IDAHO POWER CO - 10-Q Quarterly Report

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

				Three Months Ended March 31,
				2005		2004
				(thousands of dollars except for per
				share amounts)
Operating Revenues:
	Electric utility:
		General business		$	146,370	$	146,157
		Off-system sales			32,212		28,121
		Other revenues			12,286		9,325
			Total electric utility revenues		190,868		183,603
	Other				5,314		4,586
		Total operating revenues			196,182		188,189

Operating Expenses:
	Electric utility:
		Purchased power			44,078		18,505
		Fuel expense			25,096		27,504
		Power cost adjustment			(4,417)		12,564
		Other operations and maintenance			55,098		54,146
		Depreciation			24,919		24,890
		Taxes other than income taxes			5,227		5,565
			Total electric utility expenses		150,001		143,174
	Other				11,284		8,821
			Total operating expenses		161,285		151,995

Operating Income (Loss):
	Electric utility				40,867		40,429
	Other				(5,970)		(4,235)
		Total operating income			34,897		36,194

Other Income					4,273		3,018

Earnings of Unconsolidated Equity-method Investments					663		614

Other Expenses					1,103		822

Interest Expense and Preferred Dividends:
	Interest on long-term debt				14,075		13,353
	Other interest				455		453
	Preferred dividends of Idaho Power Company				-		854
		Total interest expense and preferred dividends			14,530		14,660

Income Before Income Taxes					24,200		24,344

Income Tax Expense					1,134		4,685

Net Income				$	23,066	$	19,659

Weighted Average Common Shares Outstanding (000's)					42,210		38,200
Earnings Per Share of Common Stock (basic and diluted)				$	0.55	$	0.51
Dividends Paid Per Share of Common Stock				$	0.30	$	0.30

The accompanying notes are an integral part of these statements.

IDACORP, Inc.
Consolidated Balance Sheets
(unaudited)

			March 31,		December 31,
			2005		2004
Assets			(thousands of dollars)

Current Assets:
	Cash and cash equivalents		$	61,384	$	23,403
	Receivables:
		Customer		93,562		92,258
		Allowance for uncollectible accounts		(42,631)		(43,108)
		Employee notes		3,253		3,523
		Other		5,684		8,806
	Energy marketing assets			17,490		9,203
	Accrued unbilled revenues			24,908		33,832
	Materials and supplies (at average cost)			31,054		28,008
	Fuel stock (at average cost)			12,920		6,539
	Prepayments			20,901		30,035
	Deferred income taxes			25,192		23,407
	Regulatory assets			3,396		5,510
		Total current assets		257,113		221,416

Investments				188,018		223,061

Property, Plant and Equipment:
	Utility plant in service			3,400,764		3,324,816
	Accumulated provision for depreciation			(1,334,096)		(1,316,125)
		Utility plant in service - net		2,066,668		2,008,691
	Construction work in progress			110,387		152,427
	Utility plant held for future use			2,611		2,636
	Other property, net of accumulated depreciation			44,664		45,708
		Property, plant and equipment - net		2,224,330		2,209,462

Other Assets:
	American Falls and Milner water rights			31,585		31,585
	Company-owned life insurance			35,738		35,765
	Energy marketing assets - long-term			26,124		16,635
	Regulatory assets			437,882		433,271
	Long-term receivables (net of allowance of $2,578)			3,343		2,895
	Employee notes			3,490		3,746
	Goodwill			13,659		13,659
	Other			44,113		42,677
		Total other assets		595,934		580,233

		Total	$	3,265,395	$	3,234,172

The accompanying notes are an integral part of these statements.

IDACORP, Inc.
Consolidated Balance Sheets
(unaudited)

				March 31,		December 31,
				2005		2004
Liabilities and Shareholders' Equity				(thousands of dollars)

Current Liabilities:
	Current maturities of long-term debt			$	77,811	$	78,603
	Notes payable				53,700		36,270
	Accounts payable				52,574		79,156
	Energy marketing liabilities				17,986		9,420
	Taxes accrued				48,248		46,318
	Interest accrued				22,473		14,426
	Other				25,787		21,265
		Total current liabilities			298,579		285,458

Other Liabilities:
	Deferred income taxes				557,320		555,774
	Energy marketing liabilities - long-term				26,124		16,635
	Regulatory liabilities				277,168		275,854
	Other				110,667		112,616
		Total other liabilities			971,279		960,879

Long-Term Debt					977,563		979,549

Commitments and Contingencies

Shareholders' Equity:
	Common stock, no par value (shares authorized 120,000,000; 42,436,741
		and 42,373,758 shares issued, respectively)			592,422		589,440
	Retained earnings				434,713		424,312
	Accumulated other comprehensive loss				(1,776)		(888)
	Treasury stock (241,241 and 156,741 shares at cost, respectively)				(7,385)		(4,578)
		Total shareholders' equity			1,017,974		1,008,286

			Total	$	3,265,395	$	3,234,172

The accompanying notes are an integral part of these statements.

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

				Three Months Ended
				March 31,
				2005		2004
				(thousands of dollars)
Operating Activities:
	Net income			$	23,066	$	19,659
	Adjustments to reconcile net income to net cash provided by
		operating activities:
		Unrealized losses from energy marketing activities			279		-
		Depreciation and amortization			30,611		30,667
		Deferred taxes and investment tax credits			2,644		(1,498)
		Changes in regulatory assets and liabilities			(7,873)		12,488
		Change in:
			Accounts receivables and prepayments		10,316		(4,614)
			Accounts payable and other accrued liabilities		(26,586)		(27,077)
			Taxes receivable/accrued		1,930		10,303
			Other current assets		247		7,310
			Other current liabilities		11,824		7,319
		Other assets			(4,001)		361
		Other liabilities			1,140		2,996
			Net cash provided by operating activities		43,597		57,914

Investing Activities:
	Additions to property, plant and equipment				(40,725)		(38,023)
	Sale of non-utility assets				591		9
	Purchase of available-for-sale securities				(74,606)		(4,388)
	Sale of available-for-sale securities				106,915		5,111
	Purchase of held-to-maturity securities				(787)		-
	Maturity of held-to-maturity securities				1,153		701
	Other assets				2		95
	Other liabilities				-		(565)
		Net cash used in investing activities			(7,457)		(37,060)

Financing Activities:
	Issuance of long-term debt				-		50,000
	Retirement of long-term debt				(2,832)		(51,978)
	Dividends on common stock				(12,665)		(11,466)
	Change in short-term borrowings				17,430		(1,550)
	Acquisition of treasury shares				-		(1,420)
	Other assets				(92)		45
	Other liabilities				-		(7)
		Net cash provided by (used in) financing activities			1,841		(16,376)

Net increase in cash and cash equivalents					37,981		4,478

Cash and cash equivalents beginning of period					23,403		75,159

Cash and cash equivalents end of period				$	61,384	$	79,637

Supplemental Disclosure of Cash Flow Information:
	Cash paid during the period for:
		Income taxes		$	2	$	1
		Interest (net of amount capitalized)		$	5,859	$	4,738

The accompanying notes are an integral part of these statements.

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

				Three Months Ended
				March 31,
				2005		2004
				(thousands of dollars)

Net Income				$	23,066	$	19,659

Other Comprehensive Income (Loss):
	Unrealized gains (losses) on securities:
		Unrealized holding gains (losses) arising during the period,
			net of tax of ($274) and $349		(524)		615
		Reclassification adjustment for gains included
			in net income, net of tax of ($234) and ($164)		(364)		(255)
			Net unrealized gains (losses)		(888)		360

Total Comprehensive Income				$	22,178	$	20,019

The accompanying notes are an integral part of these statements.

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Idaho Power Company
Consolidated Statements of Income
(unaudited)

			Three Months Ended
			March 31,
			2005		2004
			(thousands of dollars)
Operating Revenues:
	General business		$	146,370	$	146,157
	Off-system sales			32,212		28,121
	Other revenues			11,878		9,048
		Total operating revenues		190,460		183,326

Operating Expenses:
	Operation:
		Purchased power		44,078		18,505
		Fuel expense		25,096		27,504
		Power cost adjustment		(4,417)		12,564
		Other		41,219		39,623
	Maintenance			13,441		13,821
	Depreciation			24,919		24,890
	Taxes other than income taxes			5,227		5,565
		Total operating expenses		149,563		142,472

Income from Operations				40,897		40,854

Other Income (Expense):
	Allowance for equity funds used during construction			1,455		1,002
	Earnings of unconsolidated equity-method investments			3,901		3,607
	Other income			2,705		2,135
	Other expense			(1,677)		(1,586)
		Total other income		6,384		5,158

Interest Charges:
	Interest on long-term debt			13,176		12,336
	Other interest			860		999
	Allowance for borrowed funds used during construction			(736)		(755)
		Total interest charges		13,300		12,580

Income Before Income Taxes				33,981		33,432

Income Tax Expense				12,472		13,169

Net Income				21,509		20,263

	Dividends on Preferred Stock			-		854

Earnings on Common Stock			$	21,509	$	19,409

The accompanying notes are an integral part of these statements.

Idaho Power Company
Consolidated Balance Sheets
(unaudited)

				March 31,		December 31,
				2005		2004
Assets				(thousands of dollars)

Electric Plant:
	In service (at original cost)			$	3,400,764	$	3,324,816
	Accumulated provision for depreciation				(1,334,096)		(1,316,125)
		In service - net			2,066,668		2,008,691
	Construction work in progress				109,080		151,652
	Held for future use				2,611		2,636

			Electric plant - net		2,178,359		2,162,979

Investments and Other Property					56,021		86,086

Current Assets:
	Cash and cash equivalents				55,758		17,679
	Receivables:
		Customer			47,094		45,441
		Allowance for uncollectible accounts			(886)		(1,363)
		Notes			3,151		3,129
		Employee notes			3,253		3,523
		Related parties			405		1,298
		Other			1,798		5,253
	Accrued unbilled revenues				24,908		33,832
	Materials and supplies (at average cost)				28,468		26,065
	Fuel stock (at average cost)				12,920		6,539
	Prepayments				19,588		28,449
	Regulatory assets				3,396		5,510

			Total current assets		199,853		175,355


Deferred Debits:
	American Falls and Milner water rights				31,585		31,585
	Company-owned life insurance				35,738		35,765
	Regulatory assets				437,882		433,271
	Employee notes				3,490		3,746
	Other				40,297		40,425

			Total deferred debits		548,992		544,792

	Total			$	2,983,225	$	2,969,212

The accompanying notes are an integral part of these statements.

Idaho Power Company
Consolidated Balance Sheets
(unaudited)

				March 31,		December 31,
				2005		2004
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			483,707		483,707
		Capital stock expense			(2,097)		(2,097)
		Retained earnings			348,952		340,107
		Accumulated other comprehensive loss			(1,776)		(888)

			Total common stock equity		926,663		918,706

	Long-term debt				923,963		923,910

			Total capitalization		1,850,626		1,842,616

Current Liabilities:
	Long-term debt due within one year				60,000		60,000
	Accounts payable				48,153		74,642
	Notes and accounts payable to related parties				266		278
	Taxes accrued				63,092		42,228
	Interest accrued				21,454		13,743
	Deferred income taxes				3,396		5,510
	Other				23,653		18,103

			Total current liabilities		220,014		214,504

Deferred Credits:
	Deferred income taxes				544,143		542,829
	Regulatory liabilities				277,168		275,854
	Other				91,274		93,409

			Total deferred credits		912,585		912,092


Commitments and Contingencies

			Total	$	2,983,225	$	2,969,212

The accompanying notes are an integral part of these statements.

Idaho Power Company
Consolidated Statements of Capitalization
(unaudited)

				March 31,				December 31,
				2005		%		2004		%
				(thousands of dollars)
Common Stock Equity:
	Common stock			$	97,877			$	97,877
	Premium on capital stock				483,707				483,707
	Capital stock expense				(2,097)				(2,097)
	Retained earnings				348,952				340,107
	Accumulated other comprehensive loss				(1,776)				(888)
		Total common stock equity			926,663		50		918,706		50

Long-Term Debt:
	First mortgage bonds:
		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				50,000
		5.875% Series due 2034			55,000				55,000
			Total first mortgage bonds		785,000				785,000
		Amount due within one year			(60,000)				(60,000)
			Net first mortgage bonds		725,000				725,000

	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

	American Falls bond guarantee				19,885				19,885
	Milner Dam note guarantee				11,700				11,700
	Unamortized premium/discount - net				(3,082)				(3,135)

			Total long-term debt		923,963		50		923,910		50

Total Capitalization				$	1,850,626		100	$	1,842,616		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,
				2005		2004
				(thousands of dollars)
Operating Activities:
	Net income			$	21,509	$	20,263
	Adjustments to reconcile net income to net cash provided by
		operating activities:
		Depreciation and amortization			26,676		27,432
		Deferred taxes and investment tax credits			2,083		(4,613)
		Changes in regulatory assets and liabilities			(7,873)		12,488
		Change in:
			Accounts receivables and prepayments		11,334		(3,454)
			Accounts payable		(26,488)		(13,314)
			Taxes receivable/accrued		20,864		22,074
			Other current assets		890		6,981
			Other current liabilities		12,512		7,133
		Other assets			(4,127)		187
		Other liabilities			(238)		2,770
			Net cash provided by operating activities		57,142		77,947

Investing Activities:
	Additions to utility plant				(38,719)		(37,181)
	Purchase of available-for-sale securities				(74,606)		(4,388)
	Sale of available-for-sale securities				106,915		5,111
	Other assets				104		(5,580)
	Other liabilities				-		5,416
		Net cash used in investing activities			(6,306)		(36,622)

Financing Activities:
	Issuance of long-term debt				-		50,000
	Retirement of long-term debt				-		(50,020)
	Dividends on common stock				(12,665)		(11,466)
	Dividends on preferred stock				-		(854)
	Increase in short-term borrowings				-		37,599
	Other assets				(92)		(28)
		Net cash provided by (used in) financing activities			(12,757)		25,231

Net increase in cash and cash equivalents					38,079		66,556

Cash and cash equivalents at beginning of period					17,679		4,031

Cash and cash equivalents at end of period				$	55,758	$	70,587

Supplemental Disclosure of Cash Flow Information:
	Cash paid (received) during the period for:
		Income taxes received from parent		$	(7,037)	$	-
		Interest (net of amount capitalized)		$	4,989	$	3,996

The accompanying notes are an integral part of these statements.

Idaho Power Company
Consolidated Statements of Comprehensive Income
(unaudited)

				Three Months Ended
				March 31,
				2005		2004
				(thousands of dollars)

Net Income				$	21,509	$	20,263

Other Comprehensive Income (Loss):
	Unrealized gains (losses) on securities:
		Unrealized holding gains (losses) arising during the period,
			net of tax of ($274) and $349		(524)		615
		Reclassification adjustment for gains included
			in net income, net of tax of ($234) and ($164)		(364)		(255)
			Net unrealized gains (losses)		(888)		360

Total Comprehensive Income				$	20,621	$	20,623

The accompanying notes are an integral part of these statements.

