IDACORP INC - 10-Q Quarterly Report

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

				Three Months Ended March 31,
				2004		2003
				(thousands of dollars except for per
				share amounts)
OPERATING REVENUES:
	Electric utility:
		General business		$	146,157	$	175,062
		Off-system sales			28,121		18,608
		Other revenues			9,325		9,752
			Total electric utility revenues		183,603		203,422
	Energy marketing				86		3,593
	Other				4,500		4,913
		Total operating revenues			188,189		211,928

OPERATING EXPENSES:
	Electric utility:
		Purchased power			18,505		13,605
		Fuel expense			27,504		25,538
		Power cost adjustment			12,564		51,847
		Other operations and maintenance			54,146		50,585
		Depreciation			24,890		24,135
		Taxes other than income taxes			5,565		5,157
			Total electric utility expenses		143,174		170,867
	Energy marketing:
		Cost of revenues			(79)		3,720
		Selling, general and administrative			520		6,703
		Net loss on legal disputes			-		10,938
	Other				8,380		8,266
			Total operating expenses		151,995		200,494

OPERATING INCOME (LOSS):
	Electric utility				40,429		32,555
	Energy marketing				(355)		(17,768)
	Other				(3,880)		(3,353)
		Total operating income			36,194		11,434

OTHER INCOME					6,357		6,152

OTHER EXPENSES					3,547		3,522

INTEREST EXPENSE AND PREFERRED DIVIDENDS:
	Interest on long-term debt				13,353		15,193
	Other interest				453		1,075
	Preferred dividends of Idaho Power Company				854		868
		Total interest expense and preferred dividends			14,660		17,136

INCOME (LOSS) BEFORE INCOME TAXES					24,344		(3,072)

INCOME TAX EXPENSE					4,685		-

NET INCOME (LOSS)				$	19,659	$	(3,072)

AVERAGE COMMON SHARES OUTSTANDING (000's)					38,200		38,192
EARNINGS (LOSS) PER SHARE OF COMMON
	STOCK (basic and diluted)			$	0.51	$	(0.08)

The accompanying notes are an integral part of these statements.

IDACORP, Inc.
Consolidated Balance Sheets
(unaudited)

			March 31,		December 31,
			2004		2003
ASSETS			(thousands of dollars)

CURRENT ASSETS:
	Cash and cash equivalents		$	79,637	$	75,159
	Receivables:
		Customer		100,743		93,599
		Allowance for uncollectible accounts		(43,309)		(43,210)
		Employee notes		3,312		3,347
		Other		6,988		8,209
	Energy marketing assets			7,194		4,176
	Accrued unbilled revenues			23,951		30,869
	Materials and supplies (at average cost)			27,487		21,351
	Fuel stock (at average cost)			4,975		6,228
	Prepayments			27,276		27,779
	Regulatory assets			5,124		6,269
		Total current assets		243,378		233,776

INVESTMENTS				196,079		204,474

PROPERTY, PLANT AND EQUIPMENT:
	Utility plant in service			3,229,618		3,220,228
	Accumulated provision for depreciation			(1,258,409)		(1,239,604)
		Utility plant in service - net		1,971,209		1,980,624
	Construction work in progress			114,678		96,091
	Utility plant held for future use			2,438		2,438
	Other property, net of accumulated depreciation			39,893		9,166
		Property, plant and equipment - net		2,128,218		2,088,319

OTHER ASSETS:
	American Falls and Milner water rights			31,585		31,585
	Company-owned life insurance			35,829		35,624
	Energy marketing assets - long-term			19,002		14,358
	Regulatory assets			414,193		427,760
	Long-term receivables			3,214		3,106
	Employee notes			4,595		4,775
	Other			58,412		57,949
		Total other assets		566,830		575,157

		TOTAL	$	3,134,505	$	3,101,726

The accompanying notes are an integral part of these statements.

IDACORP, Inc.
Consolidated Balance Sheets
(unaudited)

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

CURRENT LIABILITIES:
	Current maturities of long-term debt			$	18,027	$	67,923
	Notes payable				92,995		93,650
	Accounts payable				35,775		60,916
	Energy marketing liabilities				7,194		4,317
	Taxes accrued				45,883		35,580
	Interest accrued				22,178		13,741
	Deferred income taxes				5,195		5,639
	Other				23,301		25,557
		Total current liabilities			250,548		307,323

OTHER LIABILITIES:
	Deferred income taxes				553,105		554,715
	Energy marketing liabilities - long-term				19,002		14,393
	Regulatory liabilities				259,961		258,524
	Other				108,455		104,290
		Total other liabilities			940,523		931,922

LONG-TERM DEBT					1,019,418		945,834

COMMITMENTS AND CONTINGENT LIABILITIES

PREFERRED STOCK OF IDAHO POWER COMPANY					52,331		52,366

SHAREHOLDERS' EQUITY:
	Common stock, no par value (shares authorized 120,000,000;
		38,341,358 shares issued)			474,294		472,902
	Retained earnings				405,358		397,167
	Accumulated other comprehensive income (loss)				(2,269)		(2,630)
	Treasury stock (156,736 and 110,748 shares at cost, respectively)				(4,627)		(3,158)
	Unearned compensation				(1,071)		-
		Total shareholders' equity			871,685		864,281

			TOTAL	$	3,134,505	$	3,101,726

The accompanying notes are an integral part of these statements.

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

				Three Months Ended
				March 31,
				2004		2003
				(thousands of dollars)
OPERATING ACTIVITIES:
	Net income (loss)			$	19,659	$	(3,072)
	Adjustments to reconcile net income (loss) to net cash provided by
		operating activities:
		Net non-cash loss on legal disputes			-		10,938
		Allowance for uncollectible accounts			84		(99)
		Unrealized gains from energy marketing activities			-		(1,154)
		Depreciation and amortization			30,667		32,381
		Deferred taxes and investment tax credits			(1,498)		(30,572)
		Accrued power cost adjustment costs			12,043		50,578
		Change in:
			Receivables and prepayments		(4,698)		28,995
			Accrued unbilled revenues		6,918		6,824
			Materials and supplies and fuel stock		392		(2,252)
			Accounts payable and other accrued liabilities		(27,077)		(40,577)
			Taxes receivable/accrued		10,303		34,291
			Other current liabilities		7,319		9,949
		Other assets			754		(2,208)
		Other liabilities			3,441		1,487
			Net cash provided by operating activities		58,307		95,509

INVESTING ACTIVITIES:
	Additions to property, plant and equipment				(38,013)		(24,968)
	Other assets				424		-
	Other liabilities				136		(7,312)
		Net cash used in investing activities			(37,453)		(32,280)

FINANCING ACTIVITIES:
	Issuance of first mortgage bonds				50,000		-
	Issuance of other long-term debt				-		25,475
	Retirement of first mortgage bonds				(50,000)		-
	Retirement of other long-term debt				(1,978)		(766)
	Retirement of preferred stock of Idaho Power Company				(28)		(589)
	Dividends on common stock				(11,466)		(17,706)
	Decrease in short-term borrowings				(1,550)		(73,350)
	Common stock issued				73		4,123
	Acquisition of treasury shares				(1,420)		(798)
	Other assets				-		(475)
	Other liabilities				(7)		(345)
		Net cash used in financing activities			(16,376)		(64,431)

Net increase (decrease) in cash and cash equivalents					4,478		(1,202)

Cash and cash equivalents beginning of period					75,159		42,736

Cash and cash equivalents end of period				$	79,637	$	41,534

SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION:
	Cash paid during the period for:
		Income taxes		$	1	$	292
		Interest (net of amount capitalized)		$	4,738	$	4,581

The accompanying notes are an integral part of these statements.

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

				Three Months Ended
				March 31,
				2004		2003
				(thousands of dollars)

NET INCOME (LOSS)				$	19,659	$	(3,072)

OTHER COMPREHENSIVE INCOME (LOSS):
	Unrealized gains on securities:
		Unrealized holding gains (losses) arising during the period,
			net of tax of $349 and ($792)		615		(1,334)
		Reclassification adjustment for (gains) losses included
			in net income, net of tax of ($164) and $211		(255)		329
			Net unrealized gains (losses)		360		(1,005)

TOTAL COMPREHENSIVE INCOME (LOSS)				$	20,019	$	(4,077)

The accompanying notes are an integral part of these statements.

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

1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES:

Nature of Business
IDACORP, Inc. (IDACORP) is a holding company whose principal operating subsidiary is Idaho Power Company (IPC). IPC is an electric utility engaged in the generation, transmission, distribution, sale and purchase of electric energy. IPC is regulated by the Federal Energy Regulatory Commission (FERC) and the state regulatory commissions of Idaho and Oregon. IPC is the parent of Idaho Energy Resources Co., a joint venturer in Bridger Coal Company, which supplies coal to the Jim Bridger generating plant owned in part by IPC.

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;

Velocitus - commercial and residential Internet service provider;

IDACOMM - provider of telecommunications services;

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

IDACORP Energy (IE) - marketer of electricity and natural gas, which wound down its operations during 2003.

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 beneficiary, 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 $21 million of total assets, primarily the hydro plant. Marysville also has $19 million of long-term debt, collateralized by the hydroelectric assets. This debt is non-recourse to IDACORP.

IFS is a limited partner in Empire Development Company, LLC (Empire), an entity that earned 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 57 percent. These investments were acquired between 1996 and 2002. IFS' maximum exposure to loss in these developments totaled $108 million at March 31, 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 March 31, 2004, and consolidated results of operations and consolidated cash flows for the three months ended March 31, 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 849,700 common stock options for the three months ended March 31, 2004, because the options' exercise prices were greater than the average market price of the common stock during the period. For the same period in 2003, 1,261,000 options were excluded from the diluted EPS calculation for the same reason. In total, 1,269,700 options were outstanding at March 31, 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 restricted stock are reflected in net income based on the market value at the award date, or the period-end price for shares not yet vested. No stock-based employee compensation cost is reflected in net income for stock options, as all options granted under these plans had an exercise price equal to the market value of the underlying common stock on the date of grant. IDACORP and IPC have adopted the disclosure only provision of Statement of Financial Accounting Standards (SFAS) 123, "Accounting for Stock-Based Compensation." The following table illustrates the effect on net income (loss) and EPS if the fair value recognition provisions of SFAS 123 had been applied to stock-based employee compensation (in thousands of dollars except for per share amounts):

			Three Months Ended
			March 31,
			2004		2003

Net income (loss), as reported			$	19,659	$	(3,072)
Add: Stock-based employee compensation expense included
	in reported net income (loss), net of related tax effects			121		(18)
Deduct: Total stock-based employee compensation expense
	determined under fair value based method for all awards,
	net of related tax effects			344		164
		Pro forma net income (loss)	$	19,436	$	(3,254)
Earnings (loss) per share:
	Basic and diluted - as reported		$	0.51	$	(0.08)
	Basic and diluted - pro forma			0.51		(0.09)

Adopted Accounting Pronouncement
In January 2004, IDACORP and IPC adopted Financial Accounting Standards Board 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. 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.

