditures represent over 85 percent of these capital requirements.

The current expectation of 51 percent of 2004 capital requirements is a decline from the 61 percent anticipated earlier in the year. Most of the decline is due to increased reliance on higher-cost thermal generation and purchased power as a result of the ongoing below normal water conditions, changes in working capital and tax payment timing differences. An additional component of the decline is the result of the IPUC not granting the full amount of rate relief requested by IPC. IDACORP and IPC expect to continue financing the utility construction program and other capital requirements with internally generated funds and with increased reliance on externally financed capital.

Utility Construction Program: Utility construction expenditures were $137 million for the nine months ended September 30, 2004 compared to $97 million for the nine months ended September 30, 2003. The increase is primarily related to construction of the Bennett Mountain Power Plant.

IPC's total construction expenditures are expected to be $643 million, excluding AFDC, from 2004 through 2006. IPC expects to spend approximately $207 million, excluding AFDC, in 2004 and a total of approximately $436 million, excluding AFDC, for 2005 and 2006 combined. With reduced rate relief from what IPC originally anticipated, one area under review is the utility construction program. Given current requirements, significant reductions in this program are not anticipated in 2004.

Aging facilities, relicensing costs and projected load growth may increase construction expenditures. IPC's coal-fired plants are approaching their fourth decade of service and plant utilization has increased due to both load growth and reduced hydroelectric generation resulting from below normal water conditions. These factors result in increased upgrade and replacement requirements and plant additions such as the new Bennett Mountain Power Plant.

IPC's 2002 IRP identified the need for additional resources to address potential electricity shortfalls within IPC's utility service territory by mid-2005. The Bennett Mountain Power Plant, a 162-MW gas-fired generating plant, is currently under construction and will be used to overcome the majority of the potential shortfalls. The estimated project cost includes plant construction of $54 million and associated transmission system upgrades of $7 million. At September 30, 2004, $34 million of construction costs were included in Construction Work in Progress.

In January 2004, the IPUC approved IPC's application for a Certificate of Public Convenience and Necessity, which will allow IPC to place reasonable and prudent capital costs of the Bennett Mountain Power Plant into its Idaho base rates when the plant is operational. The plant is scheduled to be online by the summer of 2005 and will be used primarily to meet peak electrical needs during high-use summer and winter months. The IPUC's order allows IPC to reasonably expect to recover up to $54 million from rates after the plant is completed.

Based upon present environmental laws and regulations, IPC estimates its 2004 capital expenditures for environmental matters, excluding AFDC, will total $10 million. Studies and measures related to environmental concerns at IPC's hydroelectric facilities account for $8 million and investments in environmental equipment and facilities at the thermal plants account for $2 million. From 2005 through 2006, environmental-related capital expenditures, excluding AFDC, are estimated to be $49 million. Anticipated expenses related to IPC's hydroelectric facilities account for $38 million and thermal plant expenses are expected to total $11 million. As of September 30, 2004, environmental-related capital expenditures, excluding AFDC, for IPC's hydroelectric facilities totaled $6 million and for thermal plants totaled $1 million.

IPC expects to incur significant capital costs related to the relicensing of its hydroelectric projects. See discussion in "REGULATORY ISSUES - Relicensing of Hydroelectric Projects."

Variations in the timing and amounts of capital expenditures will result from regulatory and environmental factors, load growth and other resource acquisition needs and the timing of relicensing expenditures. IDACORP and IPC are going through their annual long-term planning process and will prioritize capital expenditures while considering the effects of the outcome of IPC's general rate case, the need for additional resources in order for IPC to supply power to a growing number of customers and the maintenance of corporate credit ratings.

Financing Programs
Credit facilities: On March 17, 2004, IDACORP entered into a $150 million three-year credit agreement with various lenders, Bank One, NA (merged with JP Morgan Chase Corporation on July 1, 2004), as co-lead arranger and administrative agent and Wachovia Bank, National Association, as co-lead arranger and syndication agent (IDACORP Facility). The IDACORP Facility replaced IDACORP's two credit agreements, a $175 million facility that expired on March 17, 2004 and a $140 million facility that was to expire on March 25, 2005. The IDACORP Facility, which will be used for general corporate purposes and commercial paper back-up, will terminate on March 16, 2007. The IDACORP facility provides for the issuance of loans and standby letters of credit not to exceed the aggregate principal amount of $150 million, provided that the aggregate amount of the standby letters of credit may not exceed $75 million. At September 30, 2004, no loans were outstanding and $60 million of commercial paper was outstanding.

Under the terms of the IDACORP Facility, IDACORP may borrow floating rate advances and eurodollar rate advances. The floating rate is equal to the higher of (i) the prime rate announced by Bank One or its parent and (ii) the sum of the federal funds effective rate for such day plus 1/2 percent per annum, plus, in each case, an applicable margin. The eurodollar rate is based upon the British Bankers' Association interest settlement rate for deposits in U.S. dollars, as adjusted by the applicable reserve requirement for eurocurrency liabilities imposed under Regulation D of the Board of Governors of the Federal Reserve System, for periods of one, two, three or six months plus the applicable margin. The applicable margin is based on IDACORP's rating for senior unsecured long-term debt securities without third-party credit enhancement as provided by Moody's and S&P. The applicable margin for the floating rate advances is zero percent unless IDACORP's rating falls below Baa3 from Moody's or BBB- from S&P, at which time it would equal 0.50 percent. The applicable margin for eurodollar rate advances ranges from 0.54 percent to 1.65 percent depending upon the credit rating. At September 30, 2004, the applicable margin was zero percent for floating rate advances and 0.85 percent for eurodollar rate advances. A facility fee, payable quarterly by IDACORP, is calculated on the average daily aggregate commitment of the lenders under the IDACORP Facility and is also based on IDACORP's rating from Moody's or S&P as indicated above. At September 30, 2004, the facility fee was 0.15 percent.

In connection with the issuance of letters of credit, IDACORP must pay (i) a fee equal to the applicable margin for eurodollar rate advances on the average daily undrawn stated amount under such letters of credit, payable quarterly in arrears, (ii) a fronting fee in an amount agreed upon with the letter of credit issuer, payable quarterly in arrears, and (iii) documentary and processing charges in accordance with the letter of credit issuer's standard schedule for such charges.

A ratings downgrade would result in an increase in the cost of borrowing and of maintaining letters of credit, but would not result in any default or acceleration of the debt under the IDACORP Facility.

The events of default under the IDACORP Facility include (i) nonpayment of principal when due and nonpayment of interest or other fees within five days after becoming due, (ii) materially false representations or warranties made on behalf of IDACORP or any of its subsidiaries on the date as of which made, (iii) breach of covenants, subject in some instances to grace periods, (iv) voluntary and involuntary bankruptcy of IDACORP or any material subsidiary, (v) the non-consensual appointment of a receiver or similar official for IDACORP or any of its material subsidiaries or any substantial portion (as defined in the IDACORP Facility) of its property, (vi) condemnation of all or any substantial portion of the property of IDACORP or its subsidiaries, (vii) default in the payment of indebtedness in excess of $25 million or a default by IDACORP or any of its subsidiaries under any agreement under which such debt was created or governed which will cause or permit the acceleration of such debt or if any of such debt is declared to be due and payable prior to its stated maturity, (viii) IDACORP or any of its subsidiaries not paying, or admitting in writing its inability to pay, its debts as they become due, (ix) the acquisition by any person or two or more persons acting in concert of beneficial ownership (within the meaning of Rule 13d-3 of the Securities Exchange Act of 1934) of 20 percent or more of the outstanding shares of voting stock of IDACORP, (x) the failure of IDACORP to own free and clear of all liens, at least 80 percent of the outstanding shares of voting stock of IPC on a fully diluted basis, (xi) certain liabilities under the Employee Retirement Income Security Act of 1974 exceeding $25 million and (xii) IDACORP or any subsidiary being subject to any proceeding or investigation pertaining to the release of any toxic or hazardous waste or substance into the environment or any violation of any environmental law (as defined in the IDACORP Facility) which could reasonably be expected to have a material adverse effect (as defined in the IDACORP Facility). A default or an acceleration of indebtedness of IPC under the IPC Facility described below will result in a cross default under the IDACORP Facility, provided that such indebtedness is equal to at least $25 million.

Upon any event of default relating to the voluntary or involuntary bankruptcy of IDACORP or the appointment of a receiver, the obligations of the lenders to make loans under the facility and of the letter of credit issuer to issue letters of credit will automatically terminate and all unpaid obligations will become due and payable. Upon any other event of default, the lenders holding 51 percent of the outstanding loans or 51 percent of the aggregate commitments (required lenders) or the administrative agent with the consent of the required lenders may terminate or suspend the obligations of the lenders to make loans under the facility and of the letter of credit issuer to issue letters of credit under the facility or declare the obligations to be due and payable. IDACORP will also be required to deposit into a collateral account an amount equal to the aggregate undrawn stated amount under all outstanding letters of credit and the aggregate unpaid reimbursement obligations thereunder.