IDACORP, Inc. AND IDAHO POWER COMPANY
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
(unaudited)

1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES:

This Quarterly Report on Form 10-Q is a combined report of IDACORP, Inc. (IDACORP) and Idaho Power Company (IPC). Therefore, the Notes to the Consolidated Financial Statements apply to both IDACORP and IPC. However, IPC makes no representation as to the information relating to IDACORP's other operations.

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

IPC is an electric utility 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:

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

IdaTech, LLC - developer of integrated fuel cell systems;

IDACOMM, Inc. - provider of telecommunications services and commercial and residential Internet services; and

Ida-West Energy Company - operator of small hydroelectric generation projects that satisfy the requirements of the Public Utilities Regulatory Policy Act of 1978.

IDACORP Energy (IE), a marketer of electricity and natural gas, wound down its operations in 2003.

Principles of Consolidation
The consolidated financial statements of IDACORP and IPC include the accounts of each company and their majority-owned subsidiaries, including variable interest entities for which the companies are the primary beneficiaries. All significant intercompany balances have been eliminated in consolidation. Investments in business entities that IDACORP and IPC do not consolidate, but have the ability to exercise significant influence over operating and financial policies, are accounted for using the equity method.

Financial Statements
In the opinion of IDACORP and IPC, the accompanying unaudited consolidated financial statements contain all adjustments necessary to present fairly their consolidated financial positions as of March 31, 2005, and consolidated results of operations and consolidated cash flows for the three months ended March 31, 2005 and 2004. 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, 2004. 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 1,051,114 common stock options for the three months ended March 31, 2005, because the options' exercise prices were greater than the average market price of the common stock during the period. For the same period in 2004, 849,700 options were excluded from the diluted EPS calculation for the same reason. In total, 1,440,114 options were outstanding at March 31, 2005, with expiration dates between 2010 and 2015.

Stock-Based Compensation
Stock-based employee compensation is accounted for under the recognition and measurement principles of Accounting Principles Board (APB) Opinion 25, "Accounting for Stock Issued to Employees," and related interpretations. Grants of performance shares are reflected in net income based on the market value at the award date or the period-end price for shares not yet vested. Grants of restricted stock are reflected in net income based on the market value on the grant date. No stock-based employee compensation cost is reflected in net income for stock options, as all options granted had an exercise price equal to the market value of the underlying common stock on the date of grant. IDACORP and IPC have adopted the disclosure only provision of Statement of Financial Accounting Standards (SFAS) 123, "Accounting for Stock-Based Compensation."

The following tables illustrate the effect on IDACORP's net income and EPS and IPC's net income if the fair value recognition provisions of SFAS 123 had been applied to stock-based employee compensation (in thousands of dollars except for per share amounts).

			Three Months Ended
			March 31,
IDACORP:			2005		2004

Net income, as reported			$	23,066	$	19,659
Add: Stock-based employee compensation expense included in reported net income, net of
	related tax effects			175		121
Deduct: Total stock-based employee compensation expense determined under fair value
	based method for all awards, net of related tax effects			415		344
		Pro forma net income	$	22,826	$	19,436
EPS of common stock:
	Basic and diluted - as reported		$	0.55	$	0.51
	Basic and diluted - pro forma		$	0.54	$	0.51

IPC:

Net income, as reported			$	21,509	$	20,263
Add: Stock-based employee compensation expense included in reported net income,
	net of related tax effects			99		96
Deduct: Total stock-based employee compensation expense determined under fair value
	based method for all awards, net of related tax effects			301		264
		Pro forma net income	$	21,307	$	20,095

For purposes of these pro forma calculations, the estimated fair value of the performance shares, restricted stock and stock options is amortized to expense over the vesting period. The fair value of the performance shares and restricted stock is the market price of the stock on the date of grant. The fair value of a stock option award is estimated at the date of grant using a binomial option-pricing model. Expense related to forfeited performance shares, restricted stock and stock options is reversed in the period in which the forfeit occurs.

Reclassifications
Certain items previously reported for periods prior to March 31, 2005 have been reclassified to conform to the current period's presentation. Net income and shareholders' equity were not affected by these reclassifications.

New Accounting Pronouncements
SFAS 151: In November 2004, the Financial Accounting Standards Board (FASB) issued SFAS 151, "Inventory Costs," which clarifies the accounting for certain inventory-related costs. SFAS 151 will be effective for inventory costs incurred during fiscal years beginning after June 15, 2005, and is not expected to have a material effect on IDACORP's or IPC's financial statements.

SFAS 153: In December 2004, the FASB issued SFAS 153, "Exchanges of Nonmonetary Assets," which amends existing guidance on accounting for nonmonetary transactions. SFAS 153 will be effective for exchanges occurring in fiscal periods beginning after June 15, 2005, and is not expected to have a material effect on IDACORP's or IPC's financial statements.

SFAS 123(R): In December 2004, the FASB issued SFAS 123 (revised 2004), "Share-Based Payment," which revises SFAS 123 and supersedes APB 25 and its related implementation guidance. SFAS 123(R) establishes standards for the accounting for transactions in which an entity exchanges its equity instruments for goods or services. It also addresses transactions in which an entity incurs liabilities in exchange for goods or services that are based on the fair value of the entity's equity instruments or that may be settled by the issuance of those equity instruments. SFAS 123(R) focuses primarily on accounting for transactions in which an entity obtains employee services in share-based payment transactions.

Under the provisions of SFAS 123(R), the fair value of all stock options must be reported as an expense on the financial statements. IDACORP and IPC currently apply the measurement provisions of APB 25 and the disclosure-only provisions of SFAS 123. SFAS 123(R) also changes other measurement, timing and disclosure rules relating to share-based payments.

In April 2005, the staff of the Securities and Exchange Commission issued Staff Accounting Bulletin (SAB) 107 to provide additional guidance regarding the application of SFAS 123(R). SAB 107 permits registrants to choose an appropriate valuation technique or model to estimate the fair value of share options, assuming consistent application, and provides guidance for the development of assumptions used in the valuation process. Additionally, SAB 107 discusses disclosures to be made under "Management's Discussion and Analysis of Financial Condition and Results of Operations" in registrants' periodic reports.

Based upon Securities and Exchange Commission rules issued in April 2005, SFAS 123(R) is effective for fiscal years that begin after June 15, 2005 and will be adopted by IDACORP and IPC in the first quarter of 2006. Adoption is not expected to have a material effect on IDACORP's or IPC's financial statements.

FSP FAS 106-2: See Note 8 for a discussion of this FASB Staff Position (FSP), which relates to postretirement benefit obligations.

FIN 47: In March 2005 the FASB issued Interpretation (FIN) 47, "Accounting for Conditional Asset Retirement Obligations." FIN 47 clarifies that the term "conditional asset retirement obligation" as used in SFAS 143, "Accounting for Asset Retirement Obligations," refers to a legal obligation to perform an asset retirement activity in which the timing and/or method of settlement are conditional on a future event that may or may not be within the control of the entity. FIN 47 clarifies that uncertainty about the timing and/or method of settlement of a conditional asset retirement obligation should be factored into the measurement of the liability when sufficient information exists to make a reasonable estimate of the fair value of the obligation. FIN 47 also provides guidance on when an entity would have sufficient information to recognize a liability and indicators that would preclude an entity from recognizing a liability for such obligations. FIN 47 will be effective for fiscal years ending after December 15, 2005. IDACORP and IPC are currently reviewing the provisions of FIN 47 to determine its effect on their financial statements.

2. INCOME TAXES:

In accordance with interim reporting requirements, IDACORP and IPC use an estimated annual effective tax rate for computing their provisions for income taxes on an interim basis. IDACORP's effective rate for the three months ended March 31, 2005 was 4.7 percent, compared to 19.2 percent for the three months ended March 31, 2004. IPC's effective tax rate for the three months ended March 31, 2005 was 36.7 percent, compared to 39.4 percent for the three months ended March 31, 2004. The difference in estimated annual effective rates is primarily due to the timing and amount of regulatory flow-through tax adjustments at IPC, variation in the level of pre-tax earnings at IPC and the impact of tax credits at IFS.

3. COMMON STOCK:

During the three months ended March 31, 2005, IDACORP issued 62,983 original issue shares pursuant to the 2000 Long-Term Incentive and Compensation Plan for the 2005 restricted stock and performance share grants and purchased 11,925 shares on the open market and issued such shares to non-employee IDACORP directors as part of their compensation. Additionally, shareholders of an acquired business forfeited back to IDACORP the remaining 21,510 shares related to a 2001 contingent payment.

4. FINANCING:

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

				March 31,		December 31,
				2005		2004
First mortgage bonds:
	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		50,000
	5.875% Series due 2034				55,000		55,000
			Total first mortgage bonds		785,000		785,000
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

American Falls bond guarantee					19,885		19,885
Milner Dam note guarantee					11,700		11,700
Unamortized premium/(discount) - net					(3,082)		(3,135)
Debt related to investments in affordable housing					63,538		66,310
Other subsidiary debt					7,873		7,932
	Total				1,055,374		1,058,152
Current maturities of long-term debt					(77,811)		(78,603)

			Total long-term debt	$	977,563	$	979,549

(a)		Humboldt County Pollution Control Revenue bonds are secured by first mortgage bonds, bringing the total first
		mortgage bonds outstanding at March 31, 2005 to $834.8 million.

Long-Term Financing
IDACORP currently has $679 million remaining on two shelf registration statements that can be used for the issuance of unsecured debt (including medium-term notes) and preferred or common stock. IPC currently has in place two registration statements that can be used for the issuance of an aggregate principal amount of $300 million of first mortgage bonds (including medium-term notes) and unsecured debt.

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. The indenture requires that IPC's net earnings must be at least twice the annual interest requirements on all outstanding debt of equal or prior rank, including the bonds that IPC may propose to issue. Under certain circumstances, the net earnings test does not apply, including the issuance of refunding bonds to retire outstanding bonds which mature in less than two years or which are of an equal or higher interest rate, or prior lien bonds.

As of March 31, 2005, IPC could issue under the mortgage approximately $392 million of additional first mortgage bonds based on retired first mortgage bonds and $719 million of additional first mortgage bonds based on unfunded property additions. As of March 31, 2005, unfunded property additions were approximately $1.2 billion. Property additions consist of electric or gas property, or property used in connection therewith. Property additions exclude securities, contracts or choses in action, merchandise and equipment for consumption or resale, materials and supplies, property used principally for production or gathering of natural gas, or any power sites and uncompleted works under Idaho state permits. In determining net property additions, IPC deducts all retired funded property from gross property additions except to the extent of certain credits for released funded property.

The mortgage requires IPC to spend or appropriate 15 percent of its annual gross operating revenues for maintenance, retirement or amortization of its properties. IPC may, however, anticipate or make up these expenditures or appropriations within the five years that immediately follow or precede a particular year.

The mortgage secures all bonds issued under the indenture equally and ratably, without preference, priority or distinction. IPC may issue additional first mortgage bonds in the future, and those first mortgage bonds will also be secured by the mortgage. The lien of the indenture constitutes a first mortgage on all the properties of IPC, subject only to certain limited exceptions including liens for taxes and assessments that are not delinquent and minor excepted encumbrances. Certain of the properties of IPC are subject to easements, leases, contracts, covenants, compensation awards and similar encumbrances and minor defects and clouds common to properties. The mortgage does not create a lien on revenues or profits, or notes or accounts receivable, contracts or choses in action, except as permitted by law during a completed default, securities or cash, except when pledged or merchandise or equipment manufactured or acquired for resale. The mortgage creates a lien on the interest of IPC in property subsequently acquired, other than excepted property, subject to limitations in the case of consolidation, merger or sale of substantially all of the assets of IPC.

On April 20, 2005, IPC entered into a forward-starting interest rate swap agreement, totaling $60 million, in order to manage the risk of changes in interest rates affecting the amount of future interest payments. This interest rate swap agreement relates to the anticipated issuance of first mortgage bonds to refinance the $60 million 5.83% First Mortgage Bonds that mature in September 2005. Under the term of this agreement, the value of the interest rate swap is determined based upon IPC paying a fixed rate and receiving a variable rate based on LIBOR for a 30 year term beginning in September 2005. The interest rate swap agreement provides for a mandatory early settlement date of September 30, 2005. The agreement will be accounted for in accordance with SFAS 133, "Accounting for Derivative Instruments and Hedging Activities." IPC expects to defer any gains or losses and related expenses for recovery through the regulatory process.

At March 31, 2005, IFS had $64 million of debt related to investments in affordable housing with interest rates ranging from 3.65 percent to 8.59 percent due between 2005 and 2010. The investments in affordable housing developments that collateralize this debt had a net book value of $107 million at March 31, 2005. IFS's $17 million Series 2003-1 tax credit note is non-recourse to both IFS and IDACORP. The $11 million Series 2003-2 tax credit note and other outstanding debt are recourse only to IFS.

Credit Facilities
On May 3, 2005, IDACORP entered into a $150 million five-year credit agreement with various lenders. The new IDACORP facility replaced IDACORP's three-year $150 million credit agreement that would have expired on March 16, 2007. The IDACORP facility, which will be used for general corporate purposes and commercial paper back-up, will terminate on March 31, 2010. At March 31, 2005, no loans were outstanding on IDACORP's previous three-year credit facility and $54 million of commercial paper was outstanding.

Under its facility, IDACORP pays (a) a facility fee on the commitment, quarterly in arrears, based on its rating for senior unsecured long-term debt securities without third-third party credit enhancement as provided by Moody's Investors Services (Moody's) and Standard & Poor's Ratings Services (S&P) and (b) a utilization fee, 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 which is applied to the unpaid principal amount of each loan during such periods the outstanding credit exposure under the IDACORP facility exceeds 50 percent of the aggregate commitments under the IDACORP facility. 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 at a per annum rate of 0.125 percent on the average daily undrawn stated amount under each letter of credit, payable quarterly in arrears and (iii) documentary and processing charges in accordance with the letter of credit issuer's standard schedule for such charges. At closing, IDACORP paid each of the lenders an upfront fee to secure the commitments of each lender under the facility and an arrangement fee for each bank that arranged and structured the facilities.

At March 31, 2005, IPC had regulatory authority to incur up to $250 million of short-term indebtedness. On May 3, 2005, IPC entered into a $200 million five-year credit agreement with various lenders. The new IPC facility replaced IPC's three-year $200 million credit agreement that would have expired on March 16, 2007. The new IPC facility, which expires on March 31, 2010, will be used for general corporate purposes and commercial paper back-up. At March 31, 2005, no loans were outstanding on IPC's previous three-year credit facility and no commercial paper was outstanding.

Under its facility, IPC pays (a) a facility fee on the commitment, quarterly in arrears, based on its rating for senior unsecured long-term debt securities without third-third party credit enhancement as provided by Moody's and S&P and (b) a utilization fee, 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 which is applied to the unpaid principal amount of each loan during such periods the outstanding credit exposure under the IPC facility exceeds 50 percent of the aggregate commitments under the IPC facility. In connection with the issuance of letters of credit, IPC 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 at a per annum rate of 0.125 percent on the average daily undrawn stated amount under each letter of credit, payable quarterly in arrears and (iii) documentary and processing charges in accordance with the letter of credit issuer's standard schedule for such charges. At closing, IPC paid each of the lenders an upfront fee to secure the commitments of each lender under the facility and an arrangement fee for each bank that arranged and structured the facilities.