Reclassifications
Certain items previously reported for periods prior to March 31, 2004 have been reclassified to conform to the current period's presentation. Net income (loss) and shareholders' equity were not affected by these reclassifications.

2. INCOME TAXES:

IDACORP uses an estimated annual effective tax rate for computing its provision for income taxes on an interim basis. IDACORP's effective rate for the three months ended March 31, 2004 was 19.2 percent, compared to an effective rate of zero for the three months ended March 31, 2003. For 2003 it was expected that available tax benefits from tax credits and regulatory flow-through tax deductions would approximately offset the tax expense on pre-tax book income, resulting in a zero effective tax rate. The increase in the 2004 estimated tax rate is due primarily to the increase in pre-tax earnings compared to the first quarter of 2003.

3. CAPITAL STOCK:

Common Stock
During the three months ended March 31, 2004, IDACORP purchased 45,988 shares for its Restricted Stock Plan and issued 1,167 shares to shareholders of Rocky Mountain Communications Holdings, the parent company of Velocitus.

Preferred Stock of Idaho Power Company
During the three months ended March 31, 2004, IPC reacquired and retired 353 shares of 4% preferred stock.

4. FINANCING:

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

			March 31,		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		-
		Total first mortgage bonds		730,000		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				1,085		1,105

American Falls bond guarantee				19,885		19,885

Milner Dam note guarantee				11,700		11,700

Unamortized premium/(discount) - net				(2,537)		(2,205)

Debt related to investments in affordable housing				80,766		82,715

Other subsidiary debt				26,086		97
	Total			1,037,445		1,013,757
Current maturities of long-term debt				(18,027)		(67,923)

		Total long-term debt	$	1,019,418	$	945,834

(a) Humboldt County Pollution Control Revenue bonds are secured by first mortgage bonds.

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 March 31, 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 to pay at maturity the $50 million First Mortgage Bonds 8% Series due 2004, on March 15, 2004. At March 31, 2004, $110 million remained available to be issued on this shelf registration statement.

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 March 31, 2004, $55 million of commercial paper was outstanding.

At March 31, 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 March 31, 2004, $38 million of commercial paper was outstanding. This balance was paid as it matured during the first week of April using short-term investments, which are classified as cash and cash equivalents on the Consolidated Balance Sheets.

At March 31, 2004, IFS had $81 million of debt with interest rates ranging from 3.65 percent to 8.59 percent due 2004 to 2010. This debt is collateralized by investments in affordable housing developments with a net book value of $113 million at March 31, 2004.

As a result of IDACORP's adoption of FIN46R in January 2004, other subsidiary debt increased from December 31, 2003. This debt is non-recourse to IDACORP.

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 v. Idaho Power Company: 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 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. The court has yet to rule on the motions. Absent a favorable ruling from the court on the post-trial motions, IPC intends to appeal this decision.

IPC is unable to predict the outcome of this matter; however, based upon the information provided to date, IPC's insurance carrier has confirmed coverage. IPC has previously expensed the full amount of its self-insured retention. With coverage, this matter will not have a material adverse effect on IPC's 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 Federal District Court lacked jurisdiction because the FERC has exclusive jurisdiction over wholesale power transactions and thus the matter is preempted under the Federal Power Act (FPA) and barred by the filed-rate doctrine. The court ruled in favor of the companies' motion to dismiss and dismissed the case with prejudice on January 28, 2003. On February 25, 2003, Grays Harbor filed a Notice of Appeal, appealing the final judgment of dismissal to the United States Court of Appeals for the Ninth Circuit. Briefing on the appeal was completed in August 2003, but the court has yet to set a date for oral argument. The companies intend to vigorously defend their position on appeal and believe this matter will not have a material adverse effect on their consolidated financial positions, results of operations or cash flows.

Port of Seattle: On May 21, 2003, the Port of Seattle, a Washington municipal corporation, filed a lawsuit against 20 energy firms, including IPC and IDACORP, in the United States District Court for the Western District of Washington at Seattle. The Port of Seattle's complaint alleges fraud and violations of state and federal antitrust law and the Racketeering Influenced and Corrupt Organization Act. 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, have moved to dismiss the complaint in lieu of answering it. The motions are all 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. Briefing on these motions was completed in early February 2004. A hearing on the motion to dismiss was heard on March 26, 2004. The parties await the court's ruling. 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.

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, appealing the court's final judgment dismissing the action to the United States Court of Appeals for the Ninth Circuit. The briefing on the appeal was completed on October 31, 2003. The court set oral argument for June 14, 2004. IPC intends to vigorously defend its position on appeal and believes this matter will not have a material adverse effect on its consolidated financial position, results of operations or cash flows.

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

On April 22, 2002, more than a year after the initial complaints had been filed, two of the original defendants, Duke and Reliant, filed separate cross-complaints against IPC and IE, and approximately 30 other cross-defendants. Duke and Reliant's cross-complaints seek indemnity from IPC, IE and the other cross-defendants for an unspecified share of any amounts they must pay in the underlying suits because, they allege, other market participants like IPC and IE engaged in the same conduct at issue in the PMC. Duke and Reliant also seek declaratory relief as to the respective liability and conduct of each of the cross-defendants in the actions alleged in the PMC. Reliant has also asserted a claim against IPC for alleged violations of the California Unfair Competition Law, Business and Professions Code Section 17200. 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 Federal District Court granted Plaintiffs' Motion to Remand to state court, but did not issue a ruling on IPC and IE's motion to dismiss. The Ninth Circuit has granted certain Defendants and Cross-Defendants' Motions to Stay the Remand Order while they appeal the Order. The briefing on the appeal was completed in December 2003. The court set oral argument on the remand issue for June 14, 2004. A decision by the Ninth Circuit is expected sometime in 2004. As a result of the various motions, no trial date is set. The companies intend to vigorously defend their position in this proceeding and believe these matters will not have a material adverse effect on their consolidated financial positions, results of operations or cash flows.

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

On January 18, 2001, the CalPX sent IPC an invoice for $2 million - a "default share invoice" - - as a result of an alleged Southern California Edison (SCE) payment default of $215 million for power purchases. IPC made this payment. On January 24, 2001, IPC terminated the participation agreement. On February 8, 2001, the CalPX sent a further invoice for $5 million, due February 20, 2001, as a result of alleged payment defaults by SCE, Pacific Gas and Electric Company (PG&E) and others. However, because the CalPX owed IPC $11 million for power sold to the CalPX in November and December 2000, IPC did not pay the February 8th invoice. 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 plus $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 charge back methodology and provides for further oversight in the CalPX's implementation of its default mitigation procedures.

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

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

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

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

On July 25, 2001, the FERC issued an order establishing evidentiary hearing procedures related to the scope and methodology for calculating refunds related to transactions in the spot markets operated by the Cal ISO and the CalPX during the period October 2, 2000 through June 20, 2001.

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

The ALJ issued a Certification of Proposed Findings on California Refund Liability on December 12, 2002.

The FERC issued its Order on Proposed Findings on Refund Liability on March 26, 2003. In large part, the FERC affirmed the recommendations of its ALJ. However, the FERC changed a component of the formula the ALJ was to apply when it adopted findings of its staff that published California spot market prices for gas did not reliably reflect the prices a gas market that had not been manipulated would have produced, despite the fact that many gas buyers paid those amounts. The findings of the ALJ, as adjusted by the FERC's March 26, 2003 order, are expected to 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 will 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 November 2004. The Cal ISO is required to update the FERC on its progress monthly. After that time, the FERC will consider cost-based filings from sellers to reduce their refund exposure. On December 2, 2003, IE petitioned for review of the FERC's orders, and since that time, dozens of other petitions for review have been filed. The Ninth Circuit has 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 84. The Ninth Circuit has 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 before the FERC. 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 March 31, 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 March 31, 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 rates violate the FPA, and, even if market-based rate requirements are valid, that the quarterly transaction reports filed by sellers do not contain the transaction-specific information mandated by the FPA and the FERC. The complaint stated that refunds for amounts charged between market-based rates and cost-based rates should be ordered. The FERC denied the challenge to market-based rates and refused to order refunds, but did require sellers, including IE and IPC, to refile their quarterly reports to include transaction-specific data. The AG appealed the FERC's decision to the United States Court of Appeals for the Ninth Circuit. The AG contends that the failure of all market-based rate authority sellers of power to have rates on file with the FERC in advance of sales is impermissible. The Ninth Circuit heard oral arguments on October 9, 2003, but has not specified the date on which it will issue a decision. The companies cannot predict the outcome of this matter.

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

The California Parties urged the FERC to apply the precepts of its earlier decision, to replace actual prices charged in every hour starting May 1, 2000 through the beginning of the existing refund period (October 2, 2000) with 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 previously, the FERC declined to generically apply its refund determinations across the board to sales by all market participants, although it stated that it reserved the right to provide remedies for the market against parties shown to have engaged in proscribed conduct.

On June 25, 2003, the FERC ordered over 50 entities that participated in the western wholesale power markets between January 1, 2000 and June 20, 2001, including IPC, to show cause why certain trading practices did not constitute gaming or anomalous market behavior in violation of the Cal ISO and the CalPX Tariffs. The Cal ISO was ordered to provide data on each entity's trading practices within 21 days of the order, and each entity was to respond explaining their trading practices within 45 days of receipt of the Cal ISO data. IPC submitted its responses to the show cause orders on September 2 and 4, 2003. On October 16, 2003, IPC reached agreement with the Staff on the two orders commonly referred to as the "gaming" and "partnership" show cause orders. Regarding the gaming order, the Staff determined it had no basis to proceed with allegations of false imports and paper trading and IPC agreed to pay $83,373 to settle allegations of circular scheduling. IPC believed that it had defenses to the circular scheduling allegation but determined that the cost of settlement was less than the cost of litigation. In the settlement, IPC did not admit any wrongdoing or violation of any law. With respect to the "partnership" order, the Staff submitted a motion to the FERC to dismiss the proceeding because materials submitted by IPC demonstrated that IPC did not use the "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 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 multi-district litigation, a lottery was held and, subject to motions by adversely affected parties, these cases are to be considered in the Washington, D.C. Circuit. Notwithstanding the outcome of the multi-district panel lottery, some petitions currently remain pending in the Ninth Circuit. No briefing schedule has 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 will review evidence of alleged economic withholding of generation. The FERC has determined that all bids into the CalPX and the Cal ISO markets for more than $250 per MWh for the time period May 1, 2000 through October 1, 2000 will be considered prima facie evidence of economic withholding. The FERC has issued data requests in this investigation to over 60 market participants including IPC. If it is determined that IPC engaged in improper bidding, the FERC has indicated that sanctions may include disgorgement of alleged profits and other non-monetary actions, including possible revocation of market-based rate authority and/or additional required provisions in codes of conduct. IPC received some information regarding these matters from the Cal ISO and on July 24, 2003, IPC responded to the FERC's data requests. Based on the information received to date from the Cal ISO, IDACORP and IPC believe that any potential penalties imposed by the FERC would not have a material adverse effect on their consolidated financial positions, results of operations or cash flows.