On March 17, 2004, IPC entered into a $200 million three-year credit agreement with various lenders, Bank One, NA (merged with JP Morgan Chase Corporation on July 1, 2004), as co-lead arranger and administrative agent and Wachovia Bank, National Association, as co-lead arranger and syndication agent (IPC Facility). The IPC Facility replaced IPC's $200 million credit agreement, which expired on March 17, 2004. The IPC Facility, which expires on March 16, 2007, will be used for general corporate purposes and commercial paper back-up. At September 30, 2004, no loans were outstanding and $22 million of commercial paper was outstanding. Under the terms of the IPC Facility, IPC may borrow floating rate advances and eurodollar rate advances. The methods of calculating the floating rate and the eurodollar rate are the same as set forth above for the IDACORP Facility. The applicable margin for the IPC Facility is also dependent upon IPC's rating for senior unsecured long-term debt securities without third-party credit enhancement as provided by Moody's and S&P. At September 30, 2004, the applicable margin for the IPC Facility was zero percent for floating rate advances and 0.75 percent for eurodollar rate advances. A facility fee, payable quarterly by IPC, is calculated on the average daily aggregate commitment of the lenders under the IPC Facility and is also based on IPC's rating from Moody's or S&P as indicated above. At September 30, 2004, the facility fee was 0.125 percent. A ratings downgrade would result in an increase in the cost of borrowing, but would not result in any default or acceleration of the debt under the IPC Facility.

The events of default under the IPC Facility are the same as under the IDACORP Facility.

Upon any event of default relating to the voluntary or involuntary bankruptcy of IPC or the appointment of a receiver, the obligations of the lenders to make loans under the facility will automatically terminate and all unpaid obligations of IPC will become due and payable. Upon any other event of default, the required lenders (or the administrative agent with the consent of the required lenders) may terminate or suspend the obligation of the lenders to make loans under the IPC Facility or declare IPC's unpaid obligations to be due and payable.

Short-term financings: At September 30, 2004, IDACORP's commercial paper borrowings totaled $60 million, compared to $94 million at December 31, 2003. At September 30, 2004, IPC's commercial paper borrowings totaled $22 million and there were no short-term borrowings at December 31, 2003. IDACORP's and IPC's short-term borrowings are expected to increase during 2004 mainly due to increased power supply costs at IPC caused by the continued impacts of the fifth consecutive year of below normal water conditions. A portion of IPC's power supply costs are recovered through its PCA regulatory mechanism discussed in "REGULATORY ISSUES - Deferred Power Supply Costs."

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, 2004, 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 in two series: $70 million First Mortgage Bonds 4.25% Series due 2013 and $70 million First Mortgage Bonds 5.50% Series due 2033. Proceeds were used to pay down IPC short-term borrowings incurred from the payment at maturity 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. On March 26, 2004, IPC issued $50 million First Mortgage Bonds 5.50% Series due 2034. Proceeds were used to reduce short-term borrowings and replace short-term investments, which were used on March 15, 2004 to pay at maturity the $50 million First Mortgage Bonds 8% Series due 2004. On August 16, 2004, IPC issued $55 million First Mortgage Bonds 5.875% Series due 2034. On September 20, 2004, the proceeds of this issuance were used to redeem all of IPC's outstanding preferred stock. At September 30, 2004, $55 million remained available to be issued on this shelf registration statement.

On August 17, 2004, IPC redeemed all $1 million of its Rural Electrification Administration notes.

IPC plans to file a shelf registration statement for $300 million for first mortgage bonds and debt securities during the fourth quarter of 2004.

The amount of first mortgage bonds issuable by IPC is limited to a maximum of $1.1 billion and by property, earnings and other provisions of the mortgage and supplemental indentures thereto. IPC may amend the indenture and increase this amount without consent of the holders of the first mortgage bonds. Substantially all of the electric utility plant is subject to the lien of the mortgage. As of September 30, 2004, IPC could issue under the mortgage approximately $677 million of additional first mortgage bonds based on unfunded property additions and $392 million of additional first mortgage bonds based on retired first mortgage bonds. At September 30, 2004, unfunded property additions, which consist of electric property, were approximately $1.1 billion.

At September 30, 2004, IFS had $71 million of debt related to investments in affordable housing with interest rates ranging from 3.65 percent to 8.59 percent due 2004 to 2010. The investments in affordable housing developments, which collateralize this debt, had a net book value of $107 million at September 30, 2004. IFS's $18 million Series 2003-1 tax credit note is non-recourse to both IFS and IDACORP. The $12 million Series 2003-2 tax credit note and $21 million of borrowings from a corporate lender are recourse only to IFS.

In June 2004, Ida-West purchased from a third party $18 million of debt issued by Marysville Hydro Partners, a 50-percent-owned, consolidated joint venture, for $11 million. This debt, previously consolidated under the provisions of FIN 46R, "Consolidation of Variable Interest Entities - an interpretation of ARB No. 51," is now eliminated in consolidation. Ida-West borrowed $6 million from IDACORP for this transaction.

IDACORP is considering issuing new shares of common equity in support of its ongoing capital efforts at IPC and reducing the level of outstanding commercial paper at IDACORP. The new shares of common equity may be a combination of one-time equity issuances along with the ongoing use of original share issuance in conjunction with the Dividend Reinvestment Program.

Debt Covenants: The IDACORP Facility and the IPC Facility contain a covenant requiring IDACORP and IPC, respectively, to maintain a leverage ratio of consolidated indebtedness to consolidated total capitalization of no more than 65 percent as of the end of each fiscal quarter. At September 30, 2004, the leverage ratios for IDACORP and IPC were 56 percent and 55 percent, respectively.

Other covenants in the IPC Facility include (i) prohibitions against investments and acquisitions by IPC or any subsidiary without the consent of the required lenders, subject to exclusions for investments in cash equivalents or securities of IPC, investments by IPC and its subsidiaries in any business trust controlled, directly or indirectly, by IPC to the extent such business trust purchases securities of IPC, investments and acquisitions related to the energy business of IPC and its subsidiaries not exceeding $500 million in the aggregate at any one time outstanding, investments by IPC or a subsidiary in connection with a permitted receivables securitization (as defined in the IPC Facility), (ii) prohibitions against IPC or any material subsidiary merging or consolidating with any other person or selling or disposing of all or substantially all of its property to another person without the consent of the required lenders, subject to exclusions for mergers into or dispositions to IPC or a wholly owned subsidiary and dispositions in connection with a permitted receivables securitization, (iii) restrictions on the creation of liens by IPC or any material subsidiary and (iv) prohibitions on any material subsidiary entering into any agreement restricting its ability to declare or pay dividends to IPC except pursuant to a permitted receivables securitization. At September 30, 2004, IPC was in compliance with all of the covenants of the facility.

Other covenants in the IDACORP Facility include (i) prohibitions against investments and acquisitions by IDACORP or any subsidiary without the consent of the required lenders subject to exclusions for investments in cash equivalents or securities of IDACORP, investments by IDACORP and its subsidiaries in any business trust controlled, directly or indirectly, by IDACORP to the extent such business trust purchases securities of IDACORP, investments and acquisitions related to the energy business or other business of IDACORP and its subsidiaries not exceeding $500 million in the aggregate at any one time outstanding (provided that investments in non-energy related businesses not exceed $150 million), investments by IDACORP or a subsidiary in connection with a permitted receivables securitization (as defined in the IDACORP Facility), (ii) prohibitions against IDACORP or any material subsidiary merging or consolidating with any other person or selling or disposing of all or substantially all of its property to another person without the consent of the required lenders, subject to exclusions for mergers into or dispositions to IDACORP or a wholly owned subsidiary and dispositions in connection with a permitted receivables securitization, (iii) restrictions on the creation of liens by IDACORP or any material subsidiary and (iv) prohibitions on any material subsidiary entering into any agreement restricting its ability to declare or pay dividends to IDACORP except pursuant to a permitted receivables securitization.

IDACORP is also required to maintain an interest coverage ratio of Credit Agreement EBITDA to consolidated interest charges equal to at least 2.75 to 1.00 as of the end of any fiscal quarter. Credit Agreement EBITDA is a financial measure that is used in the IDACORP Facility and is not a defined term under GAAP. Credit Agreement EBITDA differs from the term "EBITDA" (earnings before interest expense, income tax expense and depreciation and amortization) as it is commonly used. Credit Agreement EBITDA is defined as consolidated net income plus interest charges, income taxes, depreciation and all non-cash items that reduce such consolidated net income minus all non-cash items that increase consolidated net income. At September 30, 2004, IDACORP was in compliance with all of the covenants of the facility.

LEGAL AND ENVIRONMENTAL ISSUES:

Legal and Other Proceedings
Vierstra Dairy: On August 11, 2000, Mike and Susan Vierstra, dairy operators from Twin Falls, Idaho, brought suit against IPC in Idaho State District Court, Fifth Judicial District, Twin Falls County. The plaintiffs sought monetary damages of approximately $8 million for negligence and nuisance (allegedly allowing electrical current to flow in the earth and adversely affect the health of the plaintiffs' dairy cows) and punitive damages of approximately $40 million.

IPC intends to vigorously defend its position in this proceeding and believes this matter will not have a material adverse effect on its consolidated financial position, results of operations or cash flows.