5. COMMITMENTS AND CONTINGENCIES:

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

IPC has agreed to guarantee the performance of reclamation activities at Bridger Coal Company, of which Idaho Energy Resources Co., a subsidiary of IPC, owns a one-third interest. This guarantee, which is renewed each December, was $60 million at March 31, 2005. 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 of this guarantee is minimal.

In August 2003, IE sold its forward book of electricity trading contracts to Sempra Energy Trading. As part of the sale of the forward book of electricity trading contracts IE entered into an Indemnity Agreement with Sempra Energy Trading, guaranteeing the performance of one of the counterparties through 2009. The maximum amount payable by IE under the Indemnity Agreement is $20 million. The indemnity agreement has been accounted for in accordance with FIN 45, "Guarantor's Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others," and did not have a significant effect on IDACORP's financial statements.

Legal Proceedings
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.

Alves Dairy: On May 18, 2004, Herculano and Frances Alves, dairy operators from Twin Falls, Idaho, brought suit against IPC in Idaho State District Court, Fifth Judicial District, Twin Falls County. The plaintiffs seek unspecified monetary damages for negligence and nuisance (allegedly allowing electrical current to flow in the earth, injuring the plaintiffs' right to use and enjoy their property and adversely affecting their dairy herd). On July 16, 2004, IPC filed an answer to Mr. and Mrs. Alves' complaint, denying all liability to the plaintiffs, and asserting certain affirmative defenses. The parties have begun discovery in the case. No trial date has been scheduled. On December 14, 2004, IPC filed a motion with the District Court for permission to appeal the court's denial of IPC's Motion to Disqualify the trial judge, for cause. The District Court granted the motion for permissive appeal. On February 16, 2005, IPC filed a motion for permissive appeal with the Idaho Supreme Court. On March 7, 2005, the Idaho Supreme Court denied IPC's Application to Appeal the District Court's refusal to disqualify the trial judge for cause.

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

On March 28, 2005, the Stray Current and Voltage Remediation Act was signed into law by the Governor of Idaho. IPC believes the new legislation to be a positive development in a number of respects. Among other things, the act specifies levels of "stray voltage" below which no remedial action must be taken by a utility, and confers exclusive initial jurisdiction upon the Idaho Public Utilities Commission (IPUC) to determine whether a utility has properly investigated and, if necessary, remedied, a dairy producer's complaint of stray voltage. The act provides that any party to such an administrative proceeding at the IPUC may, after exhausting its administrative remedies at the IPUC, file a civil action in any appropriate Idaho court, with the express statutory proviso that the IPUC's determination shall be admissible as evidence in the civil action. The act will not preclude the Alves case from proceeding in the District Court as set forth above, but will require that any future Idaho stray voltage claimants first exhaust their administrative remedies at the IPUC.

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 removed this action from the state court to the U.S. 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 U.S. 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 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 U.S. Court of Appeals for the Ninth Circuit. On August 10, 2004, the Ninth Circuit affirmed the dismissal of Grays Harbor's complaint, finding that Grays Harbor's claims were preempted by federal law and were barred by the filed-rate doctrine. The court also remanded the case to allow Grays Harbor leave to amend its complaint to seek declaratory relief only as to contract formation, and held that Grays Harbor could seek monetary relief, if at all, only from the FERC, and not from the courts. IDACORP, IPC and IE sought rehearing from the Ninth Circuit arguing that the court erred in granting leave to amend the complaint as such a declaratory relief claim would be preempted and would be barred by the filed-rate doctrine. The Ninth Circuit denied the rehearing request on October 25, 2004, and the decision became final on November 12, 2004. On that same date, the companies took steps to have the case transferred and consolidated with other similar cases arising out the California energy crisis currently pending before the Honorable Robert H. Whaley, sitting by designation in the Southern District of California and presiding over Multidistrict Litigation Docket No. 1405, regarding California Wholesale Electricity Antitrust Litigation. On November 18, 2004, Grays Harbor filed an amended complaint alleging that the contract was formed under circumstances of "mistake" as to an "artificial . . . power shortage." Grays Harbor asks that the contract therefore be declared "unenforceable" and found "unconscionable." On December 23, 2004, the Judicial Panel on Multidistrict Litigation conditionally transferred the case to Judge Whaley. Grays Harbor sought to vacate the transfer; however, on April 18, 2005, the Judicial Panel on Multidistrict Litigation ordered the case transferred. IDACORP, IPC and IE have not responded to the amended complaint as a response is not yet required. The companies plan to file a motion to dismiss the amended complaint. The companies intend to vigorously defend their position on remand and believe this matter will not have a material adverse effect on their consolidated financial positions, results of operations or cash flows.

Port of Seattle: On May 21, 2003, the Port of Seattle, a Washington municipal corporation, filed a lawsuit against 20 energy firms, including IPC and IDACORP, in the U.S. District Court for the Western District of Washington at Seattle. The Port of Seattle's complaint alleges fraud and violations of state and federal antitrust laws and the Racketeer Influenced and Corrupt Organizations Act. On December 4, 2003, the Judicial Panel on Multidistrict Litigation transferred the case to the Southern District of California for inclusion with several similar multidistrict actions currently pending before the Honorable Robert H. Whaley.

All defendants, including IPC and IDACORP, moved to dismiss the complaint in lieu of answering it. The motions were based on the ground that the complaint seeks to set alternative electrical rates, which are exclusively within the jurisdiction of the FERC and are barred by the filed-rate doctrine. A hearing on the motion to dismiss was heard on March 26, 2004. On May 28, 2004, the court granted IPC's and IDACORP's motion to dismiss. In June 2004, the Port of Seattle appealed the court's decision to the U.S. Court of Appeals for the Ninth Circuit. The appeal has been fully briefed, however no date has yet been set for oral argument. The companies intend to vigorously defend their position in this proceeding and believe these matters will not have a material adverse effect on their consolidated financial positions, results of operations or cash flows.

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

The companies' motion to dismiss the complaint was granted on February 11, 2005. Wah Chang appealed to the Ninth Circuit on March 10, 2005. The Ninth Circuit recently set a briefing schedule on the appeal, requiring Wah Chang's opening brief to be filed by July 6, 2005, with the companies' and other defendants' opposition brief to be filed by August 5, 2005. Wah Chang will have 14 days from the date of service of the companies' opposition brief to file an optional reply brief. 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.

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

On September 8, 2004, this case was transferred and consolidated with other similar cases currently pending before the Honorable Robert H. Whaley, sitting by designation in the Southern District of California and presiding over Multidistrict Litigation Docket No. 1405, regarding California Wholesale Electricity Antitrust Litigation. The companies' motion to dismiss the complaint was granted on February 11, 2005. The City of Tacoma appealed to the Ninth Circuit on March 10, 2005. The Ninth Circuit recently set a briefing schedule on the appeal, requiring the City of Tacoma's opening brief to be filed by June 27, 2005, with the companies' and other defendants' opposition brief to be filed by July 26, 2005. The City of Tacoma will have 14 days from the date of service of the companies' opposition brief to file an optional reply brief. 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.

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. The plaintiffs asserted various claims that the defendants violated the California Antitrust Law (the Cartwright Act), Business and Professions Code Section 16720 and California's Unfair Competition Law, Business and Professions Code Section 17200. Among the acts complained of are bid rigging, information exchanges, withholding of power and other wrongful acts. These actions were subsequently consolidated, resulting in the filing of Plaintiffs' Master Complaint in San Diego Superior Court on March 8, 2002.

On April 22, 2002, more than a year after the initial complaints were filed, two of the original defendants, Duke and Reliant, filed separate cross-complaints against IPC and IE, and approximately 30 other cross-defendants. Duke and Reliant's cross-complaints seek indemnity from IPC, IE and the other cross-defendants for an unspecified share of any amounts they must pay in the underlying suits because, they allege, other market participants like IPC and IE engaged in the same conduct at issue in the Plaintiffs' Master Complaint. 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 Plaintiffs' Master Complaint. Reliant 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 Plaintiffs' Master Complaint 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 U.S. 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 U.S. Court of Appeals for the Ninth Circuit 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. On December 8, 2004, the Ninth Circuit issued its opinion in People of California v. NRG Energy, Inc., et al., which affirmed the district court's remand of these cases to state court and dismissed certain federal government defendants due to their sovereign immunity from suit.

On March 10, 2005, the Ninth Circuit's mandate, remanding People of California v. NRG Energy, Inc. to state court was issued. On March 15, 2005, however, cross-defendant, Powerex Corp., filed a motion to recall mandate until a petition for certiorari seeking review of this case by the U.S. Supreme Court is filed and ruled upon by the Supreme Court. Powerex Corp. has not yet filed a petition for certiorari. On April 6, 2005, the Ninth Circuit denied Powerex Corp.'s motion to recall mandate.

Upon remand, IPC and IE intend to refile their motion to dismiss, which had been filed previously in federal court, as a demurrer in state court. The companies believe these matters will not have a material adverse effect on their consolidated financial positions, results of operations or cash flows.

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

On January 18, 2001, the CalPX sent IPC an invoice for $2 million - a "default share invoice" - - as a result of an alleged Southern California Edison payment default of $215 million for power purchases. IPC made this payment. On January 24, 2001, IPC terminated its participation agreement with the CalPX. On February 8, 2001, the CalPX sent a further invoice for $5 million, due on February 20, 2001, as a result of alleged payment defaults by Southern California Edison, Pacific Gas and Electric Company and others. However, because the CalPX owed IPC $11 million for power sold to the CalPX in November and December 2000, IPC did not pay the February 8 invoice. The CalPX later reversed IPC's payment of the January 18, 2001 invoice, but on June 20, 2001 invoiced IPC for an additional $2 million which the CalPX has not reversed. The CalPX owes IPC $14 million for power sold in November and December including $2 million associated with the default share invoice dated June 20, 2001. IPC essentially discontinued energy trading with the CalPX and the California Independent System Operator (Cal ISO) in December 2000.

IPC believes that the default invoices were not proper and that IPC owes no further amounts to the CalPX. IPC has pursued all available remedies in its efforts to collect amounts owed to it by the CalPX. On February 20, 2001, IPC filed a petition with the FERC to intervene in a proceeding that requested the FERC to suspend the use of the CalPX chargeback methodology and provide for further oversight in the CalPX's implementation of its default mitigation procedures.

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

In April 2001, Pacific Gas and Electric Company filed for bankruptcy. The CalPX and the Cal ISO were among the creditors of Pacific Gas and Electric Company. To the extent that Pacific Gas and Electric Company'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 Pacific Gas and Electric Company's and Southern California Edison's liabilities. Shortly after the issuance of that order, the CalPX segregated the CalPX chargeback amounts it had collected in a separate account. The CalPX claimed it was awaiting further orders from the FERC and the bankruptcy court before distributing the funds that it collected under its chargeback tariff mechanism. On October 7, 2004, the FERC issued an order determining that it would not require the disbursement of chargeback funds until the completion of the California refund proceedings. On November 8, 2004, IE, along with a number of other parties, sought rehearing of that order. On March 15, 2005, the FERC issued an order on rehearing confirming that the CalPX is to continue to hold the chargeback funds, but solely to offset seller-specific shortfalls in the seller's CalPX account at the conclusion of the California refund proceeding. Balances are to be returned to the respective sellers at the conclusion of a seller's participation in the refund proceeding.

California Refund:
In April 2001, the FERC issued an order stating that it was establishing price mitigation for sales in the California wholesale electricity market. Subsequently, in a June 19, 2001 order, the FERC expanded that price mitigation plan to the entire western United States electrically interconnected system. That plan included the potential for orders directing electricity sellers into California since October 2, 2000 to refund portions of their spot market sales prices if the FERC determined that those prices were not just and reasonable, and therefore not in compliance with the Federal Power Act. 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 Administrative Law Judge submitted a Report and Recommendation to the FERC recommending that the FERC adopt the methodology set forth in the report and set for evidentiary hearing an analysis of the Cal ISO's and the CalPX's spot markets to determine what refunds may be due upon application of that methodology.

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

The Administrative Law Judge 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 Administrative Law Judge. However, the FERC changed a component of the formula the Administrative Law Judge 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 Administrative Law Judge, 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 Mitigated Market Clearing Prices and refund amounts within five months. The Cal ISO has since, on a number of occasions, requested additional time to complete its compliance filings. This Cal ISO compliance filing has been delayed until at least August 2005. The Cal ISO is required to update the FERC on its progress monthly. After receipt of the compliance filing, the FERC will consider cost-based filings from sellers to reduce their refund exposure.

On December 2, 2003, IE petitioned the U.S. Court of Appeals for the Ninth Circuit for review of the FERC's orders, and since that time, dozens of other petitions for review have been filed. The Ninth Circuit consolidated IE's and the other parties' petitions with the petitions for review arising from earlier FERC orders in this proceeding, bringing the total number of consolidated petitions to more than 100. The Ninth Circuit held the appeals in abeyance pending the disposition of the market manipulation claims discussed below and the development of a comprehensive plan to brief this complicated case. Certain parties also sought further rehearing and clarification before the FERC. On September 21, 2004, the Ninth Circuit convened case management proceedings, a procedure reserved to help organize complex cases. On October 22, 2004, the Ninth Circuit severed a subset of the stayed appeals in order that briefing could commence regarding limited issues of: (1) which parties are subject to the FERC's refund jurisdiction under section 201(f) of the Federal Power Act; (2) the temporal scope of refunds under section 206 of the Federal Power Act; and (3) which categories of transactions are subject to refunds. Oral argument was held on April 12-13, 2005.

On May 12, 2004, the FERC issued an order clarifying portions of its earlier refund orders and, among other things, denying a proposal made by Duke Energy North America and Duke Energy Trading and Marketing (and supported by IE) to lodge as evidence a contested settlement in a separate complaint proceeding, California Public Utilities Commission (CPUC) v. El Paso, et al. The CPUC's complaint alleged that the El Paso companies manipulated California energy markets by withholding pipeline transportation capacity into California in order to drive up natural gas prices immediately before and during the California energy crisis in 2000-2001. The settlement will result in the payment by El Paso of some $1.69 billion. Duke claimed that the relief afforded by the settlement was duplicative of the remedies imposed by the FERC in its March 26, 2003 order changing the gas cost component of its refund calculation methodology. IE, along with other parties, has sought rehearing of the May 12, 2004 order. On November 23, 2004, the FERC denied rehearing and within the statutory time allowed for petitions, a number of parties, including IE, filed petitions for review of the FERC's order with the Ninth Circuit. These petitions have since been consolidated with the larger number of review petitions in connection with the California refund proceeding.