Pacific Northwest Refund: On July 25, 2001, the FERC issued an order establishing another proceeding to explore whether there may have been unjust and unreasonable charges for spot market sales in the Pacific Northwest during the period December 25, 2000 through June 20, 2001. The FERC ALJ submitted recommendations and findings to the FERC on September 24, 2001. The ALJ found that prices should be governed by the Mobile-Sierra standard of the public interest rather than the just and reasonable standard, that the Pacific Northwest spot markets were competitive and that no refunds should be allowed. Procedurally, the ALJ's decision is a recommendation to the commissioners of the FERC. Multiple parties submitted comments to the FERC respecting the ALJ's recommendations. The ALJ's recommended findings had been pending before the FERC, when at the request of the City of Tacoma and the Port of Seattle on December 19, 2002, the FERC reopened the proceedings to allow the submission of additional evidence related to alleged manipulation of the power market by Enron and others. As was the case in the California refund proceeding, at the conclusion of the discovery period, parties alleging market manipulation were to submit their claims to the FERC and responses were due on March 20, 2003. Grays Harbor, whose civil litigation claims were dismissed, as noted above, 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 is requesting refunds from IPC of $5 million. Grays Harbor did not suggest that there was any misconduct by the company. The company submitted responsive testimony defending vigorously against Grays Harbor's refund claims.

In addition, the Port of Seattle, the City of Tacoma and 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 having received incorrectly congestion revenues from the Cal ISO. On June 25, 2003, after having considered oral argument held earlier in the month, the FERC issued its Order Granting Rehearing, Denying Request to Withdraw Complaint and Terminating Proceeding, in which it terminated the proceeding and required that no refunds be paid. The FERC denied rehearing on November 10, 2003, triggering the right to file for review. The Port of Seattle, the City of Tacoma, the City of Seattle, the California AG, the California Public Utilities Commission and Puget Sound Energy Inc. filed petitions for review in the Ninth Circuit within the time permitted. 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. 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 the petitions of others. The FERC's order remains subject to review by the Ninth Circuit. The companies are unable to predict the outcome of these matters.

Nevada Power Company: In February and April of 2001, IPC entered into two transactions under the Western Systems Power Pool (WSPP) Agreement whereby IPC agreed to deliver to Nevada Power Company (NPC) 25 MW during the third quarter of 2002. NPC agreed to pay IPC $250 per MWh for heavy load deliveries and $155 per MWh for light load deliveries. IPC assigned the contracts to IE with NPC's consent and the assignment was subsequently approved by the FERC. Based upon the uncertain financial condition of NPC, and pursuant to the terms of the WSPP Agreement, IE requested NPC to provide assurances of its ability to pay for the power if IE made the deliveries. NPC failed to provide appropriate credit assurances; therefore, in accordance with the WSPP Agreement procedures, IE terminated all WSPP Agreement transactions with NPC effective July 8, 2002. Pursuant to the WSPP Agreement, IE notified NPC of the liquidated damages amount and NPC responded with a letter, which described their view of rights under the WSPP Agreement and suggested a negotiated resolution. IE and NPC unsuccessfully attempted to mediate a resolution to this dispute.

IE filed a complaint against NPC on April 25, 2003, in Idaho State District Court in and for the County of Ada. This complaint was served on NPC on May 14, 2003. IE asked the Idaho State District Court for damages in excess of $9 million pursuant to the contracts. On June 17, 2003, NPC filed a motion to dismiss IE's complaint alleging, among other things, that: the Idaho State District Court lacks jurisdiction over NPC; a separate complaint seeking declaratory judgment was filed in the United States District Court, District of Nevada on May 14, 2003 by NPC against IPC, IE and IDACORP involving the same subject matter as the complaint filed by IE against NPC; IE does not have standing to maintain certain claims against NPC; Idaho is not a convenient forum to adjudicate the matter; and IE filed the action in Idaho State District Court in violation of the WSPP Agreement. NPC's motion to dismiss was heard on December 2, 2003. The parties await the court's ruling. NPC has never served IE with the complaint for declaratory judgment filed in the United States District Court in Nevada.

On September 23, 2003, NPC filed and served IE, IPC, and IDACORP with a Declaratory Action filed with the Nevada State Court in and for the County of Clark concerning the same subject matter of the pending Idaho State District Court action filed by IE on April 25, 2003. NPC seeks declaratory judgment on the following issues: that the assignment of the February and April 2001 energy supply contracts from IPC to IE is void or voidable; that IE did not comply with the WSPP Agreement when requesting reasonable assurances; and that NPC is relieved of its obligations to pay under the contracts by reason of force majeure. IE filed a motion to dismiss NPC's Nevada State Court claims. That motion was heard, and denied, on November 17, 2003. Trial of the Nevada State Court action is scheduled to commence on February 7, 2005.

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

At March 31, 2004, IE had a $4 million receivable related to the NPC contracts.

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 five of the right-of-way permits for 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 five rights-of-way for 25 years, including payment of the independently appraised value of the rights-of-way to the Tribes (and the Tribal allottees who own portions of the rights-of-way). The Tribes have not agreed to renew the rights-of-way and have demanded a substantially greater payment of $19 million, including an up-front payment of $4 million with the remainder to be paid over the 25-year term of the permits, or in the alternative $11 million including an up-front payment of $4 million with the remainder paid over the first three years of the permits. These amounts are based on an "opportunity cost" methodology, which calculates the value of the rights-of-way as a percentage of the cost to IPC of relocating the transmission lines off the Reservation. Both parties have discussed potential legal action regarding renewal of the rights-of-way, but no such action has been taken to date. The probable cost of renewing the rights-of-way is difficult to ascertain due to the lack of definitive legal guidelines for the renewals. IPC believes that the amount payable for 25-year rights-of-way should not exceed $11 million, the approximate present value of the offers communicated to date by the Tribes. IPC plans to obtain Idaho Public Utilities Commission (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:

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

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

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

On May 16, 2003, the FERC issued an order approving a stipulation and consent agreement resolving issues regarding access to IPC's transmission system, IPC's noncompliance with Sections 203 and 205 of the FPA, standards of conduct and codes of conduct. The order provided for (1) the refund of $0.3 million to certain counterparties associated with the inappropriate use of native load priority and for failure to obtain FERC approval prior to assigning certain contracts from IPC to IE, (2) the transfer of $5.8 million in benefits from IE to IPC as the result of certain transactions between the affiliates that were not properly filed with the FERC and (3) the implementation of certain compliance and auditing programs to ensure future compliance with FERC requirements.

In an IPUC proceeding that has been underway since May 2001, IPC, the IPUC staff and several interested customer groups have been working to determine the appropriate compensation IE should provide to IPC for certain transactions between the affiliates. The IPUC has issued several orders since then regarding these matters. Order No. 28852 issued on September 28, 2001 covered the time period prior to February 2001. Order No. 29026 covered the time period from March 2001 through March 2002. The IPUC also approved IPC's ongoing hedging and risk management strategies in Order No. 29102 issued on August 28, 2002. This order formalized IPC's agreement to implement a number of changes to its existing practices for managing risk and initiating hedging purchases and sales. In the same order, the IPUC directed IPC to present a resolution or a status report to the IPUC on additional compensation due to the utility for the use of its transmission system and other capital assets by IE and any remaining transfer pricing issues. Status reports were filed with the IPUC on December 20, 2002, March 20, 2003 and May 13, 2003 and settlement discussions were initiated. The $5.8 million in benefits related to the FERC settlement have been included in the Power Cost Adjustment (PCA) and credited to Idaho retail customers in accordance with the PCA methodology. The parties to the proceeding reached a settlement agreement that provided for an additional $5.5 million to be flowed through the PCA mechanism to the Idaho retail customers from April 2003 through December 2005. The IPUC approved the settlement on March 15, 2004 in Order No. 29446. The settlement should resolve all remaining compensation issues.

Federal Energy Regulatory Commission
As previously disclosed, IPC made a filing with the FERC on May 14, 2001, with respect to the pricing of real-time energy transactions between IPC and IE. For the period June 2001 through March 2002, IE paid IPC approximately $6 million, which was calculated based upon the pricing methodology for the entire period that was most favorable to IPC. This amount was credited to Idaho retail customers through the PCA. An additional $1 million has been paid to IPC for the period April 2002 through July 2002 based upon the same pricing methodology. On February 24, 2004, the FERC accepted the revised tariffs and service agreements filed by IPC to resolve this matter. The February 24, 2004 order represented final agency action and no requests for rehearing were filed within the 30-day period. As such, this matter has been concluded.

General Rate Case
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 February 20, 2004, the IPUC Staff and seven other intervenors filed their testimony with the IPUC. The testimony covered revenue requirement and rate design issues. The IPUC Staff's proposal of $15 million, a three percent overall increase to base rates, was the lowest recommendation of any of the parties. IPC filed its direct rebuttal to these recommendations on March 19, 2004. On rebuttal, IPC lowered its overall requested increase to $70 million annually, an average increase of 14.5 percent. The revised amount includes: updated depreciation rates in accordance with IPUC case No. IPC-E-03-7, the recognition of lower year-end employment levels than were expected when the case was originally filed and a change in IPC's pension cost recovery method. The IPUC conducted formal hearings on the matter from March 29, 2004 through April 5, 2004. A final order is expected from the IPUC by May 28, 2004, with a June 1, 2004 effective date.

IPC cannot predict what level of rate adjustment the IPUC will grant. Should the IPUC grant less than IPC's request, IPC might need to implement alternative strategies. These strategies could result in the deferral or elimination of certain capital expenditures, other cost containment measures and the filing of another rate request with the IPUC.

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

		March 31,		December 31,
		2004		2003
Oregon deferral		$	13,458	$	13,620
Idaho PCA current year power supply cost deferrals:
	Deferral for 2004-2005 rate year		44,285		44,664
Idaho PCA true-up awaiting recovery:
	Remaining true-up authorized May 2003		1,644		13,646
	Total deferral	$	59,387	$	71,930

Idaho: IPC has a PCA mechanism that provides for annual adjustments to the rates charged to its Idaho retail customers. These adjustments, which have historically taken effect in May, 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 a true-up, is then included in the calculation of the next year's PCA adjustment.

On April 15, 2004, IPC filed its 2004-2005 PCA with the IPUC, with a proposed effective date of June 1, 2004, requesting to collect $71 million over proposed base rates, which is $10 million less than the 2003-2004 PCA.

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

On May 13, 2002, the IPUC issued Order No. 29026 related to the 2002-2003 PCA rate filing. The order denied recovery of $12 million of lost revenues resulting from the Irrigation Load Reduction Program that was in place in 2001.