The complaints allege that, during the purported class period, IDACORP and/or certain of its officers and/or directors made materially false and misleading statements or omissions about the company's financial outlook in violation of Sections 10(b) and 20(a) of the Securities Exchange Act of 1934, as amended, and Rule 10b-5, thereby causing investors to purchase the company's common stock at artificially inflated prices. More specifically, the complaints allege that IDACORP failed to disclose and misrepresented the following material adverse facts which were known to defendants or recklessly disregarded by them: (1) IDACORP failed to appreciate the negative impact that lower volatility and reduced pricing spreads in the western wholesale energy market would have on its marketing subsidiary, IE; (2) IDACORP would be forced to limit its origination activities to shorter-term transactions due to increasing regulatory uncertainty and continued deterioration of creditworthy counterparties; (3) IDACORP failed to discount for the fact that IPC may not recover from the lingering effects of the prior year's regional drought; and (4) as a result of the foregoing, defendants lacked a reasonable basis for their positive statements about IDACORP and their earnings projections. The Powell complaint also alleges that the defendants' conduct artificially inflated the price of the company's common stock. The actions seek an unspecified amount of damages, as well as other forms of relief. By order dated August 31, 2004, the court consolidated the Powell and Shorthouse cases for pretrial purposes, and ordered the plaintiffs to file a consolidated complaint within 60 days. On November 1, 2004, IDACORP and the directors and officers named above were served with a purported consolidated complaint captioned Powell et al. v. IDACORP, Inc. et al., which was filed in the United States District Court for the District of Idaho.

On September 8, 2004, this case was transferred and consolidated with other similar cases currently pending before the Honorable Robert H. Whaley, sitting by designation in the Southern District of California and presiding over Multidistrict Litigation Docket No. 1405, regarding California Wholesale Electricity Antitrust Litigation. IDACORP, IE and IPC have not answered the complaint filed against them, as a response is not yet required. The companies plan to file a motion to dismiss the complaint and intend to vigorously defend their position in this proceeding and believe this matter will not have a material adverse effect on their consolidated financial positions, results of operations or cash flows.

On September 8, 2004, this case was transferred and consolidated with other similar cases currently pending before the Honorable Robert H. Whaley, sitting by designation in the Southern District of California and presiding over Multidistrict Litigation Docket No. 1405, regarding California Wholesale Electricity Antitrust Litigation. IDACORP, IE and IPC have not answered this complaint, as a response is not yet required. The companies plan to file a motion to dismiss the complaint and intend to vigorously defend their position in this proceeding and believe this matter will not have a material adverse effect on their consolidated financial positions, results of operations or cash flows.

Western Energy Proceedings at the FERC: IE and IPC are involved in a number of FERC proceedings arising out of the western energy situation and claims that dysfunctions in the organized California markets contributed to or caused unjust and unreasonable prices in Pacific Northwest spot markets, and may have been the result of manipulations of gas or electric power markets. They include proceedings involving: (1) the chargeback provisions of the 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 (SCE) default and later by the Pacific Gas & Electric (PG&E) default. The FERC ordered the CalPX to rescind all chargeback actions related to the SCE and PG&E liabilities. The CalPX is awaiting further orders from the FERC and bankruptcy court before distributing the funds it collected under the chargeback mechanism; (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). The FERC issued an order on refund liability on March 26, 2003 which multiple parties, including IE, sought rehearing on. On October 16, 2003, the FERC denied the requests for rehearing and required the California Independent System Operator (Cal ISO) to make a compliance filing regarding refund amounts by December 2004. On May 12, 2004, the FERC issued an order clarifying its earlier refund orders and denying a request by certain parties to present as evidence an earlier settlement between the California Public Utilities Commission and El Paso related to manipulation of gas pipeline capacity claiming that the settlement dollars California is receiving from El Paso ($1.69 billion) are duplicative of the FERC order changing the gas component of its refund methodology. On December 2, 2003, IE and others petitioned the United States Court of Appeals for the Ninth Circuit for review of the FERC's orders. On September 21, 2004, the Ninth Circuit convened the first of its case management proceedings, a procedure reserved to help organize complex cases. A briefing schedule has been established for a portion of these cases. A second conference in the case management proceeding is scheduled for November 9, 2004. At September 30, 2004, 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, 2004, 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; (3) in the Pacific Northwest refund proceedings 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 and denied rehearing on November 11, 2003 and February 9, 2004. The FERC orders were appealed to the Ninth Circuit with briefing due to be completed by January 2005. IE and IPC are unable to predict the outcome of these matters. On July 21, 2004, the City of Seattle petitioned the Ninth Circuit requesting the court to direct the FERC to permit additional evidence consisting of audio tapes of Enron trader conversations and a delay in the briefing schedule in the Pacific Northwest refund. On August 2, 2004, the Ninth Circuit held the briefing schedule in abeyance until resolution of the motion to offer additional evidence. On August 2, 2004 and August 3, 2004, respectively, the FERC and a group of parties, including IE, filed their answers in opposition to the motion to offer additional evidence. On September 29, 2004, the Ninth Circuit denied the City of Seattle's motion without prejudice to renew the request in briefing and established a briefing schedule with final briefs due March 2, 2005, and (4) two cases which result from a ruling of the Ninth Circuit that the FERC permit 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 ("gaming") or anomalous market behavior ("partnership") in violation of the Cal ISO and CalPX Tariffs. On October 16, 2003, IPC reached agreement with the FERC Staff on the show cause orders. The "gaming" settlement was approved by the FERC on March 3, 2004. The FERC approved the motion to dismiss the "partnership" proceeding on January 23, 2004. Although the orders establishing the scope of the show cause proceedings are presently the subject of review petitions in the Ninth Circuit, the order dismissing IPC from the "partnership" proceedings was not the subject of rehearing requests. Eight parties have requested rehearing of the FERC's March 3, 2004 order approving the "gaming" settlement but the FERC has not yet acted on those requests.

On July 21, 2004, Californians for Renewable Energy (CARE) filed a motion with the FERC in connection with the California refund, the Pacific Northwest refund and the market manipulation cases requesting the FERC to revise its approach to the 2000-2001 western energy situation by (1) revoking market-based rate authority and replacing it with cost-of-service rates and requiring refunds back to the date of the order granting the market-based rate authority, (2) revising long-term contracts entered into during the western energy situation and (3) deferring new and rejecting existing refund settlements. IPC is unable to predict how the FERC will respond to CARE's motion.

The FERC also issued an order instituting an investigation of anomalous bidding behavior and practices in the western wholesale power markets. IPC submitted all data and information requested by the FERC Staff, and in a letter dated May 12, 2004, the FERC's Office of Market Oversight and Investigations advised that it was terminating the investigation as to IPC.

These matters are discussed in more detail in Note 5 to IDACORP's Consolidated Financial Statements.

Other Legal Proceedings: IDACORP, IPC and/or IE are involved in various lawsuits and legal proceedings in addition to those discussed above and in Note 5 to IDACORP's Consolidated Financial Statements. The companies believe they have meritorious 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.

Other Legal Issues
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. 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 and have heard nothing further from the CFTC.

Idaho Power Company Transmission Line Rights-of-Way Across Fort Hall Indian Reservation: IPC has multiple transmission lines that cross the Shoshone-Bannock Tribes' (Tribes) Fort Hall Indian Reservation near the city of Pocatello in southeastern Idaho. IPC has been working since 1996 to renew four of the right-of-way permits (for five of the transmission lines), which have stated permit expiration dates between 1996 and 2003. IPC filed applications with the United States Department of the Interior, Bureau of Indian Affairs, to renew the four 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 and allottees have demanded substantially greater payments for the permit renewals, 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. Due to the lack of definitive legal guidelines for valuation of the permit renewals, IPC is in the process of negotiating mutually acceptable renewal terms with the Tribes and allottees. The parties are pursuing a possible 23-year renewal of the permits (including all pre-renewal periods) for a total payment of approximately $7 million to the Tribes and allottees. IPC plans to obtain IPUC approval for the recovery of any renewal payment in its utility rates as a prerequisite to any settlement of the right-of-way renewals with the Tribes.

Environmental Issues
Idaho Water Management Issues: IPC holds water rights for hydroelectric purposes at each of its hydroelectric projects. The Snake River, at various places throughout its reach from Rexburg, Idaho to King Hill, Idaho, is connected to the Eastern Snake Plain Aquifer, a large underground aquifer that has been estimated to hold between 200-300 million acre-feet of water. As connected resources, depletion of the Eastern Snake Plain Aquifer can reduce flows in the Snake River. The majority of IPC's hydroelectric projects are impacted by spring flows that are connected to and fed by the Eastern Snake Plain Aquifer. With the advent of groundwater pumping for irrigation, the conversion of surface irrigated acres to groundwater irrigated acres and the conversion of surface irrigation to sprinkler systems (conserving water usage but reducing Eastern Snake Plain Aquifer recharge) depletion of the Eastern Snake Plain Aquifer has occurred and spring flows in the Thousand Springs reach of the Snake River have been steadily declining since the 1950's.