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, 2005, 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, 2005, 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 California Attorney General filed a complaint with the FERC against various sellers in the wholesale power market, including IE and IPC, alleging that the FERC's market-based rate requirements violate the Federal Power Act, and, even if the market-based rate requirements are valid, that the quarterly transaction reports filed by sellers do not contain the transaction-specific information mandated by the Federal Power Act 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 Attorney General appealed the FERC's decision to the U.S. Court of Appeals for the Ninth Circuit. The Attorney General contends that the failure of all market-based rate authority sellers of power to have rates on file with the FERC in advance of sales is impermissible. The Ninth Circuit issued its decision on September 9, 2004, concluding that market-based tariffs are permissible under the Federal Power Act, but remanded the matter to the FERC to consider whether the FERC should exercise remedial power (including some form of refunds) when a market participant failed to submit reports that the FERC relies on to confirm the justness and reasonableness of rates charged. Certain parties to the litigation have sought rehearing. The companies cannot predict whether rehearing will be granted or what action the FERC might take if the matter is remanded.

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

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

The California Parties urged the FERC to apply the precepts of its earlier decision, to replace actual prices charged in every hour starting May 1, 2000 through the beginning of the existing Refund Period with a Mitigated Market Clearing Price, seeking approximately $8 billion in refunds to the Cal ISO and the CalPX. On March 20, 2003, numerous parties, including IE and IPC, submitted briefs and responsive testimony.

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

On June 25, 2003, the FERC ordered over 50 entities that participated in the western wholesale power markets between January 1, 2000 and June 20, 2001, including IPC, to show cause why certain trading practices did not constitute gaming or anomalous market behavior in violation of the Cal ISO and the CalPX Tariffs. The Cal ISO was ordered to provide data on each entity's trading practices within 21 days of the order, and each entity was to respond explaining their trading practices within 45 days of receipt of the Cal ISO data. IPC submitted its responses to the show cause orders on September 2 and 4, 2003. On October 16, 2003, IPC reached agreement with the FERC Staff on the two orders commonly referred to as the "gaming" and "partnership" show cause orders. Regarding the gaming order, the FERC Staff determined it had no basis to proceed with allegations of false imports and paper trading and IPC agreed to pay $83,373 to settle allegations of circular scheduling. IPC believed that it had defenses to the circular scheduling allegation but determined that the cost of settlement was less than the cost of litigation. In the settlement, IPC did not admit any wrongdoing or violation of any law. With respect to the "partnership" order, the FERC Staff submitted a motion to the FERC to dismiss the proceeding because materials submitted by IPC demonstrated that IPC did not use its "parking" and "lending" arrangement with Public Service Company of New Mexico to engage in "gaming" or anomalous market behavior ("partnership"). The "gaming" settlement was approved by the FERC on March 3, 2004. Eight parties have requested rehearing of the FERC's March 3, 2004 order, but the FERC has not yet acted on those requests. The motion to dismiss the "partnership" proceeding was approved by the FERC in an order issued on 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 U.S. Court of Appeals for the Ninth Circuit and the District of Columbia Circuit for review of the FERC's orders initiating the show cause proceedings. Some of the parties contend that the scope of the proceedings initiated by the FERC was too narrow. Other parties contend that the orders initiating the show cause proceedings were impermissible. Under the rules for multidistrict litigation, a lottery was held and although these cases were to be considered in the District of Columbia Circuit by order of February 10, 2005, the District of Columbia Circuit transferred the proceedings to the Ninth Circuit. The FERC had moved the District of Columbia Circuit to dismiss these petitions on the grounds of prematurity and lack of ripeness and finality. The transfer order was issued before a ruling from the District of Columbia Circuit and the motions, if renewed, will be considered by the Ninth Circuit. IPC is not able to predict the outcome of the judicial determination of these issues.

On June 25, 2003, the FERC also issued an order instituting an investigation of anomalous bidding behavior and practices in the western wholesale power markets. In this investigation, the FERC was to review evidence of alleged economic withholding of generation. The FERC determined that all bids into the CalPX and the Cal ISO markets for more than $250 per MWh for the time period May 1, 2000 through October 1, 2000 would be considered prima facie evidence of economic withholding. The FERC Staff issued data requests in this investigation to over 60 market participants including IPC. IPC responded to the FERC's data requests. In a letter dated May 12, 2004, the FERC's Office of Market Oversight and Investigations advised that it was terminating the investigation as to IPC. In March 2005, the California Attorney General, the CPUC, California Electricity Oversight Board and Pacific Gas and Electric Company sought judicial review in the Ninth Circuit of the FERC's termination of this investigation as to IPC and approximately 30 other market participants. IPC has moved to intervene in these proceedings. On April 25, 2005, Pacific Gas and Electric Company sought review in the Ninth Circuit of another FERC order in the same docketed proceeding confirming the agency's earlier decision not to allow the participation of the California Parties in what the FERC characterized as its non-public investigative proceeding.

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 Administrative Law Judge submitted recommendations and findings to the FERC on September 24, 2001. The Administrative Law Judge 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 Administrative Law Judge's decision is a recommendation to the commissioners of the FERC. Multiple parties submitted comments to the FERC with respect to the Administrative Law Judge's recommendations. The Administrative Law Judge'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 had 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 IPC or IE. The companies submitted responsive testimony defending vigorously against Grays Harbor's refund claims.

In addition, the Port of Seattle, the City of Tacoma and the City of Seattle made filings with the FERC on March 3, 2003 claiming that because some market participants drove prices up throughout the west through acts of manipulation, prices for contracts throughout the Pacific Northwest market should be re-set starting in May 2000 using the same factors the FERC would use for California markets. Although the majority of these claims are generic, they named a number of power market suppliers, including IPC and IE, as having used parking services provided by other parties under FERC-approved tariffs and thus as being candidates for claims of improperly having received congestion revenues from the Cal ISO. On June 25, 2003, after having considered oral argument held earlier in the month, the FERC issued its Order Granting Rehearing, Denying Request to Withdraw Complaint and Terminating Proceeding, in which it terminated the proceeding and denied claims that refunds should be paid. The FERC denied rehearing on November 10, 2003, triggering the right to file for review. The Port of Seattle, the City of Tacoma, the City of Seattle, the California Attorney General, the CPUC and Puget Sound Energy, Inc. filed petitions for review in the Ninth Circuit. These petitions have 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. On July 21, 2004, the City of Seattle submitted to the Ninth Circuit in the Pacific Northwest refund petition for review a motion requesting leave to offer additional evidence before the FERC in order to try to secure another opportunity for reconsideration by the FERC of its earlier rulings. The evidence that the City of Seattle seeks to introduce before the FERC consisted of audio tapes of what purports to be Enron trader conversations containing inflammatory language that have been the subject of coverage in the press. Under Section 313(b) of the Federal Power Act, a court is empowered to direct the introduction of additional evidence if it is material and could not have been introduced during the underlying proceeding. The City of Seattle also requested that the current briefing schedule, which required briefs to be filed by August 5, 2004, be delayed. On September 29, 2004, the Ninth Circuit denied the City of Seattle's motion for leave to adduce evidence, without prejudice to renewing the request for remand in the briefing in the Pacific Northwest refund case. Briefing is currently scheduled to be completed on May 25, 2005. A date for oral argument has not yet been set.

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

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

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

The new complaint alleges that during the class period IDACORP and/or certain of its officers and/or directors made materially false and misleading statements or omissions about its business operations, and specifically the IE financial outlook, in violation of Rule 10b-5, thereby causing investors to purchase IDACORP's common stock at artificially inflated prices. The new complaint alleges that IDACORP failed to disclose and misrepresented the following material adverse facts which were known to it or recklessly disregarded by it: (1) IDACORP falsely inflated the value of energy contracts held by IE in order to report higher revenues and profits; (2) IDACORP permitted IPC to inappropriately grant native load priority for certain energy transactions to IE; (3) IDACORP failed to file 13 ancillary service agreements involving the sale of power for resale in interstate commerce that it was required to file under Section 205 of the Federal Power Act; (4) IDACORP failed to file 1,182 contracts that IPC assigned to IE for the sale of power for resale in interstate commerce that IPC was required to file under Section 203 of the Federal Power Act; (5) IDACORP failed to ensure that IE provided appropriate compensation from IE to IPC for certain affiliated energy transactions; and (6) IDACORP permitted inappropriate sharing of certain energy pricing and transmission information between IPC and IE. These activities allegedly allowed IE to maintain a false perception of continued growth that inflated its earnings. In addition, the new complaint alleges that those earnings press releases, earnings release conference calls, analyst reports and revised earnings guidance releases issued during the class period were false and misleading. The action seeks an unspecified amount of damages, as well as other forms of relief. IDACORP and the other defendants filed a consolidated motion to dismiss on February 9, 2005, and the plaintiffs filed their opposition to the consolidated motion to dismiss on March 28, 2005. IDACORP and the other defendants filed their response to the plaintiff's opposition on April 29, 2005 and oral argument on the motion is scheduled for May 19, 2005.

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

Powerex: On August 31, 2004, Powerex Corp., the wholly owned power marketing subsidiary of BC Hydro, a Crown Corporation of the province of British Columbia, Canada, filed a lawsuit against IE and IDACORP in the U.S. District Court for the District of Idaho. Powerex Corp. alleges that IE breached an oral and written contract regarding the assignment of transmission capacity for electric power by IE to Powerex Corp. for a 14 month period and for intentional interference with Powerex Corp.'s alleged contract with IE. Powerex Corp. seeks unspecified general and special damages. On November 29, 2004, the companies filed an answer to Powerex Corp.'s complaint, denying all liability to the plaintiffs, and asserting certain affirmative defenses. The companies intend to vigorously defend their position in this proceeding but cannot predict the outcome of this matter.

Other Legal Issues
Idaho Power Company Transmission Line Rights-of-Way Across Fort Hall Indian Reservation: IPC has multiple transmission lines that cross the Shoshone-Bannock Tribes' Fort Hall Indian Reservation near the city of Pocatello in southeastern Idaho. IPC has been working since 1996 to renew four of the right-of-way permits (for five of the transmission lines), which have stated permit expiration dates between 1996 and 2003. IPC filed applications with the U.S. Department of the Interior, Bureau of Indian Affairs, to renew the four rights-of-way for 25 years, including payment of the independently appraised value of the rights-of-way to the tribes (and the tribal allottees who own portions of the rights-of-way). Due to the lack of definitive legal guidelines for valuation of the permit renewals, IPC is in the process of negotiating mutually acceptable renewal terms with the tribes and allottees. The parties are pursuing a possible 23-year renewal of the permits (including all pre-renewal periods) for a total payment of approximately $7 million to the tribes and allottees. IPC, the tribes and the Bureau of Indian Affairs are currently working through the process of finalizing the agreement, including obtaining the requisite consents from the allottees. The parties believe it is likely that the required consents will be obtained during the second quarter of 2005. On December 27, 2004, IPC filed an application with the IPUC seeking an accounting order regarding the capitalization and amortization of the easement grant costs. On February 28, 2005, the IPUC issued an order approving IPC's application.

6. REGULATORY MATTERS:

IPUC Rate Proceedings
IPC currently has four rate proceedings before the IPUC: the rate case tax settlement adjustments, the Bennett Mountain Power Plant, the Energy Efficiency Tariff Rider and the 2005-2006 PCA. IPC has requested that the increases related to these filings be effective June 1, 2005. The 2005-2006 PCA filing is discussed below in "Deferred Net Power Supply costs - Idaho."

Rate Case Tax Settlement: In 2003, IPC filed for a general rate increase that took effect June 1, 2004. A portion of that rate case involved IPC's income tax expense. Subsequent to last year's June 1 rate change, IPC asked the IPUC to reconsider that portion of the case and the IPUC granted an ongoing income tax-related adjustment, and a one-year income tax-related adjustment to begin on June 1, 2005. Together, these tax related adjustments will increase rates by $24 million, or 4.45 percent (2.25 percent for the ongoing portion and 2.2 percent for the one-year portion). The 2.2 percent portion is temporary and will expire on June 1, 2006.

Bennett Mountain Power Plant: The Bennett Mountain Power Plant, a 164-MW gas-fired generating plant near Mountain Home, Idaho, was tested and ready for operation on March 31, 2005, and provisional acceptance occurred on the same date. IPC made a rate filing with the IPUC on March 2, 2005 to include in Idaho retail rates a return on the estimated plant investment and other expenses, at April 30, 2005, of approximately $58 million. The requested rate increase is $9 million annually, or 1.84 percent. IPC requested that these costs be included in Idaho retail rates effective June 1, 2005. Plant costs incurred after April 30, 2005 will be included in a future rate request.

Energy Efficiency Tariff Rider: IPC charges an amount to each customer to provide funding for energy efficiency initiatives. In December 2004, IPC filed a request to increase this charge from 0.5 percent of total base revenues to 1.5 percent effective June 1, 2005, and 2.4 percent effective June 1, 2007. The requested June 1, 2005 change would increase the amounts collected from customers by $5 million. Public comments concerning IPC's application were required to be filed with the IPUC by February 16, 2005.

Oregon Rate Case
On September 21, 2004, IPC filed an application with the Oregon Public Utility Commission (OPUC) to increase general rates an average of 17.5 percent or approximately $4 million annually. IPC's filing includes a request to introduce summer and non-summer rates similar to proposals that were approved in the 2003 Idaho general rate case.

On October 19, 2004, the OPUC suspended IPC's request for a period of time not to exceed nine months from October 20, 2004 to investigate the propriety and reasonableness of the request. Settlement discussions have taken place and IPC and the OPUC Staff have verbally agreed to a partial settlement. The most significant unresolved issue in this proceeding is the appropriate quantification of net power supply costs for purposes of setting rates. IPC filed its rebuttal testimony on April 8, 2005, the majority of which is directed at the OPUC Staff's proposal to reduce net power supply costs. Hearings are scheduled for May 23-24, 2005. Although a decision is expected later in 2005, IPC is unable to predict what rate relief, if any, the OPUC will grant.

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

		March 31,		December 31,
		2005		2004
Oregon deferral		$	11,478	$	12,047
Idaho PCA current year net power supply cost deferrals:
	Deferral for 2005-2006 rate year		36,285		22,778
Irrigation Lost Revenues			13,406		13,290
Idaho PCA true-up awaiting recovery:
	Remaining true-up authorized May 2004		636		11,415
	Total deferral	$	61,805	$	59,530

Idaho: IPC has a Power Cost Adjustment (PCA) mechanism that provides for annual adjustments to the rates charged to its Idaho retail customers. These adjustments are based on forecasts of net power supply costs, which are fuel and purchased power less off-system sales, and the true-up of the prior year's forecast. During the year, 90 percent of the difference between the actual and forecasted costs is deferred with interest. The ending balance of this deferral, called the true-up for the current year's portion and the true-up of the true-up for the prior years' unrecovered portion, is then included in the calculation of the next year's PCA.