The IPUC issued Order No. 28992 on April 15, 2002 disallowing recovery of the lost revenues. IPC believes that this IPUC order is 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 believes it is 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 issued its decision, which 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 considered. The IPUC petitioned for reconsideration on April 20, 2004. A decision on the reconsideration is pending. IPC submitted its calculation of lost revenues of $12 million in the earlier IPUC proceeding. IPC cannot predict what level of recovery it will receive or the timing of such recovery.

Oregon: IPC is also recovering calendar year 2001 extraordinary power supply costs applicable to the Oregon jurisdiction. In two separate 2001 orders, the Oregon Public Utility Commission (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.

7. INDUSTRY SEGMENT INFORMATION:

IDACORP has identified three reportable operating 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 discussion on the wind down of energy marketing.

IFS represents that subsidiary's investments in affordable housing developments and historic preservation 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
March 31, 2004:
		Revenues	$	183,603	$	86	$	-	$	4,500	$	-	$	188,189
		Net income (loss)		19,409		(163)		2,585		(2,172)		-		19,659

Total assets at March 31,
	2004		$	2,886,842	$	50,270	$	144,579	$	120,513	$	(67,699)	$	3,134,505

Three months ended
	March 31, 2003:
		Revenues	$	203,422	$	3,593	$	-	$	4,913	$	-	$	211,928
		Net income (loss)		13,713		(10,436)		2,470		(8,819)		-		(3,072)

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

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 paid		(615)		(321)		-		(936)
Balance at March 31, 2004		$	1,192	$	1,701	$	33	$	2,926

The remaining 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 the Consolidated Balance Sheets.

9. BENEFIT PLANS

The following table shows the components of net periodic benefit cost for the three months ended March 31 (in thousands of dollars):

						Deferred				Other
		Pension Plan				Compensation Plan				Benefits
		2004		2003		2004		2003		2004		2003
Service cost		$	2,948	$	2,543	$	340	$	303	$	344	$	302
Interest cost			5,109		4,866		578		604		999		1,004
Expected return on plan assets			(6,978)		(5,861)		-		-		(565)		(483)
Amortization of net obligation
	at transition		-		-		153		153		-		-
Amortization of prior service
	cost		193		182		(90)		(86)		(141)		(141)
Amortization of net (gain)/loss			-		-		219		186		-		-
Recognized actuarial loss			-		90		-		-		357		351
Recognized net initial (asset)
	obligation		(66)		(66)		-		-		510		510
Net periodic benefit cost		$	1,206	$	1,754	$	1,200	$	1,160	$	1,504	$	1,543

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

INDEPENDENT ACCOUNTANTS' REPORT

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

We have reviewed the accompanying consolidated balance sheet of IDACORP, Inc. and subsidiaries as of March 31, 2004, and the related consolidated statements of operations, comprehensive income (loss) and cash flows for the three month periods ended March 31, 2004 and 2003. These financial statements are the responsibility of the Company's management.

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

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

We have previously audited, in accordance with auditing standards generally accepted in the United States of America, the consolidated balance sheet of IDACORP, Inc. and subsidiaries as of December 31, 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

Portland, Oregon
May 5, 2004

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Idaho Power Company
Consolidated Statements of Income
(unaudited)

			Three Months Ended
			March 31,
			2004		2003
			(thousands of dollars)
OPERATING REVENUES:
	General business		$	146,157	$	175,062
	Off-system sales			28,121		18,608
	Other revenues			9,048		9,320
		Total operating revenues		183,326		202,990

OPERATING EXPENSES:
	Operation:
		Purchased power		18,505		13,605
		Fuel expense		27,504		25,538
		Power cost adjustment		12,564		51,847
		Other		39,623		36,791
	Maintenance			13,821		13,584
	Depreciation			24,890		24,135
	Taxes other than income taxes			5,565		5,157
		Total operating expenses		142,472		170,657

INCOME FROM OPERATIONS				40,854		32,333

OTHER INCOME:
	Allowance for equity funds used during construction			1,002		851
	Other income			5,742		5,677
	Other expense			1,586		1,384
		Total other income		5,158		5,144

INTEREST CHARGES:
	Interest on long-term debt			12,336		14,492
	Other interest			999		1,331
	Allowance for borrowed funds used during construction			(755)		(820)
		Total interest charges		12,580		15,003

INCOME BEFORE INCOME TAXES				33,432		22,474

INCOME TAX EXPENSE				13,169		7,893

NET INCOME				20,263		14,581

	Dividends on preferred stock			854		868

EARNINGS ON COMMON STOCK			$	19,409	$	13,713

The accompanying notes are an integral part of these statements.

Idaho Power Company
Consolidated Balance Sheets
(unaudited)

				March 31,		December 31,
				2004		2003
ASSETS				(thousands of dollars)

ELECTRIC PLANT:
	In service (at original cost)			$	3,229,618	$	3,220,228
	Accumulated provision for depreciation				(1,258,409)		(1,239,604)
		In service - Net			1,971,209		1,980,624
	Construction work in progress				114,280		96,086
	Held for future use				2,438		2,438

			Electric plant - Net		2,087,927		2,079,148

INVESTMENTS AND OTHER PROPERTY					53,006		49,739

CURRENT ASSETS:
	Cash and cash equivalents				70,587		4,031
	Receivables:
		Customer			50,936		43,694
		Allowance for uncollectible accounts			(1,565)		(1,466)
		Notes			3,202		3,186
		Employee notes			3,312		3,347
		Related parties			516		1,143
		Other			3,204		4,848
	Accrued unbilled revenues				23,951		30,869
	Materials and supplies (at average cost)				26,218		19,755
	Fuel stock (at average cost)				4,975		6,228
	Prepayments				25,831		26,835
	Regulatory assets				5,124		6,269

			Total current assets		216,291		148,739


DEFERRED DEBITS:
	American Falls and Milner water rights				31,585		31,585
	Company-owned life insurance				35,829		35,624
	Regulatory assets				414,193		427,760
	Employee notes				4,595		4,775
	Other				43,416		43,341

			Total deferred debits		529,618		543,085

	TOTAL			$	2,886,842	$	2,820,711

The accompanying notes are an integral part of these statements.

Idaho Power Company
Consolidated Balance Sheets
(unaudited)

				March 31,		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			398,236		398,231
		Capital stock expense			(2,685)		(2,686)
		Retained earnings			328,679		320,735
		Accumulated other comprehensive income (loss)			(2,269)		(2,630)

			Total common stock equity		819,838		811,527

	Preferred stock				52,331		52,366

	Long-term debt				930,515		880,868

			Total capitalization		1,802,684		1,744,761

CURRENT LIABILITIES:
	Long-term debt due within one year				78		50,077
	Notes payable				37,600		-
	Accounts payable				32,262		45,529
	Notes and accounts payable to related parties				29		75
	Taxes accrued				77,457		55,383
	Interest accrued				20,868		12,893
	Deferred income taxes				5,124		6,179
	Other				20,449		20,985

			Total current liabilities		193,867		191,121

DEFERRED CREDITS:
	Deferred income taxes				542,091		546,205
	Regulatory liabilities				259,961		258,524
	Other				88,239		80,100

			Total deferred credits		890,291		884,829


COMMITMENTS AND CONTINGENT LIABILITIES

			TOTAL	$	2,886,842	$	2,820,711

The accompanying notes are an integral part of these statements.

Idaho Power Company
Consolidated Statements of Capitalization
(unaudited)

				March 31,				December 31,
				2004		%		2003		%
				(thousands of dollars)
COMMON STOCK EQUITY:
	Common stock			$	97,877			$	97,877
	Premium on capital stock				398,236				398,231
	Capital stock expense				(2,685)				(2,686)
	Retained earnings				328,679				320,735
	Accumulated other comprehensive income (loss)				(2,269)				(2,630)
		Total common stock equity			819,838		45		811,527		47

PREFERRED STOCK:
	4% preferred stock				12,331				12,366
	7.68% Series, serial preferred stock				15,000				15,000
	7.07% Series, serial preferred stock				25,000				25,000
		Total preferred stock			52,331		3		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				-
			Total first mortgage bonds		730,000				730,000
		Amount due within one year			-				(50,000)
			Net first mortgage bonds		730,000				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				1,085				1,105
		Amount due within one year			(78)				(77)
			Net REA notes		1,007				1,028

	American Falls bond guarantee				19,885				19,885

	Milner Dam note guarantee				11,700				11,700

	Unamortized premium/discount - net				(2,537)				(2,205)

			Total long-term debt		930,515		52		880,868		50

TOTAL CAPITALIZATION				$	1,802,684		100	$	1,744,761		100

The accompanying notes are an integral part of these statements.

Idaho Power Company
Consolidated Statements of Cash Flows
(unaudited)

				Three Months Ended
				March 31,
				2004		2003
				(thousands of dollars)
OPERATING ACTIVITIES:
	Net income			$	20,263	$	14,581
	Adjustments to reconcile net income to net cash provided by
		operating activities:
		Allowance for uncollectible accounts			84		(99)
		Depreciation and amortization			27,432		27,260
		Deferred taxes and investment tax credits			(4,613)		(18,726)
		Accrued PCA costs			12,043		50,578
		Change in:
			Receivables and prepayments		(3,584)		8,454
			Accrued unbilled revenue		6,918		6,824
			Materials and supplies and fuel stock		64		(2,297)
			Accounts payable		(13,268)		(22,868)
			Taxes receivable/accrued		22,074		3,411
			Other current liabilities		7,133		4,857
		Other assets			581		1,121
		Other liabilities			3,215		(2,183)
			Net cash provided by operating activities		78,342		70,913

INVESTING ACTIVITIES:
	Additions to utility plant				(37,181)		(24,794)
	Note receivable advance to parent				-		(620)
	Other assets				(5,252)		154
	Other liabilities				5,416		-
		Net cash used in investing activities			(37,017)		(25,260)

FINANCING ACTIVITIES:
	Issuance of first mortgage bonds				50,000		-
	Retirement of first mortgage bonds				(50,000)		-
	Retirement of preferred stock				(28)		(589)
	Dividends on common stock				(11,466)		(17,706)
	Dividends on preferred stock				(854)		(868)
	Increase (decrease) in short-term borrowings				37,599		(10,500)
	Other liabilities				(20)		79
		Net cash provided by (used in) financing activities			25,231		(29,584)

Net increase in cash and cash equivalents					66,556		16,069

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

Cash and cash equivalents at end of period				$	70,587	$	28,768

SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION:
	Cash paid during the period for:
		Income taxes paid to parent		$	-	$	27,238
		Interest (net of amount capitalized)		$	3,996	$	4,072

The accompanying notes are an integral part of these statements.