In August 2001, the Idaho Department of Water Resources designated portions of the Eastern Snake Plain Aquifer that are tributary to the Thousand Springs reach of the Snake River as a Ground Water Management Area due to the effect, exacerbated by several years of drought, of junior priority ground water withdrawals on senior surface water rights. Subsequently, in late 2001 and early 2002, junior ground water interests entered into a stipulated agreement with certain affected senior surface water users in an effort to mitigate the effects of ground water pumping. The Idaho Department of Water Resources established two ground water districts to facilitate the operation of the agreement. However, in 2003, surface water users that were not parties to the stipulated agreement filed delivery calls with the Idaho Department of Water Resources, demanding that it manage ground water withdrawals pursuant to the prior appropriation doctrine of "first in time is first in right" and curtail junior ground water rights that are depleting the Eastern Snake Plain Aquifer and affecting flows to senior surface water rights. These delivery calls resulted in several administrative actions before the Idaho Department of Water Resources and a judicial action before the State District Court in Ada County, Idaho. Because of the effect of the Eastern Snake Plain Aquifer on Snake River flows, and because IPC holds water rights in the Thousand Springs area that are dependent upon spring flows from the Eastern Snake Plain Aquifer, IPC intervened in these legal actions to protect its interests and encourage the development of a long-term management plan that will protect the aquifer and the river from further depletion.

In March 2004, the State of Idaho negotiated an interim agreement among various ground and surface water users in an effort to avoid protracted litigation and allow the state to develop short and long-term goals and objectives for effectively managing the Eastern Snake Plain Aquifer and ensuring that senior water rights are protected consistent with the prior appropriation doctrine and state law. As part of the interim agreement, the pending administrative and judicial processes are stayed until March 15, 2005 and the Idaho Legislature directed the Natural Resources Interim Committee, a standing committee, to meet and evaluate ways to stabilize and properly manage the Eastern Snake Plain Aquifer.

On September 15, 2004, the Interim Committee released an "Eastern Snake Plain Aquifer Conceptual Settlement Framework" containing proposed measures intended to result in the addition of 600,000 to 900,000 acre-feet of water annually to the Eastern Snake Plain Aquifer water supply. These measures include the implementation of water supply, water management, and water demand reduction measures, all of which are to be implemented in a manner consistent with the prior appropriation doctrine. Parties to the March 2004 interim agreement are now considering whether the framework provides a sufficient basis for moving forward with settlement discussions. IPC continues to monitor and participate in this process and other processes related to the conjunctive management of the Eastern Snake Plain Aquifer and the Snake River to protect its existing hydroelectric water rights.

REGULATORY ISSUES:

On September 28, 2004 the IPUC issued separate orders approving two Settlement Agreements entered into on August 16, 2004 between IPC and the IPUC Staff.

Settlement No. 1, approved by the IPUC in Order No. 29601, relates to the calculation of IPC's taxes for purposes of test year income tax expense. In the Idaho general rate case order, the IPUC adopted the use of a historic five-year average income tax rate to calculate IPC's income tax expense. Settlement No. 1 approved the modification of the general rate case order to utilize IPC's statutory income tax rates to compute test year income tax expense. As a result, IPC will compute and record monthly during the period June 1, 2004 through May 31, 2005 a regulatory asset (with interest accrued at a rate of one percent per annum) of approximately $12 million. Rates will increase on June 1, 2005 to reflect the ongoing impact of the tax expense. Approximately $4 million of this amount was recorded in the third quarter of 2004 as other operating revenue. The remaining balance will be deferred monthly from October 2004 through May 2005 and the total will be included for recovery during IPC's annual PCA process in the spring of 2005. Settlement No. 1 allows IPC to continue its compliance with the normalization provisions of the Internal Revenue Code of 1986, as amended, and associated Treasury Regulations, and will allow IPC to continue to receive the benefits of accelerated depreciation.

Settlement No. 2, approved by the IPUC in Order No. 29600, resolved outstanding issues related to (1) an unplanned outage at the one of the two units of the North Valmy Steam Electric Generating Plant in the summer of 2003, (2) a matter relating to the expense adjustment rate for growth component of the PCA and (3) regulatory accounting issues related to a tax accounting method change in 2002. In Settlement No. 2, IPC and the IPUC Staff agreed that the IPUC will not examine the cost of replacement power and a possible PCA adjustment resulting from the Valmy outage, and the expense adjustment rate for growth component of the PCA will continue at its existing value until IPC's next general rate case. In September 2004, as a result of the order, IPC established a regulatory liability of $19 million with a charge to PCA expense. A monthly credit of approximately $804,000 will be included in the PCA from June 2004 through May 2006, which will reduce this regulatory liability. Also in September 2004, IPC reversed a $16 million regulatory tax liability by reducing income tax expense. This regulatory tax liability was established in 2002 when IPC adopted a tax accounting method change for capitalized overhead costs.

The effect on third quarter 2004 earnings from these two agreements was to record an increase in net income of approximately $8 million.

Oregon: On September 21, 2004, IPC filed an application with the OPUC to increase general rates an average of 17.5 percent or approximately $4 million annually. On October 19, 2004, the OPUC suspended IPC's request for a period of time not to exceed nine months from October 20, 2004 to investigate the propriety and reasonableness of the request. A pre-hearing conference and public meeting are scheduled for November 18, 2004. IPC is unable to predict what rate relief, if any, the OPUC will grant.

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

		September 30,		December 31,
		2004		2003
Oregon deferral		$	12,484	$	13,620
Idaho PCA current year power supply cost deferrals:
	Deferral for 2004-2005 rate year		-		44,664
	Deferral for 2005-2006 rate year		23,219		-
Idaho PCA true-up awaiting recovery:
	Remaining true-up authorized May 2003		-		13,646
	Remaining true-up authorized May 2004		21,535		-
	Total deferral	$	57,238	$	71,930

The true-up of the true-up portion of the PCA provides a tracking of the collection or the refund of true-up amounts. Each month, the collection or the refund of the true-up amount is quantified based upon the true-up portion of the PCA rate and the consumption of energy by customers. At the end of the PCA year, the total collection or refund is compared to the previously determined amount to be collected or refunded. Any difference between authorized amounts and amounts actually collected or refunded are then reflected in the following PCA year, which becomes the true-up of the true up. Over time, the actual collection or refund of authorized true-up dollars matches the amounts authorized.

On April 15, 2004, IPC filed its 2004-2005 PCA with the IPUC requesting PCA recovery of $71 million above base rates and a proposed effective date of June 1, 2004 for new PCA rates. On May 25, 2004, the IPUC issued Order No. 29506 approving IPC's filing with additional instructions for IPC and the IPUC Staff to examine the cost of replacement power attributable to the unplanned outage at the North Valmy Plant in 2003. Based on the order approving Settlement No. 2, discussed above, the IPUC will not examine the costs related to this outage.

Following IPC's settlement with the IPUC on issues related to IPC's past relationship with IE, IPC approached the OPUC to settle the issue of the proper amount of fair compensation to Oregon customers related to the terminated Electricity Supply Management Services Agreement between IPC and IE, as well as any other issues relating to transactions between IPC and IE. On October 4, 2004, IPC filed a petition with the OPUC requesting an accounting order approving a settlement stipulation and authorizing IPC to credit its existing deferral balance of excess power supply costs. In the proposed settlement IPC agrees to continue the $7,700 monthly credit to customers, that began in July 2001, through December 2005, and to reduce the existing excess power supply cost deferral balance by a one time credit of $100,000 on January 1, 2005. The proposed settlement is intended to resolve all outstanding compensation issues arising out of the terminated agreement. The OPUC is currently evaluating the proposed settlement. IPC cannot predict the outcome of this issue.

Public Utilities Regulatory Policy Act of 1978
As mandated by the enactment of the Public Utilities Regulatory Policy Act of 1978 (PURPA) and the adoption of avoided costs standards by the IPUC and the OPUC, IPC has entered into contracts for the purchase of energy from a number of private developers. Under these contracts, IPC is required to purchase all of the output from the facilities located inside the IPC service territory. For projects located outside the IPC service territory, IPC is required to purchase the output that IPC has the ability to receive at the facility's requested point of delivery on the IPC system. For IPUC jurisdictional projects, projects up to ten MW are eligible for IPUC Published Avoided Costs for up to a 20-year contract term. The Published Avoided Cost is a price established by the IPUC and the OPUC to estimate IPC's cost of developing additional generation resources. For OPUC jurisdictional projects, projects up to one MW are eligible for OPUC Published Avoided Cost for up to a five-year contract term (automatically renewable at the end of five years). The Oregon provisions are currently being reviewed in an OPUC proceeding, as discussed below. If a PURPA project does not qualify for the Published Avoided Cost, then IPC is required to negotiate the terms, prices and conditions with the developer of that project. These negotiations reflect the characteristics of the individual projects (i.e., operational flexibility, location and size) and the benefits to the IPC system and must be consistent with other similar energy alternatives.

Idaho: On June 8, 2004, the IPUC ordered that two separate complaints against IPC be consolidated. The complaints both have at issue the contract terms required by IPC for PURPA qualifying facilities. The specific issues to be addressed by the IPUC are: (1) size threshold for standard rates; (2) the distinction between firm and non-firm energy and the appropriateness of performance bands and (3) the ability to terminate contractual obligations should retail deregulation be implemented in Idaho.