On April 15, 2005, IPC filed the 2005-2006 PCA with the IPUC with a proposed effective date of June 1, 2005. The application proposed to hold the PCA component of customers' rates at the existing level, which is currently recovering $71 million above base rates. By IPUC order, this year's PCA includes $12 million in lost revenues and $2 million in related interest resulting from IPC's Irrigation Load Reduction Program that was in place in 2001. IPC proposed to defer approximately $29 million of power supply costs, or 4.75 percent, for one year to help mitigate the impacts of the $9 million, or 1.84 percent, increase for the Bennett Mountain Power Plant and the $23 million, or 4.45 percent, increase due to the rate case tax settlement adjustments, since all three are proposed to be effective June 1, 2005. The $29 million will be recovered during the 2006-2007 PCA rate year, and IPC will earn a two percent carrying charge on this balance.

On April 15, 2004, IPC filed its 2004-2005 PCA with the IPUC requesting recovery of $71 million above base rates and a proposed effective date of June 1, 2004 for new PCA rates. On May 25, 2004, the IPUC issued Order No. 29506 approving IPC's filing.

Oregon: On March 2, 2005, IPC filed for an accounting order to defer net power supply costs for the period of March 1, 2005 through February 28, 2006 in anticipation of continued low water conditions. The net power supply costs included in this filing were $169 million, of which $3 million related to the Oregon jurisdiction. IPC is proposing to use the same methodology for this deferral filing that was accepted in 2002 for Oregon's share of IPC's 2001 net power supply expenses. Under this methodology, IPC will earn its Oregon authorized rate of return on the deferred balance and will recover the amount through rates in future years, as approved by the OPUC.

7. INDUSTRY SEGMENT INFORMATION:

Information regarding segments is presented in accordance with SFAS 131, "Disclosure about Segments of an Enterprise and Related Information." Based on the criteria outlined in SFAS 131, IDACORP has identified two reportable segments: utility operations 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.

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

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

			Utility								Consolidated
			Operations		IFS		Other		Eliminations		Total
Three months ended
March 31, 2005:
		Revenues	$	190,868	$	335	$	4,979	$	-	$	196,182
		Net income (loss)		21,509		2,495		(938)		-		23,066

Total assets at March 31, 2005			$	2,983,225	$	139,452	$	232,464	$	(89,746)	$	3,265,395

Three months ended
	March 31, 2004:
		Revenues	$	183,603	$	-	$	4,586	$	-	$	188,189
		Net income (loss)		19,409		2,585		(2,335)		-		19,659

Total assets at December 31, 2004:			$	2,969,212	$	145,279	$	211,120	$	(91,439)	$	3,234,172

8. 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
		2005		2004		2005		2004		2005		2004
Service cost		$	3,282	$	2,948	$	292	$	340	$	389	$	344
Interest cost			5,281		5,109		538		578		991		999
Expected return on plan assets			(7,422)		(6,978)		-		-		(642)		(565)
Amortization of net obligation
	at transition		(32)		(66)		78		153		510		510
Amortization of prior service
	cost		193		193		57		(90)		(131)		(141)
Amortization of net loss			-		-		172		219		397		357
Net periodic benefit cost		$	1,302	$	1,206	$	1,137	$	1,200	$	1,514	$	1,504

As previously disclosed in their consolidated financial statements for the year ended December 31, 2004, IDACORP and IPC do not expect to contribute to their pension plan in 2005. As of March 31, 2005, no contributions have been made.

FSP FAS 106-1 and FSP FAS 106-2
In January and May 2004, the FASB released FSP FAS 106-1 and FSP FAS 106-2, "Accounting and Disclosure Requirements Related to the Medicare Prescription Drug, Improvement and Modernization Act of 2003." The Medicare Prescription Drug, Improvement and Modernization Act of 2003 (Medicare Act) was signed into law in December 2003 and establishes a prescription drug benefit, as well as a federal subsidy to sponsors of retiree health care benefit plans that provide a prescription drug benefit that is at least actuarially equivalent to Medicare's prescription drug coverage.

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

IDACORP and IPC initially determined that the effect of the Medicare Act would not be material. However, regulations published on January 28, 2005 provide more flexibility in determining actuarial equivalence to Medicare of the benefits provided by the plan, than was initially estimated by IDACORP's and IPC's actuaries. Based on these new regulations, IDACORP and IPC estimate that the accumulated postretirement benefit obligation as of January 1, 2005 will be reduced by $6 million, and 2005 periodic postretirement benefit cost will decrease by $1 million. Pending final determination of the legislation's effects, IDACORP and IPC have not yet recognized this cost reduction.

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

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

We have reviewed the accompanying consolidated balance sheet of IDACORP, Inc. and subsidiaries (the "Company") as of March 31, 2005, and the related consolidated statements of income, comprehensive income and cash flows for the three-month periods ended March 31, 2005 and 2004. These interim financial statements are the responsibility of the Company's management.

We conducted our reviews in accordance with the standards of the Public Company Accounting Oversight Board (United States). A review of interim financial information consists principally of applying analytical procedures and making inquiries of persons responsible for financial and accounting matters. It is substantially less in scope than an audit conducted in accordance with standards of the Public Company Accounting Oversight Board (United States), the objective of which is the expression of an opinion regarding the financial statements taken as a whole. Accordingly, we do not express such an opinion.

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

We have previously audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheet of IDACORP, Inc. and subsidiaries as of December 31, 2004 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 March 8, 2005, 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, 2004 is fairly stated, in all material respects, in relation to the consolidated balance sheet from which it has been derived.

DELOITTE & TOUCHE LLP

Boise, Idaho
May 4, 2005

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

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

We have reviewed the accompanying consolidated balance sheet and statement of capitalization of Idaho Power Company and subsidiary (the "Company") as of March 31, 2005, and the related consolidated statements of income, comprehensive income and cash flows for the three-month periods ended March 31, 2005 and 2004. These interim financial statements are the responsibility of the Company's management.

We have previously audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheet and statement of capitalization of Idaho Power Company and subsidiary as of December 31, 2004, 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 March 8, 2005, 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, 2004 is fairly stated, in all material respects, in relation to the consolidated balance sheet and statement of capitalization from which it has been derived.

DELOITTE & TOUCHE LLP

Boise, Idaho
May 4, 2005

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

(Dollar amounts are in thousands unless otherwise indicated. Megawatt-hours (MWh) are in thousands.)

INTRODUCTION:

In Management's Discussion and Analysis of Financial Condition and Results of Operations (MD&A), the general financial condition and results of operations for IDACORP, Inc. and its subsidiaries (collectively, IDACORP) and Idaho Power Company and its subsidiary (collectively, IPC) are discussed. IDACORP is a holding company formed in 1998 whose principal operating subsidiary is IPC. IDACORP is exempt from registration as a public utility holding company pursuant to Section 3(a)(1) of the Public Utility Holding Company Act of 1935 (1935 Act). In addition, pursuant to Rule 2 of the General Rules and Regulations under the 1935 Act, IDACORP is exempt from all the provisions of the 1935 Act and rules thereunder, except for Section 9(a)(2) of the 1935 Act, which requires IDACORP to seek prior Securities and Exchange Commission approval to acquire securities of another public utility company.

IPC is an electric utility with a service territory covering approximately 24,000 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:

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

IdaTech, LLC - developer of integrated fuel cell systems;

IDACOMM, Inc. - provider of telecommunications services and commercial and residential Internet services; and

Ida-West Energy Company - operator of small hydroelectric generation projects that satisfy the requirements of the Public Utilities Regulatory Policy Act of 1978 (PURPA).

IDACORP Energy (IE), a marketer of electricity and natural gas, wound down its operations in 2003.

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

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, 2004, and should be read in conjunction with the discussions in that 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 IDACORP's or IPC's control and may cause actual results to differ materially from those contained in forward-looking statements:

Changes in governmental policies, including new interpretations of existing 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, day-to-day business operations, acquisition and disposal of assets and facilities, operation and construction of plant facilities, relicensing of hydroelectric projects, recovery of purchased power expenses, recovery of other capital investments, present or prospective wholesale and retail competition (including but not limited to retail wheeling and transmission costs) and other refund proceedings;

Litigation and regulatory proceedings, including those resulting from the energy situation in the western United States, and settlements that influence business and profitability;

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

Weather variations affecting hydroelectric generating conditions and customer energy usage;

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

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

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

Impacts from the potential formation of a regional transmission organization (RTO);

Population growth rates and demographic patterns;

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

Changes in operating expenses and capital expenditures and fluctuations in sources and uses of cash;

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

Actions by credit rating agencies, including changes in rating criteria and new interpretations of existing criteria;

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

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

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

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

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

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

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

Reduced hydroelectric generation can reduce revenues and increase costs. Idaho Power Company has a predominately hydroelectric generating base. Because of Idaho Power Company's heavy reliance on hydroelectric generation, the weather can significantly affect its operations. Idaho Power Company is experiencing its sixth consecutive year of below normal water conditions in 2005. When hydroelectric generation is reduced, Idaho Power Company must increase its use of more expensive thermal generating resources and purchased power. Through its power cost adjustment in Idaho, Idaho Power Company can expect to recover approximately 90 percent of the increase in its Idaho jurisdictional net power supply costs, which are fuel and purchased power less off-system sales, above the level included in its base rates. The power cost adjustment recovery includes both a forecast and deferrals that are subject to the regulatory process. The non-Idaho net power supply costs are subject to periodic recovery from its Oregon and Federal Energy Regulatory Commission jurisdictional customers.

Continuing declines in stream flows and over-appropriation of water in Idaho will reduce hydroelectric generation and revenues and increase costs. The combination of declining Snake River base flows, over-appropriation of water and continuing drought conditions have led to disputes among certain surface water and ground water irrigators, and the State of Idaho. Recharging the Eastern Snake Plain Aquifer, which contributes to Snake River flows, by diverting surface water to porous locations and permitting it to sink into the aquifer is one proposed solution to the dispute. Idaho Power Company believes aquifer recharge would further reduce Snake River base flows available for hydroelectric generation, reduce Idaho Power Company revenues and increase costs.

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

The Idaho Public Utilities Commission's grant of less rate relief than requested will reduce Idaho Power Company's projected earnings and cash flows. Because Idaho Power Company did not receive the full amount of rate relief requested in its 2003 Idaho general rate case, its projected earnings and cash flows have been reduced and IDACORP, Inc.'s and Idaho Power Company's credit ratings have been downgraded. If the Idaho Public Utilities Commission were to grant less rate relief than Idaho Power Company requests in the future, it could have a negative effect on earnings and cash flow and result in future downgrades of IDACORP, Inc.'s and Idaho Power Company's credit ratings.

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

The cost of complying with environmental regulations can harm cash flows and earnings. IDACORP, Inc. and Idaho Power Company are subject to extensive federal, state and local environmental statutes, rules and regulations relating to air quality, water quality, natural resources and health and safety. Compliance with these environmental statutes, rules and regulations involves significant capital, operating and other costs, and those costs could be even more significant in the future as a result of changes in legislation and enforcement policies. For instance, considerable attention has been focused on carbon dioxide emissions from coal-fired generating plants and their potential role in contributing to global warming and mercury emissions from coal-fired plants. The adoption of new laws and regulations to implement carbon dioxide, mercury or other emission controls could adversely affect operations and increase the cost of operating coal-fired generating plants.

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

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

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

Increased capital expenditures can significantly affect liquidity. Increases in both the number of customers and the demand for energy require expansion and reinforcement of transmission, distribution and generating systems. Because Idaho Power Company did not receive the full amount of rate relief requested in its general rate case, Idaho Power Company will have to rely more on external financing for its planned utility construction expenditures from 2005 through 2007; these large planned expenditures may weaken the consolidated financial profile of Idaho Power Company and IDACORP, Inc. Additionally, a significant portion of Idaho Power Company's facilities were 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.

A downgrade in IDACORP, Inc.'s and Idaho Power Company's credit ratings could negatively affect the companies' ability to access capital. On November 29, 2004, Standard & Poor's Ratings Services, on December 3, 2004, Moody's Investors Service, and on January 24, 2005, Fitch, Inc. each downgraded IDACORP, Inc.'s and Idaho Power Company's credit ratings. These downgrades and any future downgrades of IDACORP, Inc.'s or Idaho Power Company's credit ratings could limit the companies' ability to access the capital markets, including the commercial paper markets. In addition, IDACORP, Inc. and Idaho Power Company would likely be required to pay a higher interest rate on existing variable rate debt and in future financings.

Regulatory changes could lead to IDACORP, Inc. stock price volatility, lower IDACORP, Inc. stock prices due to short selling and disparate trading activity within the industry. On July 28, 2004, the Securities and Exchange Commission adopted Regulation SHO, which implemented changes to the manner in which short sales are regulated in the U.S. markets. On the same day, the Securities and Exchange Commission established a pilot program under Regulation SHO with respect to a number of issuers, including IDACORP, Inc. The pilot program commenced on May 2, 2005 and will continue until April 28, 2006. During the pilot program, short sales will be effected without regard to the provisions of the tick test in Rule 10a-1(a) and without compliance with any short sale price tests of the New York Stock Exchange or the Pacific Exchange, where IDACORP, Inc. common stock is listed. In the absence of any rule governing the price of short sales during the pilot program, there is a risk of increased volatility in IDACORP, Inc.'s stock, as well as the possibility of short selling at successively lower prices and the acceleration of a declining market for IDACORP, Inc. common stock. There is also the risk of disparate trading activity within the industry, as certain issuers are subject to short sale price tests and others, such as IDACORP, Inc., are not.

If IDACORP, Inc. and Idaho Power Company are unable to complete future assessments as to the adequacy of their internal control over financial reporting as required by Section 404 of the Sarbanes-Oxley Act of 2002, or if the companies complete the future assessments and identify and report material weaknesses, investors could lose confidence in the reliability of the companies' financial statements, which could decrease the value of IDACORP, Inc.'s common stock. As directed by Section 404 of the Sarbanes-Oxley Act of 2002, the Securities and Exchange Commission has adopted rules requiring public companies to include a report of management on the company's internal control over financial reporting in their Annual Reports on Form 10-K. This report is required to contain management's assessment of the effectiveness of the company's internal control over financial reporting as of the end of the most recent fiscal year. In addition, the independent registered public accounting firm auditing a public company's financial statements must also attest to and report on management's assessment of the effectiveness of the company's internal control over financial reporting. Effective internal controls are necessary for the companies to provide reliable financial reports and to prevent and detect fraud. If the companies should fail to have an effectively designed and operating system of internal control over financial reporting, this could result in decreased confidence in the reliability of the companies' financial statements, which could cause the market price of IDACORP, Inc.'s common stock to decline.

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

OVERVIEW OF FIRST QUARTER 2005 AND OUTLOOK:

This section provides an overview of recent developments in the most critical issues that IDACORP and IPC are facing, and discusses the significant items that affected IDACORP's and IPC's first quarter 2005 operating results.

Financial Results
IDACORP's basic and diluted earnings per share (EPS) for the quarter of $0.55 was a $0.04 per share increase from 2004's $0.51 per share. Net income for the quarter was $23 million, compared to $20 million in the first quarter of 2004. EPS was also reduced by the issuance of more than four million shares of common stock in December 2004.