Idaho Power Company
Consolidated Statements of Comprehensive Income
(unaudited)

				Three Months Ended
				March 31,
				2004		2003
				(thousands of dollars)

NET INCOME				$	20,263	$	14,581

OTHER COMPREHENSIVE INCOME (LOSS):
	Unrealized gains on securities:
		Unrealized holding gains (losses) arising during the period,
			net of tax of $349 and ($792)		615		(1,334)
		Reclassification adjustment for (gains) losses included
			in net income, net of tax of ($164) and $211		(255)		329
			Net unrealized gains (losses)		360		(1,005)

TOTAL COMPREHENSIVE INCOME				$	20,623	$	13,576

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 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
			March 31,
			2004		2003

Net income, as reported			$	20,263	$	14,581
Add: Stock-based employee compensation expense included
	in reported net income, net of related tax effects			96		(8)
Deduct: Total stock-based employee compensation expense
	determined under fair value based method for all awards,
	net of related tax effects			264		161
		Pro forma net income	$	20,095	$	14,412

2. INCOME TAXES:

IPC uses an estimated annual effective tax rate for computing its provision for income taxes on an interim basis. IPC's effective tax rate for the three months ended March 31, 2004 was 39.4 percent, compared with an effective tax rate of 35.1 percent for the three months ended March 31, 2003. The increase in the 2004 estimated tax rate is due primarily to the favorable settlement of a prior year tax issue in the first quarter of 2003.

4. FINANCING:

IPC's $49.8 million Humboldt County Pollution Control Revenue bonds are secured by first mortgage bonds.

INDEPENDENT ACCOUNTANTS' REPORT

To the Board of Directors and Shareholder of Idaho Power Company
Boise, Idaho

We have reviewed the accompanying consolidated balance sheet and statement of capitalization of Idaho Power Company and its subsidiary as of March 31, 2004, and the related consolidated statements of income, comprehensive income and cash flows for the three month periods ended March 31, 2004 and 2003. These financial statements are the responsibility of the Company's management.

We have previously audited, in accordance with auditing standards generally accepted in the United States of America, the consolidated balance sheet and statement of capitalization of Idaho Power Company and its subsidiary as of December 31, 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

Portland, Oregon
May 5, 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 as the parent of IPC and several other entities.

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

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;

Velocitus - commercial and residential Internet service provider;

IDACOMM - provider of telecommunications services;

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

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

IE wound down its power marketing 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.

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 should be read in conjunction with the discussion in the Annual Report.

FORWARD-LOOKING INFORMATION:

In connection with the safe harbor provisions of the Private Securities Litigation Reform Act of 1995 (Reform Act), IDACORP and IPC are hereby filing cautionary statements identifying important factors that could cause actual results to differ materially from those projected in forward-looking statements (as such term is defined in the Reform Act) made by or on behalf of IDACORP or IPC in this Quarterly Report on Form 10-Q, in presentations, in response to questions or otherwise. Any statements that express, or involve discussions as to expectations, beliefs, plans, objectives, assumptions or future events or performance (often, but not always, through the use of words or phrases such as "anticipates," "believes," "estimates," "expects," "intends," "plans," "predicts," "projects," "will likely result," "will continue" or similar expressions) are not statements of historical facts and may be forward-looking. Forward-looking statements involve estimates, assumptions and uncertainties and are qualified in their entirety by reference to, and are accompanied by, the following important factors, which are difficult to predict, contain uncertainties, are beyond our control and may cause actual results to differ materially from those contained in forward-looking statements:

Changes in governmental policies and regulatory actions, including those of the Federal Energy Regulatory Commission (FERC), the Idaho Public Utilities Commission (IPUC) and the Oregon Public Utility Commission (OPUC), with respect to allowed rates of return, industry and rate structure, acquisition and disposal of assets and facilities, operation and construction of plant facilities, 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 resulting from the energy situation in the western United States;

Economic, geographic and political factors and risks;

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

Weather variations affecting customer energy usage;

Operating performance of plants and other facilities;

System conditions and operating costs;

Population growth rates and demographic patterns;

Pricing and transportation of commodities;

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

Changes in capacity, fuel availability and prices;

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

Changes in actuarial assumptions;

Adoption 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;

Competition for new energy development opportunities;

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

Natural disasters, acts of war or terrorism;

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

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

Technological developments that could affect the operations and prospects of our subsidiaries or their competitors;

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 significantly affect operating results. 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 (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 which are subject to the regulatory process. The non-Idaho power supply costs (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 affect operating results. While Idaho Power Company experienced colder than usual temperatures in its service territory in January and February, March was warm and dry. Warmer than normal winters or cooler than normal summers will reduce retail revenues from power sales.

Conditions that may be imposed in connection with hydroelectric license renewals may negatively affect earnings. Idaho Power Company is currently involved in renewing federal licenses for most of its hydroelectric projects. Idaho Power Company currently expects new licenses for five middle Snake River region hydroelectric plants to be issued in 2004. In addition, Idaho Power Company filed its license application on July 18, 2003 for the Hells Canyon Complex, which provides 40 percent of Idaho Power Company's total generating capacity. Conditions with respect to environmental, operating and other matters that the Federal Energy Regulatory Commission may impose in connection with the renewal of these licenses could have a negative effect on Idaho Power Company's operations and earnings.

The cost of complying with environmental regulations can significantly affect operating results. 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.

If the Idaho Public Utilities Commission does not grant requested rate relief, Idaho Power Company's earnings and cash flow will be negatively affected. Idaho Power Company is proceeding through its Idaho general rate case filed with the Idaho Public Utilities Commission on October 16, 2003. Idaho Power Company has not had an overall base rate increase since 1995. Since that time, Idaho Power Company has invested more than $850 million in its electrical system, experienced an increase in normal operating costs due to inflation and added nearly 100,000 customers. If the Idaho Public Utilities Commission does not grant the requested rate relief, Idaho Power Company's earnings and cash flow will be negatively impacted and its credit ratings may be downgraded.

Terrorist threats and activities can significantly affect operating results. 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 administrative proceedings, settlements, investigations and claims, including those that may arise out of the California 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 energy crisis in California include efforts by certain public parties to reform or terminate contracts for the purchase of power from IDACORP Energy and show cause proceedings at the Federal Energy Regulatory Commission, which have been settled but are the subject of motions for reconsideration or have been appealed. To the extent the companies are required to make payments, earnings will be negatively affected. It is possible that additional proceedings related to the California energy crisis may be filed in the future against IDACORP, Inc., IDACORP Energy or Idaho Power Company.

Increased capital expenditures can significantly affect liquidity. Increases in both the number of customers and the demand for energy require expansion and reinforcement of transmission, distribution and generating systems. Additionally, a significant portion of 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.

SUMMARY OF FIRST QUARTER 2004 AND OUTLOOK:

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

Financial Results
IDACORP's basic and diluted earnings per share (EPS) of $0.51 was a $0.59 per share increase over 2003's $0.08 per share loss. Several key factors impacted 2004's first quarter results:

IPC earned $0.51 per share during the three months ended March 31, 2004, a $0.15 per share increase over the first quarter last year. EPS increased due primarily to increases in electricity volumes sold, a result of colder temperatures in 2004. This increase was partially offset by increased operations and maintenance expenses. IPC's future operating results are largely dependent upon weather conditions, hydroelectric generating conditions and decisions made by the IPUC regarding the general rate case and the annual Power Cost Adjustment (PCA).

IDACORP Energy: Wind down activity at IE was completed and this segment had no effect on EPS for the first quarter of 2004 compared to a $0.28 per share loss in the first quarter of 2003. The 2003 loss is attributed to the wind down as well as an $11 million loss on the settlement of legal matters. IE will pay its remaining involuntary termination benefits accrual through 2004 and its remaining lease termination accrual through 2008.

IFS contributed $0.07 per share, principally from the generation of federal income tax credits and tax depreciation benefits. IFS is expected to continue generating these benefits at current levels. On April 22, 2004, IFS closed the sale of its equity investment in the El Cortez Hotel located in San Diego, California. In June of 2000, IFS invested $4 million to assist in the renovation of the Historic El Cortez into upscale apartment units. Upon exiting the investment IFS recognized a gain on sale of $6 million, income taxes of $4 million and a net gain of $2 million.

Other: The holding company and its other subsidiaries had a loss of $0.07 per share for the three months ended March 31, 2004 compared to a loss of $0.22 per share last year. The decreased loss is due primarily to the timing of 2003 tax benefits-intra-period tax benefits principally related to affordable housing tax credits for the first quarter of 2003 were allocated to later quarters in 2003.

General Rate Case
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 February 20, 2004, the IPUC Staff and seven other intervenors filed their testimony with the IPUC. The testimony covered revenue requirement and rate design issues. The IPUC Staff's proposal of $15 million, a three percent overall increase to base rates, was the lowest recommendation of any of the parties. Copies of the parties' testimony and exhibits can be viewed at the IPUC web site. IPC filed its direct rebuttal to these recommendations on March 19, 2004. On rebuttal, IPC lowered its overall requested increase to $70 million annually, an average increase of 14.5 percent. The IPUC conducted formal hearings on the matter from March 29, 2004 through April 5, 2004. A final order is expected from the IPUC by May 28, 2004, with a June 1, 2004 effective date.

IPC has not had an overall base rate increase since 1995. Since that time, IPC has invested more than $850 million in its electrical system, experienced an increase in normal operating costs due to inflation and added nearly 100,000 customers.

PCA
IPC filed its 2004-2005 PCA with the IPUC on April 15, 2004. The PCA seeks to collect $71 million over proposed base rates and is expected to be implemented on June 1, 2004.

Hydroelectric Generation and Power Supply Costs
IPC relies on low-cost hydroelectric generation for a significant portion of its power supply. January and February 2004 gave early indications of some relief from the below normal hydroelectric generating conditions experienced for the past four years; however, March 2004 was very warm and dry. Because below normal conditions are continuing for the fifth consecutive year, IPC must increase its reliance on higher-cost thermal generation and purchased power.

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 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 federal income tax credits, remains a key component of the revised corporate strategy.

Legal Issues and Regulatory Matters
Vierstra Dairy vs. Idaho Power Company: 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. In March 2004, IPC filed motions for new trial and judgment notwithstanding the verdict. Absent a favorable ruling on the post-trial motions, IPC intends to appeal the jury decision. IPC is unable to predict the outcome of this matter; however, based upon the information provided to date, IPC's insurance carrier has confirmed coverage. IPC has previously expensed the full amount of its self-insured retention.

IPUC and FERC Settlements: In February and March 2004, IPC and IE settled issues identified during the wind down of IE's operations. On February 24, 2004, the FERC accepted revised tariffs and service agreements filed by IPC to resolve the issues relating to pricing of real-time energy transactions between IPC and IE. On March 15, 2004, the IPUC approved a settlement agreement among IPC, the IPUC staff and several customer groups regarding the appropriate compensation IE should provide to IPC for certain transactions between the affiliates.

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. 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 recorded. The IPUC petitioned the Supreme Court for reconsideration on April 20, 2004 and the court's decision on the reconsideration is pending.

CRITICAL ACCOUNTING POLICIES:

IDACORP 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, will make adjustments when facts and circumstances dictate.