A public hearing was conducted on September 2, 2004 and September 3, 2004 and post-hearing briefs were filed on September 17, 2004. IPC is awaiting a final order from the IPUC on these complaints. The outcome is unknown at this time.

Oregon: In January 2004, the OPUC opened a proceeding to review its policies on PURPA matters and issue a comprehensive order to address them. The following issues have been identified for consideration in this proceeding: (1) contract length and price structure; (2) size threshold for standard rates; (3) utility tariff content; (4) avoided cost calculation methods; (5) applicability of Oregon PURPA administrative rules and (6) dispute mediation. A hearing began on October 27, 2004. The outcome of these issues is unknown at this time.

Idaho Renewable Energy Legislation
Idaho's interim legislative energy committee is reviewing three green-power incentive bills. The first bill would provide an investment tax credit against state income taxes for qualifying renewable generating facilities, the companion bill would provide an income tax credit for energy generated by qualifying facilities constructed after January 1, 2004 and the final bill would forgive a portion of sales tax paid on equipment purchases related to renewable generating facilities. The committee will bring the three bills forward for public discussion in the coming months before submitting any of them to the legislature. IPC is unable to predict what effect the passage of these bills would have on its operations.

Integrated Resource Plan
IPC filed its 2004 IRP with the IPUC and the OPUC in August 2004. The 2004 IRP reviews IPC's load and resource situation for the next ten years, analyzes potential supply-side and demand-side options and sets near-term and long-term action items. The two primary goals of the 2004 IRP are to: (1) identify sufficient resources to reliably serve the growing demand for energy service within IPC's service area throughout the 10-year planning period and (2) ensure that the portfolio of resources selected balances cost, risk and environmental concerns. In addition, there are two secondary goals: (1) to give equal and balanced treatment to both supply-side resources and demand-side measures and (2) to involve the public in the planning process in a meaningful way.

The IRP is filed every two years with both the IPUC and the OPUC. Prior to filing, the IRP requires extensive involvement by IPC, the IPUC Staff and the OPUC Staff, as well as customer, technological and environmental representatives and is the starting point for demonstrating prudence in IPC's resource decisions. Public comments concerning IPC's 2004 IRP are to be filed with the IPUC by December 3, 2004. IPC expects that the commissions will acknowledge the plan in late 2004 or early 2005. The 2004 IRP includes the following elements, which may require significant capital expenditures in the future:

76-MW demand response programs;

48-MW energy efficiency programs;

350-MW wind-powered generation;

100-MW geothermal-powered generation;

48-MW combined heat and power at customer facilities;

88-MW simple-cycle natural gas fired combustion turbine;

62-MW combustion turbine, distributed general or market purchases; and

500-MW coal-fired generation.

The 2004 IRP identifies specific actions to be taken by IPC prior to the next IRP in 2006. During the fourth quarter of 2004, IPC plans to issue an RFP for 200 MW of wind-powered generation, issue an RFP for a combustion turbine peaking resource and proceed with a transmission upgrade of the Borah-West line. In 2005, IPC will design demand-side measures in coordination with the Energy Efficiency Advisory Group and both commissions, issue an RFP for a 12-MW combined heat and power (co-generation) facility and issue an RFP for 100 MW of geothermal-powered generation.

Advanced 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 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 was expected to implement Advanced Meter Reading (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 the 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 directed IPC to collaboratively develop and submit a Phase One AMR Implementation Plan to replace current residential meters with advanced meters in selected service areas. IPC complied with this order on December 23, 2003 by filing a Phase One Implementation Plan that targeted the Emmett, Idaho and McCall, Idaho areas for 2004 installation and 2005 implementation. Phase One is estimated to cost $6 million and IPC will include these costs in future rate filings. Since April 2004, approximately 24,000 meters have been installed. IPC will submit a report to the IPUC by December 31, 2005, summarizing the AMR project and associated benefits and costs.

Relicensing of Hydroelectric Projects
IPC, like other utilities that operate nonfederal hydroelectric projects, obtains licenses for its hydroelectric projects from the FERC. These licenses last for 30 to 50 years depending on the size and complexity of the project. IPC recently received new licenses for five of its middle Snake River projects. The license for IPC's Malad hydroelectric project expired and the project will continue to operate under an annual license until the FERC issues a new multi-year license. IPC's hydroelectric project license for the HCC will expire in 2005 and the Swan Falls project license will expire in 2010. IPC is actively pursuing the relicensing of these projects, a process that may continue for the next ten to 15 years.

Middle Snake River Projects: The middle Snake River projects consist of the Bliss, Upper Salmon Falls, Lower Salmon Falls, Shoshone Falls and CJ Strike projects. On August 4, 2004, IPC received the FERC license orders for each of the middle Snake River projects. Each license is for a 30-year duration effective August 1, 2004. A central component of each license order is a Settlement Agreement between IPC and the United States Fish and Wildlife Service (USFWS) regarding five snail species that inhabit the middle Snake River, which are listed as threatened or endangered species under the ESA. As a basis for the settlement, IPC and the USFWS agreed that additional studies and analyses are needed in order to accurately assess the effect, if any, that the middle Snake River projects may have on one or more of the listed snail species. The Settlement Agreement provides for an operational regime for the five projects that will permit six years of studies and analyses of various project operations on the listed snail species, while providing interim protection of the listed species. After the studies are completed, IPC and the USFWS intend to jointly develop a plan that will address project operations and the protection of listed snails for the remainder of the new license terms.

On September 2, 2004, two conservation groups, American Rivers and Idaho Rivers United filed petitions for rehearing of the orders issuing the licenses for the middle Snake River projects. These petitions ask the FERC to vacate the licensing orders and request a determination from the USFWS that the middle Snake River projects jeopardize the listed snail species. On October 4, 2004, the FERC issued an Order Granting Rehearing for Further Consideration to provide additional time for consideration of the matters raised by the rehearing requests. The order further provided that the FERC anticipated issuing an order on the merits of the rehearing requests on or before November 1, 2004. The FERC has yet to issue an order.

On September 20, 2004, Idaho Rivers United filed a complaint against the USFWS in the United States District Court for the District of Idaho seeking judicial review of the biological opinion issued by the USFWS on May 14, 2004 on the effect of the relicensing of the middle Snake River projects on the listed snail species. The complaint alleges that the USFWS action in entering into and relying on the Settlement Agreement as a basis for issuing a no jeopardy determination in the biological opinion was arbitrary, capricious and contrary to law and asks the court to reverse the biological opinion and remand it to USFWS for further consideration. Neither the FERC nor IPC are parties to the action. The USFWS has not yet responded to the complaint.

Several of the new license articles for the middle Snake River projects require that IPC file additional information with the FERC either upon license issuance or within 30, 45 or 60 days following license issuance. IPC has made these required filings.

Many of the new license articles require IPC to develop comprehensive plans and submit them to the FERC for approval. The plans are due within six months to one year following license issuance. These plans are required to have detailed costs, schedules and methods for implementing the plans. IPC is also required to consult with certain parties that participated in the relicensing process including state and federal resource agencies, Native American Indian Tribes and non-governmental organizations (environmental organizations) prior to the completion of development and the filing of some of the plans. The FERC will then review and approve the plans, after which IPC will proceed with implementation of the plans.

Plans to be developed and approved for each license include White Sturgeon Conservation, Recreation Management, Middle Snake River and CJ Strike Wildlife Management Area Land Management, Minimum and Aesthetic Water Flows, Water Quality Monitoring; Historic Properties Management, Spring Habitat Protection, Fish Stocking and Operational Compliance Monitoring.

Because IPC is at the initial stages of developing the required plans for the FERC's review and approval, comprehensive cost estimates regarding implementing the measures required by the new licenses are not yet available. The FERC identified some generalized cost estimates in its Economic Benefits of Project Power section for each new license. The FERC's cost estimates are based on information provided by IPC in the Final License Applications and AIRs submitted in 1995 and 2000, respectively. For the five middle Snake River projects combined, the FERC's estimated annual costs of measures and operations-related expenses, as licensed, are $15 million.

At September 30, 2004, $10 million of Middle Snake River Project relicensing and compliance costs were in Electric Plant in Service. The majority of these costs, which were incurred prior to the completion of IPC's recent Idaho general rate case, were approved for recovery in rates. The remaining costs and any future costs will be submitted to regulators for recovery through the rate-making process.

It is expected that most of calendar year 2005 will be spent preparing and filing plans and seeking FERC approval. The budget for these activities is $6 million. Construction and operations expenditures are anticipated to begin in 2006.

Malad Project: The license for the Malad project expired on August 1, 2004. IPC filed new license applications in July 2002 and will operate the project on an annual license issued under the same terms and conditions of the expired license until the FERC issues a new multi-year license. In September 2004, the FERC issued a Final Environmental Assessment under the National Environmental Policy Act (NEPA) for the Malad project concluding that with appropriate environmental protection measures, relicensing the project would not constitute a major federal action significantly affecting the quality of the human environment thereby permitting IPC to proceed with the relicensing of the project.

At September 30, 2004, $3 million of Malad project relicensing costs were included in Construction Work in Progress. The relicensing costs are recorded and held in Construction Work in Progress until a new multi-year license is issued by the FERC, at which time the charges are transferred to Electric Plant in Service.