IPC's quarterly contribution of $0.51 per share is the same as last year, but was also reduced by the IDACORP share issuance. Net income increased from $19 million to $22 million. IPC's results reflect the positive effects of a rate increase that took place on June 1, 2004, and a decrease in the effective tax rate, offset by the continued effects of below normal hydroelectric generating conditions and warmer winter weather. Increased revenue resulting from the general rate case was approximately $3 million and unrecovered power supply costs increased from $2 million to $4 million.

The remainder of IDACORP's increased EPS results from a decrease in the effective tax rate. IDACORP and IPC use an estimated annual effective tax rate for computing their provisions for income taxes on an interim basis.

Regulatory Matters
IPC has four IPUC rate proceedings that are expected to affect customers effective June 1, 2005:

Bennett Mountain: In March 2005, IPC made provisional acceptance of the newly completed Bennett Mountain Power Plant. This 164-megawatt (MW) plant will serve as a peaking resource, primarily providing electricity to customers when supplies are the lowest and wholesale costs are highest. In March 2005, IPC applied to include in Idaho retail rates a return on the estimated plant investment and other expenses of $58 million. The application requests a $9 million annual increase in rates, or 1.84 percent, to be effective June 1, 2005.

Annual PCA filing: On April 15, 2005, IPC filed the 2005-2006 power cost adjustment (PCA) with a proposed effective date of June 1, 2005. The application proposed to hold the PCA component of customer rates at the existing level, which is currently recovering approximately $71 million above base rates. The application proposes deferring the recovery of $29 million of power supply costs until the next PCA filing to help mitigate the impacts of the proposed June 1, 2005 increases related to Bennett Mountain and the rate case tax settlement.

By IPUC order, this year's PCA includes nearly $14 million related to the Irrigation Load Reduction Program that was in place in 2001.

If IPC's PCA, Bennett Mountain and rate case tax settlement adjustment recommendations are approved as filed, there will be an average increase to customer rates of 6.3 percent on an annual basis, beginning June 1, 2005. Of this increase, 4.1 percent is an ongoing rate adjustment.

Environmental Issues
IPC is currently dealing with and assessing the impact of a number of environmental matters, including water management issues such as the Eastern Snake Plain Aquifer recharge, environmental issues surrounding the relicensing of the company's hydroelectric facilities, emission allowances under the Clean Air Act and new rules regarding mercury emissions adopted under the Clean Air Act.

Power Supply Costs
Because IPC is experiencing one of the worst water years on record and its sixth consecutive year of below normal water conditions, it expects to rely on higher cost thermal generation and wholesale power purchases. Generation at IPC's hydroelectric facilities is expected to be 5.6 million MWh in 2005, compared to 2004 generation of 6.0 million MWh and normal generation of 8.7 million MWh. IPC expects power supply costs will remain high as long as below normal water conditions persist. IPC's annual PCA filing included estimated power supply costs of $155 million.

Water Conditions
Idaho is experiencing its sixth consecutive year of below normal water conditions, which has exacerbated a developing water conflict in Idaho between ground water and surface water irrigators. Efforts have been underway since 2001 to find a solution to this conflict. A March 2004 interim agreement between ground water and surface water interests stayed all administrative and legal proceedings to give the parties to the conflict one year to develop a solution. In January 2005, however, surface water irrigators not a party to the interim agreement submitted a delivery call letter and filed a petition with the Idaho Department of Water Resources requesting delivery of their senior natural flow and storage rights and for the designation of the Eastern Snake Plain Aquifer as a ground water management area. IPC is monitoring and participating in this process to protect its interests.

One proposed solution to the existing conflict between ground and surface water interests is aquifer recharge - diverting surface water to porous surface locations and permitting it to sink into the aquifer. At times, however, aquifer recharge can conflict with existing water rights and is inconsistent with state law. In April 2005, the Idaho legislature passed a resolution directing the Natural Resources Interim Committee, along with the Idaho Water Resources Board, to work with interested parties to develop a plan to implement an effective recharge program for the Eastern Snake Plain Aquifer, along with recommendations for necessary legislative changes to implement and fund such programs. IPC expects to participate in this process as necessary to protect its existing hydroelectric generation water rights.

Relicensing
On March 25, 2005, IPC received from the FERC a new 30-year operating license for its Malad project. The FERC's financial impacts analysis in the new license estimates the annual costs of measures and operations-related expenses, as licensed, will be $2 million.

IPC's most significant ongoing relicensing effort is the Hells Canyon Complex, which provides approximately two-thirds of IPC's hydroelectric generating capacity and 40 percent of its total generating capacity.

Capital Requirements
Unfavorable weather and snow pack conditions are expected to negatively impact IPC's internal cash generation in 2005. IDACORP's internally generated cash, after dividends, is now expected to provide 60 percent of 2005 capital requirements, a reduction from the 67 percent forecast earlier this year. This will require IDACORP and IPC to fund a larger portion of IPC's utility construction program with externally financed capital.

Legal Issues
IDACORP, IPC and IE have been named as defendants in a number of legal cases. No major developments occurred during the first quarter of 2005 that were not previously disclosed in IDACORP's and IPC's Annual Report on Form 10-K for the year ended December 31, 2004.

CRITICAL ACCOUNTING POLICIES:

IDACORP's and IPC's discussion and analysis of their financial condition and results of operations are based upon their consolidated financial statements, which have been prepared in accordance with generally accepted accounting principles. 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 other assumptions and factors that are believed to be reasonable under the circumstances, and are the basis for making judgments about the carrying values of assets and liabilities that are not readily apparent from other sources. IDACORP and IPC, based on their ongoing reviews, make adjustments when facts and circumstances dictate.

IDACORP's and IPC's critical accounting policies are discussed in more detail in the Annual Report on Form 10-K for the year ended December 31, 2004, and have not changed materially from that discussion.

RESULTS OF OPERATIONS:

This section of the MD&A takes a closer look at the significant factors that affected IDACORP's and IPC's earnings during the three months ended March 31, 2005. In this analysis, the results for 2005 are compared to the same period in 2004. The analysis is organized by IDACORP's reportable segments, which are IPC's utility operations and IFS. The following table presents EPS for the reportable segments, as well as for the holding company and its other subsidiaries combined, for the periods ended March 31:

EPS of common stock	Three months ended
	March 31,
	2005		2004
Utility operations *	$	0.51	$	0.51
IFS *		0.06		0.07
Other *		(0.02)		(0.07)
Total EPS	$	0.55	$	0.51

*The EPS of any one segment does not represent a direct legal interest in the assets and liabilities allocated to any one segment
but rather represents a direct equity interest in IDACORP's assets and liabilities as a whole.

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

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

IPC's system is dual peaking, with the larger peak demand generally occurring in the summer. IPC's record system peak of 2,963 MW occurred on July 12, 2002. Peak demand so far in 2005 was 2,072 MW on February 17, 2005. IPC was able to meet system load requirements and off-system sales requirements and had sufficient system reserves in place. IPC's 2004 Integrated Resource Plan (IRP) reports that customers' use of electricity continues to grow during the summer months. IPC projects that summer peaks could grow by an average of 2.5 percent per year over the ten-year IRP planning period.

The following table presents IPC's system generation for the three months ended March 31:

		Three months ended March 31,
				% of Total
		MWh		Generation
		2005	2004	2005	2004
Hydroelectric		1,382	1,751	44%	48%
Thermal		1,777	1,912	56%	52%
	Total system generation	3,159	3,663	100%	100%

Stream flow conditions have remained below average for the first three months of 2005 and current snow pack numbers suggest that stream flow conditions are likely to remain below average for the remainder of 2005. The National Weather Service Northwest River Forecast Center reports that January through March inflow into Brownlee Reservoir was 46 percent of normal. Weighted average snow pack for the Snake River Basin above Brownlee Reservoir reached its maximum accumulation on April 6, 2005, at 70 percent of the average peak accumulation. Storage in selected reservoirs upstream of Brownlee Reservoir was 85 percent of average in mid-April.

On April 29, 2005, the Northwest River Forecast Center projected Brownlee Reservoir inflow for the April through July period would be 2.2 million acre-feet (maf). This volume is 34 percent of the 30-year average of 6.3 maf and reflects the sixth consecutive year of below average inflow. Generation from IPC's hydroelectric facilities is currently expected to be 5.6 million MWh in 2005, compared to 2004 generation of 6.0 million MWh and normal generation of 8.7 million MWh. Thermal plant output was below last year, due to both planned and unplanned short-term outages as discussed below in "Fuel expense."

The estimate of normal hydroelectric generation has been reduced to 8.7 million MWh based on updated studies conducted by the Idaho Department of Water Resources. Normal hydroelectric generation represents the annual average based on stream flows for 1928-2002, adjusted to the 2002 level of depletion, and observed generation for 2003-2004. The prior estimate of 9.2 million MWH was based on the 1992 level of depletion.

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

		Three months ended March 31,
		Revenue				MWh
		2005		2004		2005	2004
Residential		$	78,776	$	77,727	1,328	1,362
Commercial			39,892		40,123	888	894
Industrial			27,013		27,664	832	826
Irrigation			689		643	12	10
	Total	$	146,370	$	146,157	3,060	3,092

Rates: Higher base rates in effect in 2005 increased general business revenue $3 million over the same quarter last year, but lower PCA rates had a partial offsetting effect of $1 million.

Usage: Revenues decreased approximately $8 million due in large part to warmer weather in 2005. Heating degree-days during this time were six percent less than in 2004.

Customers: An increase in general business customers improved revenue $6 million, as IPC continues to experience strong customer growth in its service territory.

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.

	Three months ended
	March 31,
	2005			2004

Revenue	$	32,212	$	28,121
MWh sold		645		673
Revenue per MWh	$	49.93	$	41.75

Off-system sales increases were due principally to higher prices in the wholesale markets, resulting from weakened regional hydroelectric generation conditions in the Northwest and higher natural gas prices.

Other revenues: IPC recognized approximately $3 million of revenue due to the IPUC order approving a settlement agreement that relates to the calculation of IPC's test year income tax expense in the 2003 Idaho general rate case. As a result of this settlement, IPC is recording monthly for the period June 1, 2004 through May 31, 2005, a regulatory asset totaling approximately $12 million. IPC expects to begin collecting this amount on June 1, 2005 with an adjustment to rates.

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

	Three months ended
	March 31,
	2005		2004

Purchases	$	44,078	$	18,505
MWh purchased		846		421
Cost per MWh purchased	$	52.08	$	43.98

Purchased power expense more than doubled compared to last year because of increased purchases and higher prices in the wholesale market. The increased volumes purchased are predominantly a result of reduced hydroelectric generation resulting from continued below normal stream flow conditions.

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

	Three months ended
	March 31,
	2005			2004

Fuel expense	$	25,096	$	27,504
Thermal MWh generated		1,777		1,912
Cost per MWh	$	14.12	$	14.38

Fuel expense decreased due to a seven percent decline in thermal generation. The decrease is due to several brief unplanned equipment outages at the Jim Bridger plant and to a planned outage at the North Valmy Steam Electric Generating Plant (Valmy).

The 2005 generation amount includes approximately 11,000 MWh produced during commissioning of the Bennett Mountain Power Plant. The cost of the natural gas to generate this energy was capitalized and is not reflected in fuel expense.

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." So far in 2005, net power supply costs, which are fuel and purchased power less off-system sales, exceeded those in the annual PCA forecast, resulting in the deferral of a portion of those costs to subsequent rate years when they are to be recovered in rates. As the revenues are being recovered, the deferred balances are amortized. In the first quarter of 2004, power supply costs were near forecast, resulting in a small accrual. The current year deferral is primarily the result of increased power purchases discussed above.

The following table presents the components of PCA expense for the three months ended March 31:

		Three months ended
		March 31,
		2005			2004
Current year power supply cost (deferral) accrual		$	(15,926)	$	134
Amortization of prior year authorized balances			11,509		12,430
	Total power cost adjustment	$	(4,417)	$	12,564

IFS
IFS contributed $0.06 per share in the first quarter of 2005, compared to $0.07 per share in the first quarter of 2004, principally from the generation of federal income tax credits and tax depreciation benefits related to its investments in affordable housing and historic rehabilitation developments. IFS generated $5 million of tax credits in the first quarter of both 2005 and 2004, and is expected to continue generating tax benefits near current levels.

INCOME TAXES:

Status of Audit Proceedings
In March 2005, the Internal Revenue Service began its examination of IDACORP's 2001 through 2003 tax years. Management believes that an adequate provision for income taxes and related interest charges has been made for the open years 2001 and after. The accrued amounts are classified as a current liability in taxes accrued.

Management cannot predict with certainty which financial accounts or tax adjustments will be chosen by the Internal Revenue Service for examination. IDACORP intends to vigorously defend its tax positions. It is possible that material differences in actual outcomes, costs and exposures relative to current estimates, or material changes in such estimates, could have a material adverse effect on IDACORP's consolidated financial position, results of operations or cash flows.

Income Tax Rate
In accordance with interim reporting requirements, IDACORP and IPC use an estimated annual effective tax rate for computing their provisions for income taxes on an interim basis. IDACORP's effective tax rate was 4.7 percent for the three months ended March 31, 2005, compared to 19.2 percent for the three months ended March 31, 2004. IPC's effective tax rate for the three months ended March 31, 2005 was 36.7 percent, compared to 39.4 percent for the three months ended March 31, 2004. The difference in estimated annual effective rates is primarily due to the timing and amount of regulatory flow-through tax adjustments at IPC, variation in the level of pre-tax earnings at IPC and the impact of tax credits at IFS.

IDACORP's and IPC's estimated effective tax rate for 2005 is approximately 5 percent and between 35 to 40 percent, respectively. The decline in IDACORP's estimated effective tax rate for 2005 from the earlier estimate of 10 to 15 percent is based on reductions in estimated income before income taxes due to the continued impact of below normal water conditions and weather related declines in operating revenues at Idaho Power. These reductions, when combined with the ongoing recognition of affordable housing tax credits at IFS, reduce the estimated consolidated effective tax rate.

LIQUIDITY AND CAPITAL RESOURCES:

Operating Cash Flows
IDACORP's and IPC's operating cash flows for the three months ended March 31, 2005 were $44 million and $57 million, respectively.

IDACORP's and IPC's operating cash flows decreased $14 million and $21 million, respectively, in the first quarter of 2005 compared to the same period in 2004. The decreases were mainly the result of a $13 million increase in the net power supply costs paid by IPC and a $9 million increase in 2004 employee incentive plan payments paid during the first quarter of 2005. There was no employee incentive plan payout for 2003 in the first quarter of 2004. Additionally, IDACORP's operating cash flows were positively impacted by a $2 million increase due to the wind down of IE. In the first quarter of 2004, IE used approximately $2 million in operating cash compared to minimal amounts used in 2005.

In 2005, net cash provided by operating activities will be driven by IPC, where general business revenues and the costs to supply power to general business customers have the greatest impact on operating cash flows. As IPC's service territory continues in the sixth consecutive year of below normal water conditions, IPC expects to rely more on higher-cost thermal generation and wholesale power purchases to meet its energy needs for the rest of 2005. While a significant portion of the deferred power supply costs are expected to be recovered through IPC's PCA mechanism, recovery will not take place until the 2006-2007 PCA year.