IDACORP's and IPC's critical accounting policies are discussed in more detail in the Annual Report on Form 10-K for the year ended December 31, 2003. IDACORP's and IPC's critical accounting policies have not changed materially from the discussions included in the 2003 Annual Report on Form 10-K.

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 months ended March 31, 2004 and 2003. In this analysis, the results of 2004 are compared to 2003. The analysis is organized by operating segment, concentrating on the Utility Operations and Energy Marketing segments. Additional noteworthy information about the results of other segments is also included. The following table presents EPS for each operating segment as well as for the holding company and its other subsidiaries combined for the three months ended March 31:

EPS of common stock
	2004		2003
Utility operations	$	0.51	$	0.36
Energy marketing		-		(0.28)
IFS		0.07		0.06
Other		(0.07)		(0.22)
Total EPS	$	0.51	$	(0.08)

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.

The increase in EPS from utility operations during the first three months of 2004 was primarily the result of increased sales due to colder temperatures during January and February. This increase was partially offset by a $4 million increase in operations and maintenance expenses.

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 absorbs.

IPC is currently experiencing its fifth consecutive year of below normal hydroelectric generating conditions. While hydroelectric generation increased over the first quarter of 2003, so did demand for electricity, caused by colder temperatures, necessitating increased higher-cost thermal generation and purchased power. The following table presents IPC's system generation for the three months ended March 31:

	MWh			% of total generation
			Total			Total
			system			system
	Hydroelectric	Thermal	generation	Hydroelectric	Thermal	generation
2004	1,751	1,912	3,663	48%	52%	100%
2003	1,571	1,831	3,402	46%	54%	100%

Streamflow conditions remained below normal for the first three months of 2004 and current snowpack numbers suggest that streamflow conditions will remain below normal for the remainder of 2004. Near normal snowpack accumulation through the end of February 2004 gave hope that relief was in sight. However, since March 1, 2004, the snowpack readings for the Snake River Basin have worsened considerably. IPC's April 28, 2004 snowpack accumulation was 52 percent of normal, compared to 77 percent at the same time a year earlier. Storage levels in selected reservoirs above Brownlee reservoir - IPC's primary storage facility - are only 87 percent of average for this time of year.

The April 29, 2004 Northwest River Forecast Center projection is for 2.8 million acre-feet (maf) of water to flow into Brownlee Reservoir during the April-through-July runoff period. This runoff is 45 percent of the 30-year average of 6.3 maf and reflects the fifth consecutive year of below normal runoff. The impact of below normal streamflows is expected to reduce IPC's hydroelectric generation by approximately 2 million MWh from the original estimates, resulting in IPC's greater reliance on higher-cost thermal generation and purchased power. Expected generation from IPC's hydroelectric facilities is expected to be 6 million MWh for 2004, compared to 2003 generation of 6.1 million MWh and normal generation of 9.3 million MWh.

General Business Revenue: The following table presents IPC's general business revenues and MWh sales for the three months ended March 31:

		Revenue				MWh
		2004		2003		2004	2003
Residential		$	77,727	$	84,209	1,362	1,200
Commercial			40,123		48,410	894	843
Industrial			27,664		42,258	826	769
Irrigation			643		185	10	1
	Total	$	146,157	$	175,062	3,092	2,813

Decreased average rates, resulting from the 2003-2004 PCA, reduced revenue $39 million. IPC filed an application with the IPUC in October 2003 requesting an increase to general rates and in April 2004 filed its 2004-2005 PCA requesting to collect $71 million over proposed base rates, which is $10 million less than the 2003-2004 PCA. New general and PCA rates are expected to be implemented on June 1, 2004 and IPC's general business revenue will be affected by the decisions of the IPUC. 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";

Revenues increased approximately $15 million due primarily to colder weather in January and February 2004. Heating degree-days during the first three months of 2004 were 16.4 percent higher than the same period in 2003. Heating 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 heating;

The expiration in March 2003 of a take-or-pay contract with FMC/Astaris caused a $9 million decrease in revenues. 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

A three percent increase in general business customers increased revenue $3 million.

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 months ended March 31:

	2004		2003

Revenue	$	28,121	$	18,608
MWh sold		673		413
Revenue per MWh	$	41.75	$	45.05

Off-system sales revenue increased $12 million due to increased volumes sold. This increase was partially offset by a $2 million decrease due to lower average prices in the wholesale electricity markets.

Purchased power: The following table presents IPC's purchased power for the three months ended March 31:

		2004		2003
Purchased power:
	Purchases	$	18,505	$	10,476
	Load reduction costs		-		3,129

MWh purchased			421		219
Cost per MWh purchased		$	43.98	$	47.77

Purchased power increased $10 million due to increased volumes purchased, which was primarily driven by colder weather during January and February of 2004. This increase was partially offset by a $2 million decrease due to lower average wholesale power prices. Additionally, there were no load reduction costs in 2004, compared to $3 million in the first quarter of 2003.

Fuel expense: The following table presents IPC's fuel expenses and generation at its thermal generating plants for the three months ended March 31:

	2004		2003
Fuel expense	$	27,504	$	25,538
Thermal MWh generated		1,912		1,831
Cost per MWh	$	14.38	$	13.95

Fuel expenses increased due to a three percent increase in average coal prices and a four percent increase in thermal generation. The largest increase in generation was at the North Valmy Steam Electric Generating Plant.

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, actual 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 months ended March 31:

		2004		2003
Current year power supply cost deferral		$	134	$	377
FMC/Astaris and irrigation program cost deferral			-		(2,245)
Amortization of prior year authorized balances			12,430		53,715
	Total power cost adjustment	$	12,564	$	51,847

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 termination benefit expenses and $2 million of lease termination and other exit-related costs. In the first quarter of 2004, IE paid $0.6 million of involuntary termination benefits and $0.3 million of lease termination and other exit-related costs. The remaining 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.

Because operations have been wound down, there were no material transactions at IE in the quarter ended March 31, 2004. In the first quarter of 2003, IE recorded a net $11 million loss on the settlement of legal disputes with Truckee-Donner Public Utility District, Overton Power District No. 5 and Enron. Also in 2003, IE incurred approximately $7 million of general and administrative expenses for involuntary termination benefit expenses, lease terminations and legal fees.

Income Taxes
Effective Tax Rate: IDACORP's effective tax rate increased to 19.2 percent for the three months ended March 31, 2004 from an effective rate of zero for the same period last year. In the first quarter of 2003, it was expected that available tax benefits from tax credits and regulatory flow-through tax deductions would approximately offset the tax expense on pre-tax book income, resulting in a zero effective tax rate. The current year rate is primarily the result of the increase in pre-tax earnings.

Tax Credits: IFS generates federal income tax credits and accelerated tax depreciation benefits related to its investments in affordable housing and historic rehabilitation developments. Net reductions in consolidated income taxes related to IFS tax credits were approximately $5 million for both the three months ended March 31, 2004 and 2003.

LIQUIDITY AND CAPITAL RESOURCES:

Operating Cash Flows
IDACORP's operating cash flows for the first quarter were $58 million compared to $96 million in last year's first quarter. Of the $38 million decrease, $28 million results from reduced collections from electricity customers in 2004, primarily a result of the PCA decrease, and $15 million is attributable to the wind down of IE. The remaining difference is primarily the result of the timing of income tax payments.

IPC's operating cash flows of $78 million for the first quarter increased $7 million from last year's first quarter. The principal year-to-year variations were the collections from electricity customers discussed above and reduced income tax payments. IPC made no income tax payments in the first quarter of 2004 in comparison to $27 million in the first quarter of 2003.

Insurance Expenses
IPC forecasts that its 2004 medical, property and liability insurance costs will not vary significantly from the amounts recorded in 2003.

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 capital expenditures from 2004 to 2006 are expected to total $643 million, significantly more than the $433 million expended in 2001 through 2003. IPC's construction program is discussed in more detail later in "Capital Requirements." The dividend reduction was also made to improve cash flows and help maintain credit ratings. During the first quarter of 2004, IDACORP paid dividends on common stock of $11 million compared to $18 million in the first quarter of 2003.

Contractual Obligations
There have been no material changes in contractual obligations, outside of the ordinary course of business, since December 31, 2003.

Off-Balance Sheet Arrangements
The federal Surface Mining 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 March 31, 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 Eenergy 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.

Capital Requirements
IDACORP 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. The contribution for internal cash generation is dependent primarily upon IPC's cash flows from operations, which are subject to risks and uncertainties relating to weather and water conditions and IPC's ability to obtain rate relief to cover its operating costs. IPC is in its fifth consecutive year of below normal water conditions and must rely on higher-cost thermal generation and purchased power during these conditions. As such, IDACORP's internally generated cash is expected to provide 70 percent of 2004 capital requirements. 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: Construction expenditures were $37 million for the first quarter of 2004 compared to $25 million in the first quarter of 2003. IPC has made no material changes to its construction program from that reported in the Annual Report on Form 10-K for the year ended December 31, 2003. It expects to spend $207 million, excluding Allowance for Funds Used During Construction (AFDC), in 2004 and a total of $436 million, excluding AFDC, for 2005 and 2006 combined. 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.

Aging facilities, relicensing costs and projected load growth are expected to increase construction expenditures over the next three years. 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 Integrated Resource Plan 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 March 31, 2004, $5 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 approximately $45 million from rates after the plant is completed. Additional construction costs up to a cap of $54 million may also be included in rates after they are found to be reasonable and prudent.

Based upon present environmental laws and regulations, IPC estimates its 2004 capital expenditures for environmental matters, excluding AFDC, will total $21 million. Studies and measures related to environmental concerns at IPC's hydroelectric facilities account for $18 million and investments in environmental equipment and facilities at the thermal plants account for $3 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 March 31, 2004, environmental-related capital expenditures, excluding AFDC, for IPC's hydroelectric facilities totaled $2 million and for thermal plants totaled $0.2 million.

Financing Programs
Credit facilities: On March 17, 2004, IDACORP entered into a $150 million three-year credit agreement with various lenders, Bank One, NA, 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 March 31, 2004, no loans were outstanding and $55 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 until IDACORP's rating falls below Baa3 from Moody's or BBB- from S&P, at which time it equals 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 March 31, 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 March 31, 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 will result in an increase in the cost of borrowing and of maintaining letters of credit, but will 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, 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 March 31, 2004, no loans were outstanding and $38 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 March 31, 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 March 31, 2004, the facility fee was 0.125 percent. A ratings downgrade will result in an increase in the cost of borrowing, but will 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 March 31, 2004, IDACORP's commercial paper borrowings totaled $55 million, compared to $94 million at December 31, 2003. At March 31, 2004, IPC's commercial paper borrowings totaled $38 million and there were no short-term borrowings at December 31, 2003. IPC's March 31, 2004 balance was paid as it matured during the first week of April using short-term investments, which are classified as Cash and Cash Equivalents on the Consolidated Balance Sheets.

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 March 31, 2004, none had been issued.