Relicensing costs and costs related to new licenses will be submitted to regulators for recovery through the rate-making process.

Hells Canyon Complex: The most significant ongoing relicensing effort is the HCC, which provides approximately two-thirds of IPC's hydroelectric generating 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 and business, environmental, tribal, customer, local government and local landowner interests. The license application was filed in July 2003 and accepted by the FERC for filing in December of 2003. The current license for the HCC expires in July 2005. IPC will thereafter operate the project under an annual license issued by the FERC until the new multi-year license is issued. The application includes the continuation of existing, as well as new proposed, measures intended to protect, mitigate and enhance fish and wildlife, protect recreational opportunities, and preserve other aspects of environmental quality (PM&E measures). The costs of these PM&E measures, as estimated in the license application, (assuming a 30-year license) are approximately $106 million in the first five years of a license and $218 million over the following 25 years, for a total estimated cost of $324 million over a 30-year license. These cost estimates do not include estimated costs of proposed water quality measures included in the license application. These measures are the subject of ongoing state processes under Section 401 of the Clean Water Act. IPC estimates that costs associated with these water quality measures may result in an additional $62 million, for a total estimated cost of $386 million. These estimated costs could increase as a result of the Consultation/Settlement Process (see discussion below). In response to the filing of the license application in July 2003, various federal and state agencies, Native American Indian Tribes and other participants in the HCC relicensing process filed initial comments to the license application, some of which contained additional proposed PM&E measures. IPC's preliminary estimate of the potential cost of these additional proposed measures, assuming all of the proposed measures are included as conditions in a final license, which IPC believes is unlikely, is approximately $2.5 billion over a 50-year license. These cost estimates are preliminary as federal, state, tribal and private parties participating in the relicensing proceeding are not required to file their final comments, recommendations, terms, conditions and prescriptions with the FERC until later in the relicensing process. The FERC will then consider these final comments, recommendations, terms, conditions and prescriptions under the FPA, the National Environmental Policy Act and other applicable federal laws, and include those conditions in the final license that the FERC determines are necessary, and required to protect, mitigate and enhance those resources affected by the operation and management of the project. As such, the actual costs of the PM&E measures associated with the relicensing of the HCC will not be known until the new license is issued by the FERC.

At September 30, 2004, $64 million of HCC relicensing costs were included in Construction Work in Progress. The relicensing costs are recorded and held in Construction Work in Progress until a new multi-year license is issued by the FERC, at which time the charges are transferred to Electric Plant in Service.

Relicensing costs and costs related to the new licenses, as discussed above, will be submitted to regulators for recovery through the rate-making process.

Consultation/Settlement Process:
In an effort to resolve issues associated with the relicensing of the HCC, IPC is engaged with the FERC and relevant federal and state agencies on the effects, if any, of the relicensing of the project on species listed as threatened or endangered under the ESA. The National Marine Fisheries Service (NMFS) listed Snake River sockeye as endangered in 1991, Snake River spring, summer and fall chinook as threatened in 1992 and Snake River steelhead as threatened in 1997. In June 1998, the USFWS also listed bull trout in the Columbia and Klamath River basins as threatened. Since 1997 IPC has been engaged in informal discussions with the NMFS and other federal, state and tribal interests on issues associated with the effect of the HCC operations on ESA-listed species and aquatic resources below the HCC in the context of the Snake River Basin Adjudication mediation.

With respect to the informal consultations regarding relicensing of the HCC initiated in the Snake River Basin Adjudication mediation, the FERC has designated IPC as its non-federal representative for purposes of continuing this informal consultation with NMFS and USFWS. In July 2004, the FERC requested formal consultation with the NMFS regarding the effects of interim HCC operations on ESA-listed species and issued a notice to all interested parties of an ESA consultation meeting on September 9, 2004 to discuss how to proceed with consultation, including how to integrate the ongoing HCC relicensing settlement discussion into the consultation process.

On September 7, 2004, IPC submitted a letter to the FERC regarding the September 9, 2004 consultation meeting, advising that IPC, NMFS and the USFWS had explored opportunities to address ESA issues associated with the interim operations and the relicensing of the HCC through a negotiated settlement process. IPC submitted to the FERC a draft document entitled "Hells Canyon ESA Consultation/Settlement Process," which generally described a proposed settlement process intended to result in a comprehensive settlement agreement to resolve issues associated with interim operations and the relicensing of the HCC.

At the September 9, 2004 meeting, IPC, NMFS and the USFWS discussed the proposed settlement process with the FERC Staff and other interested parties in attendance. At the conclusion of that meeting, the parties, with the concurrence of the FERC Staff, expressed an interest in engaging in additional discussions intended to reach agreement on an organizational structure for implementing the Hells Canyon ESA Consultation/Settlement Process.

In late September 2004, IPC, NMFS, the USFWS and other parties, including the states of Idaho and Oregon, the United States Forest Service, several Native American Indian Tribes, American Rivers and Idaho Rivers United, interested in the relicensing of the HCC met to continue discussions relative to the initiation of the Hells Canyon ESA Consultation/Settlement Process. At those meetings the parties discussed the development of procedures and the advisability of retaining a facilitator. Subsequent meetings were held in late October 2004.

Additional Information Requests:
The relicensing process permits intervenors to submit ASRs to the FERC. In the HCC relicensing process, ASRs were submitted in response to the FERC's Notice of Tendering Application issued July 31, 2003. The FERC received a total of 123 ASRs. On May 4, 2004, the FERC Staff responded to the ASRs issuing to IPC a total of fourteen AIRs.

On June 8, 2004, IPC filed a letter with the FERC objecting to certain of the AIRs and requesting clarification, modification or extensions of time as to others. IPC objected to some of the AIRs on the basis that there was no nexus between the HCC operations and the asserted effects on the resources that were the subject of the AIRs, submitting that under the FPA, the FERC's authority to impose terms and conditions in a project license is limited to resources that are affected by the development, operation and management of the project. In the case of several of the AIRs, IPC contended that the resources at issue were affected by the development and operation of federal hydroelectric projects downstream from the HCC, not by the HCC.

IPC objected to other AIRs relating to various limitations on flow, ramping rates and other operational restrictions intended to benefit recreational navigation below the HCC on the basis that the Hells Canyon National Recreation Area Act (HCNRAA), enacted by Congress in 1975, grandfathers the HCC and prohibits flow requirements of any kind on waters of the Snake River below the HCC.

On June 29, 2004, the FERC Staff denied IPC's objections to the AIRs, advising that their review of the license application indicates that the HCC has the potential to affect downstream resources and disagreeing that the HCNRAA places any restriction on requirements that can be included in the license for the HCC. The FERC Staff also granted extensions of time and provided clarification for certain other AIRs. On July 29, 2004, IPC filed a Petition for Rehearing with the FERC contesting the FERC Staff's decision denying IPC's objections to the AIRs.

By letter dated July 30, 2004, IPC requested additional time to complete certain of the AIRs because relevant studies and model runs could not be completed within the time allowed, and advised the FERC that although IPC had filed a request for rehearing regarding the FERC Staff's denial of IPC's objections, IPC was proceeding with the studies and analysis relevant to the AIRs pending the FERC's consideration of that request.

On September 13, 2004, IPC filed a request with the FERC requesting that it defer taking action on the pending rehearing request because IPC and other interested parties had commenced the Consultation/Settlement Process discussed above. IPC did not request, however, that the FERC defer action on the July 30, 2004 request for additional time.

By letter dated October 20, 2004, the FERC Staff denied some of the requests for additional time and provided limited relief as to others.

On June 11, 2004, American Rivers and Idaho Rivers United filed an interlocutory appeal of the FERC Staff's denial of fish passage study requests, one of the ASRs that the FERC Staff did not adopt in its May 4, 2004 response. IPC filed a response to the interlocutory appeal on June 28, 2004. By order dated July 15, 2004, the FERC dismissed the interlocutory appeal filed by American Rivers and Idaho Rivers United.

Swan Falls Project: The license for the Swan Falls hydroelectric project expires in 2010. IPC is preparing for the first stage of formal consultation for the new license application, which will be filed with the FERC in 2008.

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 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 two principal 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 moved to intervene in the case and 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 case was argued on March 16, 2004. On June 22, 2004, the court issued a decision in the case ordering the FERC to issue a judicially reviewable response to the 1997 petition within 45 days.

On August 6, 2004, the FERC entered an Order On Mandamus and Granting Petition granting the 1997 petition. Consistent with this order, the FERC initiated ESA consultation, setting a meeting on September 9, 2004 with NMFS, USFWS and IPC to discuss the interaction of formal consultation on ongoing operations with the anticipated ESA consultation regarding the relicensing of the HCC, and how any potential settlement discussions could be integrated into the consultation process. See previous discussion in "Hells Canyon Complex." On September 7, 2004, IPC filed a request for rehearing on the FERC's August 6, 2004 Order. On October 7, 2004, the FERC issued an Order Granting Rehearing for Further Consideration in order to afford additional time for consideration of the matters raised by the rehearing request. The order further provided that the FERC anticipates issuing an order on the merits of the rehearing request on or before November 22, 2004.