Working Capital
Changes in working capital are due primarily to an increase in cash of $38 million mainly as a result of converting investments classified as available-for-sale securities to temporary cash investments as well as timing and normal business activity.

Contractual Obligations
There have been no material changes in contractual obligations, outside of the ordinary course of business, since December 31, 2004.

Capital Requirements
IDACORP's internal cash generation after dividends is expected to provide less than the full amount of total capital requirements for 2005 through 2007. The contribution from internal cash generation is dependent primarily upon IPC's cash flows from operations, which are subject to risks and uncertainties relating to weather and water conditions, and IPC's ability to obtain rate relief to cover its operating costs. IDACORP's internally generated cash, after dividends, is expected to provide 60 percent of 2005 capital requirements, where capital requirements are defined as utility construction expenditures, excluding Allowance for Funds Used During Construction (AFDC), plus other regulated and non-regulated investments. This excludes mandatory or optional principal payments on debt obligations. 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.

The current expectation of 60 percent of 2005 capital requirements is a decline from the 67 percent anticipated earlier this year. The decline is due to unfavorable weather and snow pack conditions.

Utility Construction Program: Utility construction expenditures were $39 million for the three months ended March 31, 2005 compared to $37 million for the three months ended March 31, 2004. The increase is due to expenditures related to the Bennett Mountain Power Plant, which was operational and provisionally accepted on March 31, 2005. This plant is discussed in more detail later in "REGULATORY MATTERS - IPUC Rate Proceedings - Bennett Mountain Power Plant."

As reported in IDACORP's and IPC's Annual Report on Form 10-K for the year ended December 31, 2004, IPC's total construction expenditures are expected to be $672 million, excluding AFDC, from 2005 through 2007. For 2005, IPC expects to spend approximately $202 million, excluding AFDC, and $470 million, excluding AFDC for 2006 and 2007 combined. As 2005 progresses, the timing of certain construction expenditures may be deferred until 2006 or 2007, although the total of $672 million over the three-year period is not expected to change.

IPC's 2004 IRP includes several elements requiring significant capital expenditures in the future. Two of these projects are included in the 2005-2007 utility capital expenditure forecast: (1) $79 million of construction costs for a combustion turbine peaking resource expected to be operational in mid-2007 and (2) $2 million of planning costs for a 500-MW coal-fired plant expected to be operational in 2011. Additional generation needs identified in the 2004 IRP are expected to be met via purchased power agreements. These agreements are projected to total $7 million (19 average MW) in 2006 and $23 million (60 average MW) in 2007.

IPC's aging hydroelectric facilities require continuing upgrades and component replacement. In addition, costs related to relicensing hydroelectric facilities are expected to increase substantially. The three-year construction program anticipates $21 million of upgrades to existing hydroelectric facilities and $42 million of costs associated with relicensing of hydroelectric facilities.

Other Capital Requirements: Most of IDACORP's non-regulated capital expenditures relate to IFS's investment in affordable housing developments that help lower IDACORP's income tax liability.

Financing Programs
Credit facilities: On May 3, 2005, IDACORP entered into a $150 million five-year credit agreement with various lenders, Wachovia Bank, National Association, as joint lead arranger and administrative agent and JP Morgan Chase Bank, NA, as joint lead arranger and syndication agent and Wachovia Capital Markets, LLC and J.P. Morgan Securities Inc., as joint lead arrangers and joint book runners (IDACORP Facility). The IDACORP Facility replaced IDACORP's $150 million facility that was to expire on March 16, 2007 (Prior IDACORP Facility). The IDACORP Facility, which will be used for general corporate purposes and commercial paper back-up, will terminate on March 31, 2010. 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.

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 Wachovia Bank 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 published on the Telerate Page 3750 (or any successor page) 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 Investors Services (Moody's) and Standard & Poor's Ratings Service (S&P). The applicable margin for the floating rate advances is zero percent unless IDACORP's rating falls below Baa3 from Moody's or BBB- from S&P, at which time it would equal 0.50 percent. The applicable margin for eurodollar rate advances ranges from 0.27 percent to 0.875 percent depending upon the credit rating. In addition to the applicable margin, if the outstanding aggregate credit exposure exceeds 50 percent of the facility amount, IDACORP would pay a utilization fee ranging from 0.10 percent to 0.125 percent on outstanding loans depending on the credit rating. At May 3, 2005, the applicable margin was zero percent for floating rate advances and 0.425 percent for eurodollar rate advances and 0.125 percent for a utilization fee. 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 May 3, 2005, 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 at a per annum rate of 0.125 percent on the average daily undrawn stated amount under each letter of credit, payable quarterly in arrears and (iii) documentary and processing charges in accordance with the letter of credit issuer's standard schedule for such charges.

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

The events of default under the IDACORP Facility include (i) nonpayment of principal when due and nonpayment of reimbursement obligations under letters of credit within one business day after becoming 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, all of the outstanding shares of voting stock of IPC, (xi) unfunded liabilities of all single employer plans under the Employee Retirement Income Security Act of 1974 exceeding $50 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 in excess of $25 million, including indebtedness under the IPC Facility described below, will result in a cross default under the IDACORP Facility.

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 May 3, 2005, IPC entered into a $200 million five-year credit agreement with various lenders, Wachovia Bank, National Association, as joint lead arranger and administrative agent and JP Morgan Chase Bank, NA, as joint lead arranger and syndication agent and Wachovia Capital Markets, LLC and J.P. Morgan Securities Inc., as joint lead arrangers and joint book runners (IPC Facility). The IPC Facility replaced IPC's $200 million credit agreement that was to expire on March 16, 2007 (Prior IPC Facility). The IPC Facility, which expires on March 31, 2010, will be used for general corporate purposes and commercial paper back-up. The IPC facility provides for the issuance of loans and standby letters of credit not to exceed the aggregate principal amount of $200 million, provided that the aggregate amount of the standby letters of credit may not exceed $100 million. 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 May 3, 2005, the applicable margin for the IPC Facility was zero percent for floating rate advances and 0.35 percent for eurodollar rate advances and 0.125 percent for a utilization fee. 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 May 3, 2005, the facility fee was 0.125 percent.

In connection with the issuance of letters of credit, IPC 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 at a per annum rate of 0.125 percent on the average daily undrawn stated amount under each letter of credit, payable quarterly in arrears and (iii) documentary and processing charges in accordance with the letter of credit issuer's standard schedule for such charges.

A ratings downgrade would result in an increase in the cost of borrowing, but would not result in any default or acceleration of the debt under the IPC Facility. If there is a ratings downgrade below investment grade (BBB- or higher by S&P and Baa3 by Moody's), then IPC's authority for continuing borrowings under its regulatory approvals issued by the IPUC and the OPUC must be extended or renewed during the occurrence of the ratings downgrade. The Oregon statutes, however, permit the issuance or renewal of indebtedness maturing not more than one year after the date of such issue or renewal without approval of the OPUC. IPC has requested clarification from the IPUC that IPC's authority will not terminate but will continue for a period of 364 days from any downgrade below investment grade.

At March 31, 2005, no loans were outstanding under the Prior IDACORP Facility. At March 31, 2005 IPC had no loans outstanding under the Prior 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.

Debt Covenants: The IDACORP Facility and the IPC Facility each contain a covenant requiring each company 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. The Prior IDACORP Facility and Prior IPC Facility also contained this covenant. At March 31, 2005, the leverage ratios for both IDACORP and IPC were 52 percent. At March 31, 2005, IDACORP was in compliance with all other covenants of the Prior IDACORP Facility and IPC was in compliance with all other covenants of the Prior IPC 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 certain liens by IDACORP or any material subsidiary subject to exceptions, including the lien of IPC's first mortgage indebtedness 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.

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 certain liens by IPC or any material subsidiary subject to exceptions, including the lien of IPC's first mortgage indebtedness 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.

Long-term financings: On April 20, 2005, IPC entered into a forward-starting interest rate swap agreement, totaling $60 million, in order to manage the risk of changes in interest rates affecting the amount of future interest payments. This interest rate swap agreement relates to the anticipated issuance of first mortgage bonds to refinance the $60 million 5.83% First Mortgage Bonds that mature in September 2005. Under the term of this agreement, the value of the interest rate swap is determined based upon IPC paying a fixed rate and receiving a variable rate based on LIBOR for a 30 year term beginning in September 2005. The interest rate swap agreement provides for a mandatory early settlement date of September 30, 2005. The agreement will be accounted for in accordance with Statement of Financial Accounting Standards (SFAS) 133, "Accounting for Derivative Instruments and Hedging Activities." IPC expects to defer any gains or losses and related expenses for recovery through the regulatory process.

In April 2005, with the goal of adding additional common equity to its capital structure, IDACORP began using original issue common stock in its Dividend Reinvestment Program, rather than purchasing this stock on the open market. Approximately 5,000 shares were issued in April.

See Note 4 to IDACORP's Consolidated Financial Statements for more information regarding long-term financings.

LEGAL AND ENVIRONMENTAL ISSUES:

Legal and Other Proceedings
Alves Dairy: On May 18, 2004, Herculano and Frances Alves, dairy operators from Twin Falls, Idaho, brought suit against IPC in Idaho State District Court, Fifth Judicial District, Twin Falls County. The plaintiffs seek unspecified monetary damages for negligence and nuisance (allegedly allowing electrical current to flow in the earth, injuring the plaintiffs' right to use and enjoy their property and adversely affecting their dairy herd). On July 16, 2004, IPC filed an answer to Mr. and Mrs. Alves' complaint, denying all liability to the plaintiffs, and asserting certain affirmative defenses. The parties have begun discovery in the case. No trial date has been scheduled. On December 14, 2004, IPC filed a motion with the District Court for permission to appeal the court's denial of IPC's Motion to Disqualify the trial judge, for cause. The District Court granted the motion for permissive appeal. On February 16, 2005, IPC filed a motion for permissive appeal with the Idaho Supreme Court. On March 7, 2005, the Idaho Supreme Court denied IPC's Application to Appeal the District Court's refusal to disqualify the trial judge for cause.

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

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

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 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 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.

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

Western Energy Proceedings at the FERC: IE and IPC are involved in a number of FERC proceedings arising out of the western energy situation in California and claims that dysfunctions in the organized California markets contributed to or caused unjust and unreasonable prices in Pacific Northwest spot markets, and may have been the result of manipulations of gas or electric power markets. They include proceedings involving: (1) the chargeback provisions of the California Power Exchange (CalPX) participation agreement, which was triggered when a participant defaulted on a payment to the CalPX. Upon such a default, other participants were required to pay their allocated share of the default amount to the CalPX. This provision was first triggered by the Southern California Edison default and later by the Pacific Gas and Electric Company default. The FERC has ordered the CalPX to hold the chargeback funds and that such funds may be used to make-up individual seller shortfalls in their CalPX account at the conclusion of the California Refund proceeding. (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. 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 within five months, which has since been delayed until at least June 2005. On May 12, 2004, the FERC issued an order clarifying its earlier refund orders and denying a request by certain parties to present as evidence an earlier settlement between the California Public Utilities Commission and El Paso related to manipulation of gas pipeline capacity claiming that the settlement dollars California is receiving from El Paso ($1.69 billion) are duplicative of the FERC order changing the gas component of its refund methodology. The FERC denied requests for rehearing on November 23, 2004. On December 2, 2003, IE and others petitioned the United States Court of Appeals for the Ninth Circuit for review of the FERC's orders on California refunds. As additional FERC orders have been issued, further petitions for review have been filed, including by IE, and have been consolidated with the appeals already pending before the Ninth Circuit. On September 21, 2004, the Ninth Circuit convened the first of its case management proceedings, a procedure reserved to help organize complex cases. On October 22, the Ninth Circuit severed several issues related to the FERC's refund jurisdiction, established a schedule for briefing and held oral argument on April 12 and 13, 2005. At March 31, 2005, 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, 2005, 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) the Pacific Northwest refund proceedings wherein it was argued that the spot market in the Pacific Northwest was affected by the dysfunction in the California market, warranting refunds. The FERC rejected this claim on June 25, 2003, and denied rehearing on November 11, 2003 and February 9, 2004. The FERC orders were appealed to the Ninth Circuit. On July 21, 2004, the City of Seattle petitioned the Ninth Circuit requesting the court to direct the FERC to permit additional evidence consisting of audiotapes of Enron trader conversations and a delay in the briefing schedule in the Pacific Northwest refund. On August 2, 2004, the Ninth Circuit held the briefing schedule in abeyance pending resolution of the motion to offer additional evidence. On August 2, 2004 and August 3, 2004, respectively, the FERC and a group of parties, including IE, filed their answers in opposition to the motion to offer additional evidence. On September 29, 2004, the Ninth Circuit denied the City of Seattle's motion without prejudice to renew the request in briefing in the Pacific Northwest Refund case and established a briefing schedule with final briefs due in May of 2005. IE and IPC are unable to predict the outcome of these matters; and (4) two FERC show cause orders which resulted from a ruling of the Ninth Circuit that the FERC permit the California parties in the California refund proceeding to submit materials to the FERC demonstrating market manipulation by various sellers of electricity into California. On June 25, 2003, the FERC ordered a large number of parties including IPC to show cause why certain trading practices did not constitute gaming ("gaming") or anomalous market behavior ("partnership") in violation of the Cal ISO and CalPX Tariffs. On October 16, 2003, IPC reached agreement with the FERC Staff on the show cause orders. The "gaming" settlement was approved by the FERC on March 3, 2004. The FERC approved the motion to dismiss the "partnership" proceeding on January 23, 2004. Although the orders establishing the scope of the show cause proceedings are presently the subject of review petitions in the Ninth Circuit, the order dismissing IPC from the "partnership" proceedings was not the subject of rehearing requests. Eight parties have requested rehearing of the FERC's March 3, 2004 order approving the "gaming" settlement but the FERC has not yet acted on those requests.

In addition to the two show cause orders, on June 25, 2003, the FERC also issued an order instituting an investigation of anomalous bidding behavior and practices in the western wholesale markets for the time period May 1, 2000 through October 1, 2000 to review evidence of economic withholding of generation. IPC, along with over 60 other market participants, responded to FERC data requests and the FERC terminated its investigations as to IPC on May 12, 2004. Numerous parties have appealed the FERC's termination of this investigation as to IPC and over 30 other market participants.

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 lawsuits and legal proceedings in addition to those discussed above and in Note 5 to IDACORP's Consolidated Financial Statements. The companies believe they have meritorious defenses to all lawsuits and legal proceedings where they have been named as defendants. Resolution of any of these matters will take time, and the companies cannot predict the outcome of any of these proceedings. The companies believe that their reserves are adequate for these matters.