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 March 31, 2004, IPC could issue under the mortgage approximately $620 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 March 31, 2004, unfunded property additions, which consist of electric property, were approximately $1 billion.

IFS' $20 million Series 2003-1 tax credit note is non-recourse to both IFS and IDACORP. The $14 million Series 2003-2 tax credit note and $23 million of borrowings from a corporate lender are recourse only to IFS.

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 March 31, 2004, the leverage ratios for IDACORP and IPC were 54 percent and 53 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 March 31, 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 March 31, 2004, IDACORP was in compliance with all of the covenants of the facility.

LEGAL AND ENVIRONMENTAL ISSUES:

Legal and Other Proceedings
Vierstra Dairy v. Idaho Power Company: 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 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. The court has yet to rule on the motions. Absent a favorable ruling from the court on the post-trial motions, IPC intends to appeal this decision.

California Energy Proceedings at the FERC:
IE and IPC are involved in a number of FERC proceedings arising out of the California energy situation. They include proceedings involving (1) the chargeback provisions of the California Power Exchange (CalPX) participation agreement, which was triggered when a participant defaulted on a payment to the CalPX. Upon such a default, other participants were required to pay their allocated share of the default amount to the CalPX. This provision was first triggered by the Southern California Edison (SCE) default and later by the Pacific Gas & Electric Company (PG&E) default. The FERC has 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 November 2004. At March 31, 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 March 31, 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 have been appealed to the Court of Appeals for the Ninth Circuit. IE and IPC are unable to predict the outcome of this matter; and (4) two cases which result from a ruling of the United States Court of Appeals for 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. The FERC also issued an order instituting an investigation of anomalous bidding behavior and practices in the western wholesale power markets. IPC has submitted all data and information requested by the FERC Staff and is awaiting FERC action, and IDACORP and IPC believe that any potential penalties imposed by the FERC would not have a material adverse effect on their consolidated financial positions, results of operations or cash flows.

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, 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 five of the right-of-way permits for 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 five rights-of-way for 25 years, including payment of the independently appraised value of the rights-of-way to the Tribes (and the Tribal allottees who own portions of the rights-of-way). The Tribes have not agreed to renew the rights-of-way and have demanded a substantially greater payment of $19 million, including an up-front payment of $4 million with the remainder to be paid over the 25 year term of the permits, or in the alternative $11 million including an up-front payment of $4 million with the remainder paid over the first three years of the permits. These amounts are based on an "opportunity cost" methodology, which calculates the value of the rights-of-way as a percentage of the cost to IPC of relocating the transmission lines off the Reservation. Both parties have discussed potential legal action regarding renewal of the rights-of-way, but no such action has been taken to date. The probable cost of renewing the rights-of-way is difficult to ascertain due to the lack of definitive legal guidelines for the renewals. IPC believes that the amount payable for 25-year rights-of-way should not exceed $11 million, the approximate present value of the offers communicated to date by the Tribes. 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
Threatened and Endangered Snails: In December 1992, the United States Fish and Wildlife Service (USFWS) listed five species of snails that inhabit the middle Snake River as threatened or endangered species under the Endangered Species Act (ESA). In 1995, in preparation for the FERC relicensing of certain of IPC's hydroelectric projects, IPC obtained a permit from the USFWS to study the listed snails. Since that date, IPC has been collecting field data and conducting studies in an effort to determine the status of the listed snails and how they may be affected by a variety of factors, including hydroelectric production, water quality and irrigation practices.

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

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

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

Due to the importance of these snail data to issues pending in the relicensing of IPC's hydroelectric projects and the pending ESA consultation between the FERC and the USFWS, IPC retained the independent scientist that conducted the review to analyze the primary data used to prepare the 1995-2001 snail survey reports and to prepare new and corrected annual reports. In October and November 2003, IPC provided the FERC and the USFWS with revised annual reports for 1995-2001.

By letters dated August 5, 2003, IPC and the USFWS advised the FERC that they initiated efforts to reach a cooperative resolution of outstanding fish and wildlife issues associated with the relicensing of the Mid-Snake and CJ Strike projects, including issues relating to threatened and endangered snails and advised the FERC that they hoped to complete these efforts within 90 days of August 5, 2003. On August 14, 2003, the FERC responded to IPC advising it would not take action on the licenses prior to the expiration of the 90-day period. In subsequent progress reports to the FERC on IPC and the USFWS efforts, IPC and the USFWS requested an additional 90 days to complete their discussions. On December 3, 2003, the FERC advised IPC and the USFWS that it would take no action on the pending applications prior to the expiration of the 90-day period.

On February 12, 2004, IPC, on behalf of itself and the USFWS, presented an Offer of Settlement, including a signed Settlement Agreement and attached Appendices, to the FERC addressing issues associated with the ESA listed threatened and endangered snails and the relicensing of the Mid-Snake and CJ Strike projects. Pursuant to FERC regulations, participants in the licensing proceeding and other interested persons had until March 3, 2004 to comment on the proposed settlement. The Idaho Department of Fish and Game and Idaho Rivers United filed comments with the FERC. IPC responded to the comments on March 25, 2004. The FERC is now considering the settlement. If the proposed settlement is approved by the FERC, it is expected that the FERC and the USFWS will complete ESA consultation on the projects and the FERC will thereafter issue new licenses for the projects. IPC and the USFWS agreed that additional studies and analyses are needed in order to more accurately assess the effect, if any, that the Mid-Snake and CJ Strike 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.

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 (Aquifer), a large underground aquifer that has been estimated to hold between 200-300 maf of water. In certain times of the year, the flows into the Snake River below Milner Dam are heavily dependent on the outflow from springs that are connected to and fed by the Aquifer in the Thousand Springs reach of the Snake River. The majority of IPC's hydroelectric projects are below Milner Dam.

In August 2001, the Idaho Department of Water Resources (IDWR) designated portions of the 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 IDWR 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 IDWR, 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 Aquifer and affecting flows to senior surface water rights. These delivery calls resulted in several administrative actions before the IDWR and a judicial action before the District Court in Ada County, Idaho. Because IPC holds water rights in the Thousand Springs area that are dependent on spring flows and the overall condition of the Aquifer, IPC intervened in these actions to protect its interests and encourage the development of a long-term management plan that will protect the Aquifer from further depletion.

In March 2004, the State of Idaho negotiated an interim agreement between various ground and surface water users in an effort to allow the State to develop short and long-term goals and objectives for effectively managing the 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 Aquifer. As the Aquifer and the Snake River are connected resources, they must be managed conjunctively. Management alternatives that may be considered by the committee include, among others, using surface water from the Snake River to artificially recharge the Aquifer. Recharge, and other management alternatives considered by the Committee, may negatively impact IPC's water rights for hydroelectric generation on the Snake River. As such, IPC will participate in the Interim Committee process and other processes related to the conjunctive management of the Aquifer and Snake River to protect its existing hydroelectric generation water rights.

REGULATORY ISSUES:

General Rate Case
IPC filed an application with the IPUC on October 16, 2003 to increase its general rates an average of 17.7 percent. As originally filed, IPC's revenues would increase $86 million annually based on the proposed 11.2 percent return on equity. An additional component of the filing was a request for interim rate relief of $20 million. The IPUC turned down IPC's request for interim rate relief in Order No. 29403 on December 22, 2003 noting that the denial of interim rate relief was not an indication of the ultimate merits of the case.

In addition, IPC has proposed extensive rate design changes including seasonal rates for most customers, increased fixed charges for smaller customer classes and time of day rates for industrial customers. If approved, the price IPC charges its customers from June to August would reflect IPC's seasonably higher costs of producing or purchasing power. The change would result in summer and non-summer base rates. In connection with the seasonal pricing proposal, IPC recommended the annual PCA rate changes be implemented June 1 each year instead of May 16. If approved, this change would eliminate the need for back-to-back rate changes and the PCA recovery period would be June 1 through May 31.

On February 20, 2004, the IPUC Staff and seven other intervenors filed their testimony with the IPUC. The testimony covered revenue requirement and rate design issues. The IPUC Staff's proposal of $15 million, a three percent overall increase to base rates, was the lowest recommendation of any of the parties. Copies of the parties' increase in base rates testimony and exhibits can be viewed at the IPUC web site. IPC filed its direct rebuttal on March 19, 2004. On rebuttal, IPC lowered the overall requested increase to $70 million annually, an average increase of 14.5 percent. The revised amount includes: updated depreciation rates in accordance with IPUC Case No. IPC-E-03-7, the recognition of lower year-end employment levels than were expected when the case was originally filed and a change in IPC's pension cost recovery method. The IPUC conducted hearings on the matter from March 29 through April 5, 2004.

IPC's proposal requests revenue recovery for certain costs of serving its customers, such as increased operating expenses and substantial demands for infrastructure improvements, increased capital costs for the Protection, Mitigation and Enhancement (PM&E) requirements of new licenses at most of its hydroelectric projects, for the cost of new sources of power and continued expansion of its transmission and distribution network. Because the Idaho jurisdiction does not allow assets that have not been placed in service to be included in the rate base, Bennett Mountain Power Plant and relicensing costs included in Construction Work in Progress are not included in this filing. IPC is requesting an 11.2 percent return on equity and an overall rate of return of 8.3 percent. The success of this rate case is dependent on the IPUC review and approval, which is expected by May 28, 2004, with a June 1, 2004 effective date. IPC is unable to predict what rate relief the IPUC will grant.

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

		March 31,		December 31,
		2004		2003
Oregon deferral		$	13,458	$	13,620
Idaho PCA current year power supply cost deferrals:
	Deferral for 2004-2005 rate year		44,285		44,664
Idaho PCA true-up awaiting recovery:
	Remaining true-up authorized May 2003		1,644		13,646
	Total deferral	$	59,387	$	71,930

On April 15, 2004, IPC filed its 2004-2005 PCA with the IPUC, with a proposed effective date of June 1, 2004 requesting to collect $71 million over proposed base rates, which is $10 million less than the 2003-2004 PCA.

The IPUC issued Order No. 28992 on April 15, 2002 disallowing recovery of the lost revenues. IPC believes that this IPUC order is 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 believes it is 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 issued its decision, which 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. A decision on the reconsideration is pending. IPC submitted its calculation of lost revenues of $12 million in the earlier IPUC proceeding. IPC cannot predict what level of recovery it will receive or the timing of such recovery.

Oregon: IPC is also recovering calendar year 2001 extraordinary power supply costs applicable to the Oregon jurisdiction. In two separate 2001 orders, the OPUC approved rate increases totaling six percent, which was the maximum annual rate of recovery allowed under Oregon state law at that time. These increases 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.

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 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. Approximately 23,000 meters will be installed between April 19, 2004 and December 31, 2004. Phase One is estimated to cost $6 million. IPC will include these costs in future rate filings. 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. Currently, the licenses for five hydroelectric projects have expired. These projects continue to operate under annual licenses until the FERC issues a new multi-year license. Three more of IPC's hydroelectric project licenses will expire by 2010.