Regional Transmission Organizations
In December 1999, the FERC, in Order No. 2000, said that all companies with transmission assets must file to form RTOs or explain why they cannot do so. Order No. 2000 was a follow up to Order Nos. 888 and 889 issued in 1996, which require 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 nine other regional transmission owners filed Stage One and Stage Two plans to form RTO West, an entity that would operate the transmission grid in the northwest and British Columbia. In September 2002, the FERC issued an order granting in part RTO West's Stage Two request for a declaratory order, approving the majority of the proposed plan. With further development of detail and some modification, the FERC stated that the proposal "will satisfy not only the Order No. 2000 requirements, but that it can also provide a basic framework for standard market design for the West." Before implementation, additional filings and State approvals will be necessary.

In April 2003, the FERC issued its "White Paper: Wholesale Market Platform," and "Appendix A: Comparison of the Proposed Wholesale Market Platform (WMP) with the RTO Requirements of Order No. 2000." The White Paper set forth the FERC's then current thinking on issues under consideration in the Standard Market Design proceeding. It focused in particular on the elements that must be in place for well-functioning wholesale markets. Appendix A provided a comparison of Order No. 2000's existing requirements for RTOs with the proposed requirements of the WMP that would apply to RTOs and independent system operators. The FERC committed to consider all comments on the White Paper, as well as pending legislation, prior to the issuance of a Final Rule. To date, the FERC has not issued a Final Rule in its Standard Market Design proceeding.

In mid-2003, the RTO West Regional Representatives Group (RRG), in an effort to bolster regional support, began a new phase of discussions related to the development of an independent entity to manage the regional transmission system and improve related wholesale markets. These discussions began with wide-ranging consideration of current transmission problems and opportunities within the region.
In late summer and fall 2003, task groups from the RRG focused on developing different option packages to address the region's transmission problems and opportunities. As this effort proceeded, however, many regional parties felt it would be preferable to work toward a single proposal that could gain broad regional support. To further this goal, the RRG formed a small task group to take into account the perspectives, priorities and concerns that regional parties had identified during the course of discussions since June 2003, and, working on behalf of the RRG as a whole, to develop the best proposal possible in view of these considerations.

As a result of this effort, the task group developed a regional proposal that received support from the RRG in February 2004. The regional proposal provides a framework that seeks to better manage the regional transmission system and enhance wholesale power markets through the creation of an independent entity that will manage the region's combined transmission services, operate certain aspects of the combined system such as transmission reservation and scheduling, provide monitoring of regional power markets, perform comprehensive transmission system-wide planning and facilitate other aspects of transmission system operation. The region continues to develop this proposal. In March 2004, the RRG also changed the name of RTO West to Grid West.

Bylaws that would create an independent board to implement Grid West have been developed and reviewed by the RRG. The BPA is undertaking further review of these bylaws in preparation for an anticipated bylaw adoption later in the fall of 2004. If the bylaws are approved, the next steps will include engaging an executive search firm to help identify possible developmental board candidates, who could be seated as early as spring 2005.

OTHER MATTERS:

Southwest Intertie Project
IPC began developing the Southwest Intertie Project (SWIP) in 1988. IPC's investment consists predominantly of rights-of-way over public lands in Idaho and Nevada. The SWIP rights-of-way extend from Midpoint substation in south-central Idaho through eastern Nevada to the Crystal switchyard north of Las Vegas, Nevada. IPC does not currently anticipate constructing this transmission line itself and is currently in discussions with parties that have submitted preliminary offers for an exclusive option to purchase the rights-of-way. The Bureau of Land Management recently granted a five-year extension to begin construction of a proposed 500-kV transmission line within the rights-of-way before December 2009.

IdaTech
In September 2004, IdaTech announced that it had been selected by automobile manufacturer Volkswagen of Germany to design and manufacture an integrated fuel processor system operating on diesel fuel to be coupled with a proton exchange membrane fuel cell and used in an automotive application. The ability to use diesel fuel to produce hydrogen for fuel cells eliminates bulky storage of hydrogen and is an important factor in making fuel cells practical for vehicles. The technology, if successful, could decrease the load on the engine and improve overall fuel efficiency and emissions. Volkswagen paid IdaTech a down payment upon execution of the contract and will complete payment upon delivery of a working prototype in the first part of 2005.

Ida-West
In 2003, IDACORP made the decision to discontinue Ida-West's project development operations. This decision resulted from the implementation of IDACORP's new corporate strategy. The new strategy does not include the development or acquisition of merchant generation, which was Ida-West's focus. IDACORP reported that it would either sell Ida-West or retain its remaining properties and manage them with a smaller staff. Currently, Ida-West continues to manage its independent power projects and has reduced its workforce from 16 to 12 full-time employees.

IDACOMM
On June 29, 2004, IDACOMM acquired Sierra Pacific Communications' fiber-optic network in the Las Vegas, Nevada and Reno, Nevada metro areas. The acquisition includes 170 route-miles of metro area fiber-optic network, Sierra Pacific Communications' customers, the network's supporting infrastructure, five employees, offices and business equipment. This transaction enables IDACOMM to expand its business and strengthen its position in attractive markets without building new networks.

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

IDACORP and IPC are exposed to various market risks, including changes in interest rates, commodity prices, credit risk and equity price risk. The following discussion summarizes these risks and the financial instruments, derivative instruments and derivative commodity instruments sensitive to changes in interest rates, commodity prices and equity prices that were held at September 30, 2004.

Interest Rate Risk
IDACORP and IPC manage interest expense and short and long-term liquidity though a combination of fixed rate and variable rate debt. Generally, the amount of each type of debt is managed through market issuance, but interest rate swap and cap agreements with highly rated financial institutions may be used to achieve the desired combination.

Variable Rate Debt: At September 30, 2004, IDACORP and IPC had $194 million and $139 million, respectively, in variable rate debt, net of temporary investments. Assuming no change in either company's financial structure, if variable interest rates were to average one percentage point higher than the average rate on September 30, 2004, interest expense would increase and pre-tax earnings would decrease by approximately $2 million for IDACORP and $1 million for IPC.

Fixed Rate Debt: At September 30, 2004, IDACORP and IPC had outstanding fixed rate debt of $936 million and $865 million, respectively. The fair market value of this debt was $971 million and $897 million, respectively. These instruments are fixed rate, and therefore do not expose IDACORP or IPC to a loss in earnings due to changes in market interest rates. However, the fair value of these instruments would increase by approximately $83 million for IDACORP and $81 million for IPC if interest rates were to decline by one percentage point from their September 30, 2004 levels.

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, 2003.

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, 2003.

Energy: As part of the sale of the forward book of electricity trading contracts, IE entered into an Indemnity Agreement with Sempra Energy Trading, 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" and did not have a significant effect on IDACORP's financial statements.

Equity Price Risk
IDACORP and IPC's equity price risk has not changed materially from that reported in the Annual Report on Form 10-K for the year ended December 31, 2003.

ITEM 4. CONTROLS AND PROCEDURES

(a) Evaluation of disclosure controls and procedures:

The Chief Executive Officer and Chief Financial Officer of IDACORP, based on their evaluation of IDACORP's disclosure controls and procedures (as defined in Exchange Act Rule 13a-15(e)) as of September 30, 2004, have concluded that IDACORP's disclosure controls and procedures are effective.

The Chief Executive Officer and Chief Financial Officer of IPC, based on their evaluation of IPC's disclosure controls and procedures (as defined in Exchange Act Rule 13a-15(e)) as of September 30, 2004, have concluded that IPC's disclosure controls and procedures are effective.

(b) Changes in internal control over financial reporting:

Section 404 of the Sarbanes-Oxley Act of 2002 (SOX) and the rules issued thereunder require that as of December 31, 2004, IDACORP's and IPC's Chief Executive Officer and Chief Financial Officer assess the effectiveness of IDACORP's and IPC's internal control over financial reporting. This internal control report must include: (i) a statement of management's responsibility for establishing and maintaining adequate internal control over financial reporting, (ii) a statement identifying the framework used by management to conduct the required evaluation of the effectiveness of the company's internal control over financial reporting, (iii) management's assessment of the effectiveness of the company's internal control over financial reporting as of December 31, 2004, including a statement as to whether or not internal control over financial reporting is effective and (iv) a statement that the company's independent registered public accounting firm have issued an attestation report on management's assessment of internal control over financial reporting. To satisfy this requirement, IDACORP and IPC developed and have been applying a SOX 404 process, which includes steps to (i) identify significant accounts and disclosures and related financial statement assertions, (ii) document the existing control activities for each significant account, and disclosure and related assertions, (iii) test each of those control activities, (iv) identify control deficiencies, if any, (v) remediate the identified control deficiencies and (vi) test the remediated control activity to ensure that the identified control deficiencies have been properly remediated. IDACORP and IPC are working to strengthen their internal controls and to remediate any identified deficiencies prior to December 31, 2004.

In connection with this process, which began in 2003, a number of deficiencies have been identified in internal control over financial reporting. IDACORP and IPC reported in their Quarterly Report on Form 10-Q for the quarter ended March 31, 2004 that several control deficiencies in Information Technology controls over financial reporting had been identified related to disclosure controls and procedures. These deficiencies were in the areas of program development, program changes, computer operations and access to programs and data. Policies and procedures were developed and implemented to remediate the identified control deficiencies, and testing of the remediated control activities was performed in the third quarter of 2004.