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

Projects	Current status
Bliss, Upper Salmon Falls, Lower Salmon	Annual licenses issued under terms and conditions of the expired
Falls, Shoshone Falls and CJ Strike	multi-year license. Final Environmental Impact Statements have
	been issued. Offer of Settlement currently under consideration by the
	FERC. FERC licenses anticipated in 2004.

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

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

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

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

At March 31, 2004, $62 million of relicensing costs were included in Construction Work in Progress and $9 million of relicensing costs were included in Electric Plant in Service. The relicensing costs are recorded and held in Construction Work in Progress until a new multi-year license or annual license is issued by the FERC, at which time the charges are transferred to Electric Plant in Service. Relicensing costs and costs related to the new licenses, as discussed above, will be submitted to regulators for recovery through the rate-making process. The current Idaho general rate case filing includes $10 million of relicensing costs.

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

IPC contested the 1997 petition before the FERC on 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 and is currently under consideration by the court. A decision is expected later in 2004.

Regional Transmission Organizations
In December 1999, the FERC, in its Order No. 2000, said that all companies with transmission assets must file to form Regional Transmission Organizations (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 required transmission owners to provide non-discriminatory transmission service to third parties. By encouraging the formation of RTOs, the FERC seeks to further facilitate the formation of efficient, competitive wholesale electricity markets.

In October 2000 and March 2002, in response to FERC Order No. 2000, IPC and 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. Additional filings will be necessary to include the tariff and integration agreements associated with the new entity. State approvals also need to be obtained. In September 2002, the FERC issued an order granting in part RTO West's Stage Two request for a declaratory order, approving with modification the majority of the proposed plan. With further development of detail and some modification, the FERC stated that the proposal "will satisfy not only the Order No. 2000 requirements, but can also provide a basic framework for standard market design for the West."

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 (SMD) 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 (ISOs). 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 SMD 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, which will manage the region's combined transmission services, operate certain aspects of the combined system such as the transmission reservation and scheduling, provide monitoring of regional power markets, perform comprehensive transmission system-wide planning and facilitate other aspects of the transmission system operation. In March 2004, the RRG unanimously agreed that the name of RTO West should be changed to Grid West.

OTHER MATTERS:

Ida-West
In 2003, IDACORP made the decision to wind down Ida-West's operations. This decision resulted from the development of IDACORP's new corporate strategy. The new strategy does not include the development or acquisition of merchant generation, which had been 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 expects to reduce its workforce from 16 to 12 full-time employees in the second quarter of 2004.

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 March 31, 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: As of March 31, 2004, IDACORP and IPC had $145 million and $91 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 March 31, 2004, interest rate expense would increase and pre-tax earnings would decrease by approximately $1.5 million for IDACORP and $0.9 million for IPC.

Fixed Rate Debt: As of March 31, 2004, IDACORP and IPC had outstanding fixed rate debt of $892 million and $811 million, respectively. The fair market value of this debt was $947 million and $861 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 $77 million for IDACORP and $75 million for IPC if interest rates were to decline by one percentage point from their March 31, 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 the 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, Inc., based on their evaluation of IDACORP, Inc.'s disclosure controls and procedures (as defined in Exchange Act Rule 13a-15(e)) as of March 31, 2004, have concluded that IDACORP, Inc.'s disclosure controls and procedures are effective.

The Chief Executive Officer and Chief Financial Officer of Idaho Power Company, based on their evaluation of Idaho Power Company's disclosure controls and procedures (as defined in Exchange Act Rule 13a-15(e)) as of March 31, 2004, have concluded that Idaho Power Company's disclosure controls and procedures are effective.

(b) Changes in internal control over financial reporting:

There has been no change in IDACORP, Inc.'s or Idaho Power Company's internal control over financial reporting. However, in connection with the IDACORP, Inc. Sarbanes-Oxley 404 internal control process, several weaknesses in Information Technology internal controls over financial reporting related to disclosure controls and procedures have been identified. IDACORP, Inc. is in the process of developing a plan of remediation and expects to complete remediation prior to the filing of the Quarterly Report on Form 10-Q for the quarter ending June 30, 2004. IDACORP, Inc.'s second quarter 10-Q will include a discussion of the changes made in these internal controls.

PART II - OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS

Reference is made to Note 5 to the Consolidated Financial Statements in this Quarterly Report.

ITEM 2. CHANGES IN SECURITIES, USE OF PROCEEDS AND ISSUER PURCHASES OF EQUITY SECURITIES

Issuer Purchases of Equity Securities:

IDACORP, Inc. Common 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
January 1 - January 31, 2004	-	$	-
February 1 - February 29, 2004	45,988 (1)		30.88
March 1 - March 31, 2004	-		-
Total	45,988	$	30.88

(1) These shares were purchased on the open market in connection with grants made under the Restricted Stock Plan.

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
January 1 - January 31, 2004	210	$	79.99
February 1 - February 29, 2004	100		78.98
March 1 - March 31, 2004	43		84.74
Total	353(1)	$	80.29

(1)These shares of 4% preferred stock were repurchased and retired.

ITEM 5. OTHER INFORMATION

Board of Directors
Thomas J. Wilford was elected to the IDACORP, Inc. and Idaho Power Company Boards of Directors on March 18, 2004.

Joan H. Smith was elected to the IDACORP, Inc. and Idaho Power Company Boards of Directors effective May 20, 2004.

ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K

(a) Exhibits.

*Previously Filed and Incorporated Herein by Reference

Exhibit	File Number	As Exhibit

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

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

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

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

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

*10(h)(v)1	1-14465 1-3198 Form 10-K for 2002	10(h)(v)	IDACORP, Inc. Non-Employee Directors Stock Compensation Plan as of May 17, 1999, as amended.

*10(h)(vi)	1-14465 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)(vii)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(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).

1 Compensatory plan

*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)

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

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

15			Letter Re: Unaudited Interim Financial Information.

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

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

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

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

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

32(a)			Section 1350 certification.

32(b)			Section 1350 certification.

99			Earnings press release for first quarter 2004.

(b) Reports on SEC Form 8-K. The following Reports on Form 8-K were filed for the three months ended March 31, 2004:

Items Reported		Date of Report	Date Filed	Filed by
Item 12 - Results of Operations and
	Financial Condition	February 5, 2004	February 5, 2004	IDACORP, Inc. and IPC
Item 5 - Other Events and Regulation FD Disclosure		February 10, 2004	February 11, 2004	IDACORP, Inc. and IPC
Item 5 - Other Events and Regulation FD Disclosure		March 18, 2004	March 22, 2004	IDACORP, Inc. and IPC
Item 5 - Other Events and Regulation FD Disclosure		March 18, 2004	April 13, 2004	IDACORP, Inc. and IPC
Item 7 - Financial Statements and Exhibits		March 25, 2004	March 25, 2004	IPC
Item 5 - Other Events and Regulation FD Disclosure		March 30, 2004	April 1, 2004	IDACORP, Inc. and IPC

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	May 6, 2004	By:	/s/	Jan B. Packwood
				Jan B. Packwood
				President and Chief Executive Officer
				and Director

Date	May 6, 2004	By:	/s/	Darrel T. Anderson
				Darrel T. Anderson
				Vice President, Chief Financial Officer
				and Treasurer
				(Principal Accounting Officer)

SIGNATURES

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

IDAHO POWER COMPANY

(Registrant)

Date	May 6, 2004	By:	/s/	J. LaMont Keen
				J. LaMont Keen
				President and Chief Operating Officer

Date	May 6, 2004	By:	/s/	Darrel T. Anderson
				Darrel T. Anderson
				Vice President, Chief Financial Officer
				and Treasurer
				(Principal Accounting Officer)

EXHIBIT INDEX


Exhibit Number

10(h)(i) 1		The Revised Security Plan for Senior Management Employees - a non-qualified, deferred
		compensation plan, amended and restated effective November 20, 2003.

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

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

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

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

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

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

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

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

15		Letter Re: Unaudited Interim Financial Information.

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

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

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

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

32(a)		Section 1350 certification.

32(b)		Section 1350 certification.

99		Earnings press release for first 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 site: www.idacorpinc.com

IDACORP, Inc.:	38,184,622
Idaho Power Company:	39,150,812, all held by IDACORP, Inc.

	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
ALJ	-	Administrative Law Judge
Cal ISO	-	California Independent System Operator
CalPX	-	California Power Exchange
EPS	-	Earning per share
ESA	-	Endangered Species Act
FERC	-	Federal Energy Regulatory Commission
FIN	-	Financial Accounting Standards Board Interpretation
FPA	-	Federal Power Act
GAAP	-	Accounting Principles Generally Accepted in the United States of
			America
HCC	-	Hells Canyon Complex
Ida-West	-	Ida-West Energy, a subsidiary of IDACORP, Inc.
IE	-	IDACORP Energy, a subsidiary of IDACORP, Inc.
IFS	-	IDACORP Financial Services, a subsidiary of IDACORP, Inc.
IPC	-	Idaho Power Company, a subsidiary of IDACORP, Inc.
IPUC	-	Idaho Public Utilities Commission
maf	-	Million acre-feet
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
NPC	-	Nevada Power Company
OPUC	-	Oregon Public Utility Commission
PCA	-	Power Cost Adjustment
PM&E	-	Protection, Mitigation and Enhancement
PMC	-	Plaintiff's Master Complaint
REA	-	Rural Electrification Administration
RTOs	-	Regional Transmission Organizations
S&P	-	Standard & Poor's Ratings Services
SFAS	-	Statement of Financial Accounting Standards
VIEs	-	Variable Interest Entities
WSPP	-	Western Systems Power Pool

Page

Part I. Financial Information:
	Item 1. Financial Statements (unaudited)
		IDACORP, Inc.:
			Consolidated Statements of Operations	1
			Consolidated Balance Sheets	2-3
			Consolidated Statements of Cash Flows	4
			Consolidated Statements of Comprehensive Income (Loss)	5
			Notes to Consolidated Financial Statements	6-22
			Independent Accountants' Report	23
		Idaho Power Company:
			Consolidated Statements of Income	25
			Consolidated Balance Sheets	26-27
			Consolidated Statements of Capitalization	28
			Consolidated Statements of Cash Flows	29
			Consolidated Statements of Comprehensive Income	30
			Notes to Consolidated Financial Statements	31
			Independent Accountants' Report	32

	Item 2. Management's Discussion and Analysis of Financial
		Condition and Results of Operations		33-56

	Item 3. Quantitative and Qualitative Disclosures about Market Risk			56-57

	Item 4. Controls and Procedures			57

Part II. Other Information:

	Item 1. Legal Proceedings			58

	Item 2. Changes in Securities, Use of Proceeds and Issuer Purchases of Equity
		Securities		58

	Item 5. Other Information			58

	Item 6. Exhibits and Reports on Form 8-K			59-65

Signatures				66-67

Three Months Ended

Number