The Public Company Accounting Oversight Board (PCAOB) has adopted stringent and complex standards governing management's required evaluation of its internal control over financial reporting and the independent registered public accounting firm's review of those controls. These standards may be subject to differing interpretations and application. Also, any system of controls, however well designed and operated, can provide only reasonable, and not absolute, assurance that the objectives of the control system are met. In addition, the design of any control system is based in part upon certain assumptions about the likelihood of future events. Because of these and other inherent limitations of control systems, there can be no absolute assurance that any design will succeed in achieving its stated goals under all potential future conditions, regardless of how remote. Because the PCAOB standards are complex and may be subject to differing interpretations and application and because of inherent limitations in control systems which preclude absolute assurance, it is possible that IDACORP and IPC and the independent registered public accounting firm will differ over what constitutes (1) a key control, (2) an adequate control or adequate remediation of a control deficiency or (3) a material weakness. Such differences could preclude the independent registered public accounting firm from delivering an unqualified opinion on management's assessment of internal controls under Section 404 of SOX.

Once the SOX 404 process has been completed and the Chief Executive Officer and Chief Financial Officer have assessed, as of December 31, 2004, the effectiveness of IDACORP's and IPC's internal control over financial reporting, the internal controls will be subject to ongoing monitoring and testing to support future assessments.

PART II - OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS

Reference is made to Note 5 to the Consolidated Financial Statements in this Quarterly Report on Form 10-Q and the Quarterly Reports on Forms 10-Q for the quarters ended March 31, 2004 and June 30, 2004.

ITEM 2. UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS

Issuer Purchases of Equity Securities:


(c) Idaho Power Company Preferred Stock					(d) Maximum
					Number (or
					Approximate
				(c) Total Number	Dollar
				of Shares	Value) of
				Purchased	Shares that
				as Part of	May Yet Be
	(a) Total			Publicly	Purchased
	Number	(b) Average		Announced	Under the
	of Shares	Price Paid		Plans or	Plans or
Period	Purchased	per Share		Programs	Programs
July 1 - July 31, 2004	-	$	-
August 1 - August 31, 2004	-		-
September 1 - September 30, 2004	522,898		103.31
Total	522,8981	$	103.31

1 On September 20, 2004, IPC redeemed all outstanding shares of its preferred stock. The redemption price was $104 per share for the
4% preferred stock, $103.18 per share for the 7.07% preferred stock and $102.97 per share for the 7.68% preferred stock, plus accumulated
and unpaid dividends.

ITEM 6. 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 the quarter ended 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 the quarter ended 3/31/03	3(b)	Bylaws 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 the quarter ended 6/30/03	4(a)(iii)	Thirty-eighth	May 15, 2003
	1-3198 Form 10-Q for the quarter ended 9/30/03	4(a)(iii)	Thirty-ninth	October 1, 2003

*4(b)	1-3198 Form 10-Q for the quarter ended 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)	1-11465 Form 10-Q for the quarter ended 9/30/03	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, 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 the quarter ended 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	1-14465 1-3198 Form 10-Q for the quarter ended 3/31/04	10(h)(i)	The Revised Security Plan for Senior Management Employees - a non-qualified, deferred compensation plan, amended and restated effective November 20, 2003.

*10(h)(ii)1	1-14465 1-3198 Form 10-K for 2003	10(h)(ii)	IDACORP, Inc. 2003 Executive Incentive Plan.

*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			Form of Restricted Stock Award Agreement.

10(h)(v)1			Form of Performance Share Award Agreement.

*10(h)(vi)1	1-14465 1-3198 Form 10-K for 1998	10(h)(iv)	The Revised Security Plan for Board of Directors - a non-qualified, deferred compensation plan effective August 1, 1996, revised March 8, 1999, as amended.

*10(h)(vii)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)(viii)	1-14465 Form 10-Q for the quarter ended 9/30/99	10(h)	Agreement between IDACORP, Inc. and Jan B. Packwood, J. LaMont Keen, James C. Miller, Darrel T. Anderson, Bryan Kearney and Robert W. Stahman.

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

10(h)(x)1			Form of Stock Option Award Agreement.

*10(h)(xi)	1-14465 1-3198 Form 10-Q for the quarter ended 6/30/04	10(h)(viii)	Form of Officer Indemnification Agreement as signed by all Officers of IDACORP, Inc. and IPC.


1 Compensatory plan



*10(h)(xii)	1-14465 Form 10-Q for the quarter ended 6/30/04	10(h)(ix)	Form of Director Indemnification Agreement as signed by all Directors of IDACORP, Inc.

*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 the quarter ended 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.)

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)

15			Letter Re: Unaudited Interim Financial Information.

*21	1-14465 1-3198 Form 10-K for 2003	21	Subsidiaries of IDACORP, Inc. and IPC.

31(a)			IDACORP, Inc. Rule 13a-14(a) certification.

31(b)			IDACORP, Inc. Rule 13a-14(a) certification.

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

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

32(a)			IDACORP, Inc. Section 1350 certification.

32(b)			IPC Section 1350 certification.

99			Earnings press release for third quarter 2004.

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 4, 2004	By:	/s/	Jan B. Packwood
				Jan B. Packwood
				President and Chief Executive Officer
				and Director

Date	November 4, 2004	By:	/s/	Darrel T. Anderson
				Darrel T. Anderson
				Senior Vice President - Administrative
				Services and Chief Financial Officer
				(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 4, 2004	By:	/s/	J. LaMont Keen
				J. LaMont Keen
				President and Chief Operating Officer and
				Director

Date	November 4, 2004	By:	/s/	Darrel T. Anderson
				Darrel T. Anderson
				Senior Vice President - Administrative
				Services and Chief Financial Officer
				(Principal Accounting Officer)

EXHIBIT INDEX


Exhibit Number

10(h)(iv)1		Form of Restricted Stock Award Agreement.

10(h)(v)1		Form of Performance Share Award Agreement.

10(h)(x)1		Form of Stock Option Award Agreement.

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

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

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

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

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

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

15		Letter Re: Unaudited Interim Financial Information.

31(a)		Rule 13a-14(a) certification. (IDACORP, Inc.)

31(b)		Rule 13a-14(a) certification. (IDACORP, Inc.)

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

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

32(a)		Section 1350 certification. (IDACORP, Inc.)

32(b)		Section 1350 certification. (IPC)

99		Earnings press release for third quarter 2004.

1 Compensatory plan

	Exact name of registrants as specified	I.R.S. Employer
Commission File	in their charters, address of principal	Identification
Number	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
	(208) 388-2200
	State of Incorporation: Idaho
	Web sites: www.idacorpinc.com
www.idahopower.com
None

IDACORP, Inc.:	38,192,022
Idaho Power Company:	39,150,812, 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	7-28
			Report of Independent Registered Public Accounting Firm	29
		Idaho Power Company:
			Consolidated Statements of Income	31-32
			Consolidated Balance Sheets	33-34
			Consolidated Statements of Capitalization	35
			Consolidated Statements of Cash Flows	36
			Consolidated Statements of Comprehensive Income	37
			Notes to Consolidated Financial Statements	38
			Report of Independent Registered Public Accounting Firm	39

	Item 2. Management's Discussion and Analysis of Financial
		Condition and Results of Operations		40-79

	Item 3. Quantitative and Qualitative Disclosures about Market Risk			79

	Item 4. Controls and Procedures			80-81

Part II. Other Information:

	Item 1. Legal Proceedings			81

	Item 2. Unregistered Sales of Equity Securities and Use of Proceeds			81

	Item 6. Exhibits			82-88

Signatures				89-90

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

COMMONLY USED TERMS

AFDC	-	Allowance for Funds Used During Construction
AG	-	Attorney General
AIRs	-	Additional Information Requests
ALJ	-	Administrative Law Judge
ASRs	-	Additional Study Requests
Cal ISO	-	California Independent System Operator
CalPX	-	California Power Exchange
CPUC	-	California Public Utilities Commission
EPS	-	Earnings per share
ESA	-	Endangered Species Act
FASB	-	Financial Accounting Standards Board
FERC	-	Federal Energy Regulatory Commission
FIN	-	Financial Accounting Standards Board Interpretation
FPA	-	Federal Power Act
FSP	-	Financial Accounting Standards Board Staff Position
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, 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 of Financial Condition and
			Results of Operations
MMCP	-	Mitigated Market Clearing Price
Moody's	-	Moody's Investors Service
MW	-	Megawatt
MWh	-	Megawatt-hour
NMFS	-	National Marine Fisheries Service
OPUC	-	Oregon Public Utility Commission
PCA	-	Power Cost Adjustment
PG&E	-	Pacific Gas and Electric Company
PM&E	-	Protection, Mitigation and Enhancement
PMC	-	Plaintiff's Master Complaint
REA	-	Rural Electrification Administration
RTO	-	Regional Transmission Organization
SCE	-	Southern California Edison
S&P	-	Standard & Poor's Ratings Services
SFAS	-	Statement of Financial Accounting Standards
VIEs	-	Variable Interest Entities

Three Months Ended

Nine Months Ended

Number