Environmental Issues
Idaho Water Management Issues: IPC holds water rights for generation purposes at each of its hydroelectric projects. The state of Idaho is experiencing its sixth consecutive year of below normal precipitation and stream flows. These conditions have exacerbated a developing water shortage in the state, which is manifested by a number of water issues that are of interest to IPC because of their potential impacts on generation at IPC's hydroelectric projects, including declining Snake River base flows and recharge to the Eastern Snake Plain Aquifer, a large underground aquifer that has been estimated to hold between 200-300 maf of water. With respect to base flows, observed records suggest that the base flows in the Snake River, particularly between IPC's Twin Falls and Swan Falls projects, have been in decline for several decades. The yearly average flow measured below Swan Falls declined at an average rate of 43 cubic feet per second (cfs) per year during the period 1961-2003, and observed stream flow gains between Twin Falls and Lower Salmon Falls, which are largely attributed to base flow contribution, declined at a rate of 27 cfs per year over the same period. Low flow in the Snake River near Hagerman, Idaho continues to be observed - several river gauges in that area recorded the lowest January - March Snake River flows since the early 1960s. The Snake River, at various places throughout its reach from Rexburg, Idaho to King Hill, Idaho, is connected to the Eastern Snake Plain Aquifer. 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 Eastern Snake Plain 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 designated portions of the Eastern Snake Plain Aquifer that are tributary to the Thousand Springs reach of the Snake River as a Ground Water Management Area due to the effect, exacerbated by several years of drought, of junior priority ground water withdrawals on senior surface water rights. Subsequently, in late 2001 and early 2002, junior ground water interests entered into a stipulated agreement with certain affected senior surface water users in an effort to mitigate the effects of ground water pumping. The Idaho Department of Water Resources established two ground water districts to facilitate the operation of the agreement. However, in 2003, surface water users that were not parties to the stipulated agreement filed delivery calls with the Idaho Department of Water Resources, demanding that it manage ground water withdrawals pursuant to the prior appropriation doctrine of "first in time is first in right" and curtail junior ground water rights that are depleting the aquifer and affecting flows to senior surface water rights. These delivery calls resulted in several administrative actions before the Idaho Department of Water Resources and a judicial action before the State District Court in Ada County, Idaho. Because IPC holds water rights that are dependent on the Snake River, spring flows and the overall condition of the Eastern Snake Plain Aquifer, IPC filed petitions to intervene in several of 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 Eastern Snake Plain Aquifer and ensuring that senior water rights are protected consistent with the prior appropriation doctrine and state law. As part of the interim agreement, the pending administrative and judicial processes were 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. This Interim Committee has been meeting with interested parties since March 2004 in an effort to resolve the pending controversies. One solution being explored is aquifer recharge, or using surface water supplies to increase ground water supplies by allowing the water to sink into the earth in porous locations. Under certain circumstances aquifer recharge may impact senior water rights and therefore conflict with state law. In April 2005, the Idaho Legislature passed House Concurrent Resolution No. 28 directing the Natural Resources Interim Committee, along with the Idaho Water Resource Board, to work with interested parties to develop a plan to implement an effective recharge program for the Eastern Snake Plain Aquifer along with recommendations for necessary legislative changes to implement and fund such a program. IPC expects to participate in this process as necessary to protect its existing hydroelectric generation water rights.

On January 14, 2005, seven surface water irrigation entities from above Milner Dam that are not parties to the March 2004 interim agreement submitted a delivery call letter to the Director of the Idaho Department of Water Resources requesting that the Director administer and deliver their senior natural flow and storage water rights pursuant to Idaho law. The irrigation entities contend that existing data reflects that senior surface water rights above Milner Dam have been reduced by approximately 600,000 acre-feet, a 30 percent reduction, over the past six years due, in part, to junior groundwater pumping from the Eastern Snake Plain Aquifer and that these reductions have resulted in cumulative shortages in natural flow and storage water accrual in American Falls Reservoir, a U.S. Bureau of Reclamation reservoir that supplies a portion of their senior water rights. These same entities also filed a petition with the Idaho Department of Water Resources for water rights administration and designation of the Eastern Snake Plain Aquifer as a Ground Water Management Area. On February 3, 2005, the Idaho Ground Water Appropriators, Inc., an Idaho non-profit corporation organized to promote and represent the interests of groundwater users, petitioned to intervene in the delivery call action.

Similar to the surface water irrigation entities, IPC holds storage rights in American Falls Reservoir. To the extent that groundwater pumping and the reduced surface water flows have impacted American Falls storage water rights, IPC's storage rights may have also been impacted. As such, IPC submitted a letter to the Idaho Department of Water Resources in support of the delivery call and asked the department to grant IPC intervenor status in the pending contested case. The Idaho Ground Water Appropriators, Inc. filed a motion opposing IPC's intervention. The department subsequently denied IPC's request for intervenor status. On April 19, 2005, the Director of the Idaho Department of Water Resources issued an order in response to the delivery call by the surface water irrigation entities. The order requires ground water districts to provide not less than 27,700 acre-feet of replacement water in 2005 to mitigate the predicted 2005 shortage to the surface water irrigation entities. The replacement water is to be provided in lieu of curtailment. The surface water irrigation entities are reviewing the order and considering whether further action is required. IPC is now considering the effects of this order on its water rights, and whether to file a petition requesting the department to reconsider its denial of IPC's request for intervenor status, or take other appropriate action to protect its water rights.

Clean Air: The Environmental Protection Agency issued sulfur dioxide (SO₂) allowances, as defined in the Clean Air Act amendments of 1990, based on coal consumption during established baseline years. IPC currently has more than a sufficient amount of SO₂ allowances to provide compliance for all three of its jointly owned coal-fired facilities and both of its natural gas-fired facilities. Through 2005, IPC believes that it has approximately 107,000 allowances in excess of the amount needed for Clean Air Act compliance. In addition, IPC has been granted annual allotments of allowances ranging from 15,524 to 28,622 through the year 2034. Allowances necessary for IPC's compliance requirements are up to 14,500 annually. Excess allowances owned by IPC may be held for future use, as they do not contain expiration terms. There is an active marketplace for buying and selling allowances, so that SO₂allowances determined to be excess can be sold to others. For all the foregoing reasons, IPC does not foresee any adverse effects upon its operations with regard to SO₂ emissions at this time.

In March 2005, the Environmental Protection Agency issued two new rules limiting emissions from coal-fired utility boilers, the Clean Air Interstate Rule and the Clean Air Mercury Rule. The Clean Air Interstate Rule will cap emissions of SO₂ and nitrogen oxides (NOx) in 28 eastern states and the District of Columbia. The Clean Air Interstate Rule does not impose any restrictions on emissions from any IPC facilities. IPC does not foresee any adverse effects upon its operations with regard to the Clean Air Interstate Rule.

The Clean Air Mercury Rule will limit mercury emissions from new and existing coal-fired power plants and creates a market-based cap-and-trade program that will permanently cap utility mercury emissions in two phases. The first phase cap is 38 tons beginning in 2010, with a second phase cap set at 15 tons beginning in 2018. Mercury emission allocations have not been established and emissions at IPC facilities are currently being determined. IPC is actively observing developments on this issue and control equipment technology advances. It is anticipated that this rule may require additional emission controls and expenses at the coal-fired facilities, although impacts on future plant operations, operating costs and generating capacity are not known at this time.

Other pending or proposed air regulations could require IPC's jointly owned coal fired facilities to reduce plant emissions of SO₂, NOx and other pollutants below current levels. These reductions could be required to address regional haze programs, acid rain, mercury emissions regulations and possible re-interpretations and changes to the federal Clean Air Act. Like many other coal fired facilities in the eastern and mid-western United States, the Jim Bridger plant has received information requests from the Environmental Protection Agency related to the plant's compliance with the New Source Review provisions of the Clean Air Act, which has resulted in some discussions with the Environmental Protection Agency and state regulatory authorities. IPC may incur significant costs to comply with various tighter air emissions requirements in the future. These potential costs are expected to consist primarily of capital expenditures.

Global Climate Change: The United States is currently not a party to the Kyoto Protocol to the United Nations Framework Convention on Climate Change (Protocol) that became effective for signatories on February 16, 2005. The Protocol process generally requires developed countries to cap greenhouse gas emissions at certain levels from 2008 through 2012. Although it has not ratified the Protocol, the United States may adopt a national, mandatory greenhouse gas program at some point in the future. At this time, IPC is unable to predict the potential impacts of any future mandatory governmental greenhouse gas legislative or regulatory requirements.

Greenhouse gas emissions result from the combustion of fossil fuels to generate electricity, with carbon dioxide representing the largest quantity of greenhouse gases emitted, at IPC's coal and gas generation units. Under normal water conditions, the majority of IPC's generation is comprised of hydroelectric assets that have negligible greenhouse gas emissions compared to fossil-based generation.

REGULATORY MATTERS:

General Rate Cases
Idaho: IPC filed its 2003 Idaho general rate case with the IPUC on October 16, 2003. The IPUC approved an increase of $25 million in IPC's electric rates, an average of 5.2 percent, in an order issued on May 25, 2004. The rate increase became effective on June 1, 2004. Additionally, the IPUC approved a return on equity of 10.25 percent and an overall rate of return of 7.9 percent.

On July 13, 2004, after IPC petitioned the IPUC for reconsideration of certain items, the IPUC ordered rates increased by approximately $3 million, in light of the IPUC Staff's computational errors, on or before August 1, 2004. The IPUC also agreed to reconsider an issue relating to the determination of IPC's income tax expense. As a result of this reconsideration, on September 28, 2004, the IPUC issued separate orders approving two settlement agreements entered into on August 16, 2004 between IPC and the IPUC Staff.

In Order No. 29601, the IPUC approved the modification of the general rate case order to utilize IPC's statutory income tax rates to compute test year income tax expense. The rate case tax settlement allows IPC to continue its compliance with the normalization provisions of the Internal Revenue Code of 1986, as amended, and associated Treasury Regulations, and will allow IPC to continue to receive the benefits of accelerated depreciation. As a result, IPC will compute and record monthly during the period June 1, 2004 through May 31, 2005 a regulatory asset (with interest accrued at a rate of one percent per annum) of approximately $12 million, or 2.2 percent, which is a one-year adjustment and will expire on June 1, 2006. The IPUC also granted an ongoing adjustment of approximately $12 million, or 2.25 percent, related to the rate case tax settlement. IPC has requested the increase of 4.45 percent related to the rate case tax settlement adjustments be effective June 1, 2005.

Additionally, IPUC Order No. 29600 resolved outstanding issues related to: (1) an unplanned outage at one of the two units of Valmy in the summer of 2003, (2) a matter relating to the expense adjustment rate for growth component of the PCA and (3) regulatory accounting issues related to a tax accounting method change in 2002. As a result, in September 2004, IPC established a regulatory liability of $19 million with a charge to PCA expense. A monthly credit of approximately $804,000 will be included in the PCA through May 2006, which will reduce this regulatory liability. Also in September 2004, IPC reversed a $16 million regulatory tax liability by reducing income tax expense. This regulatory tax liability was established in 2002 when IPC adopted a tax accounting method change for capitalized overhead costs.

The final result of IPC's 2003 Idaho general rate case was a $40 million increase to the base Idaho jurisdictional revenue requirement, comprised of $25 million in the initial order, $3 million related to computational errors and $12 million in the order approving the rate case tax settlement.

IPC plans to file an Idaho general rate case with the IPUC in the fall of 2005, requesting rates to be implemented on June 1, 2006. IPC is unable to predict what rate relief, if any, the IPUC will grant.

Oregon: On September 21, 2004, IPC filed an application with the OPUC to increase general rates an average of 17.5 percent or approximately $4 million annually. IPC's filing includes a request to introduce summer and non-summer rates similar to proposals that were approved in the 2003 Idaho general rate case.

IPUC Rate Proceedings
IPC currently has four rate proceedings before the IPUC: the rate case tax settlement adjustments, the Bennett Mountain Power Plant, the 2005-2006 PCA and the Energy Efficiency Tariff Rider. IPC has requested that the increases related to these filings be effective June 1, 2005. The rate case tax settlement is discussed above in "General Rate Cases - Idaho." The 2005-2006 PCA filing is discussed below in "Deferred Net Power Supply Costs - Idaho" and the Energy Efficiency Tariff Rider increase is discussed below in "Integrated Resource Plan."

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

		March 31,		December 31,
		2005		2004
Oregon deferral		$	11,478	$	12,047
Idaho PCA current year net power supply cost deferrals:
	Deferral for 2005-2006 rate year		36,285		22,778
Irrigation Lost Revenues			13,406		13,290
Idaho PCA true-up awaiting recovery:
	Remaining true-up authorized May 2004		636		11,415
	Total deferral	$	61,805	$	59,530

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

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

On April 15, 2005, IPC filed the 2005-2006 PCA with the IPUC with a proposed effective date of June 1, 2005. The application proposed to hold the PCA component of customers' rates at the existing level, which is currently recovering $71 million above base rates. By IPUC order, this year's PCA includes $12 million in lost revenues and $2 million in related interest resulting from IPC's Irrigation Load Reduction Program that was in place in 2001. IPC proposed to defer approximately $29 million, or 4.75 percent, for one year to help mitigate the impacts of the $9 million, or 1.84 percent, increase for the Bennett Mountain Power Plant and the $23 million, or 4.45 percent, increase due to the rate case tax settlement adjustments, since all three are proposed to be effective June 1, 2005. The $29 million will be recovered during the 2006-2007 PCA rate year, and IPC will earn a two percent carrying charge on this balance.

Oregon: On March 2, 2005, IPC filed for an accounting order to defer net power supply costs for the period of March 1, 2005 through February 28, 2006 in anticipation of the low water conditions IPC is currently experiencing. The net system power supply costs included in this filing were $169 million, of which $3 million related to the Oregon jurisdiction. IPC is proposing to use the same methodology for this deferral filing that was accepted in 2002 for Oregon's share of IPC's 2001 net power supply expenses. Under this methodology, IPC will earn its Oregon authorized rate of return on the deferred balance and will recover the amount through rates in future years, as approved by the OPUC.

PURPA Wind Projects
In April 2005, the IPUC approved a contract for IPC to buy power from four wind power projects under the provisions of PURPA. Each of the projects, which are located near Hagerman, Idaho, would have a nameplate rating of 10.5 MW. These four PURPA projects are expected to be completed by December 31, 2005, with their first energy dates scheduled for January 15, 2006. All four of the projects are in the same area as the Fossil Gulch project, another 10.5 MW project approved by the IPUC in 2004.

Ultimately, IPC expects to have as much as 350 MW of wind energy in its generating portfolio.

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

The IRP is filed every two years with both the IPUC and the OPUC. Prior to filing, the IRP requires extensive involvement by IPC, the IPUC Staff and the OPUC Staff, as well as customer, technological and environmental representatives and is the starting point for demonstrating prudence in IPC's resource decisions. The IPUC accepted the 2004 IRP on April 22, 2005.

Requests for Proposals: A final Request for Proposal (RFP) for 200 MW of wind-powered generation was issued on January 13, 2005, and the successful bidder is expected to be identified by June 2005. The RFP requested deliveries of energy from approximately 100 MW of wind-powered generation commencing no later than the end of 2006, and deliveries of energy from all 200 MW commencing no later than the end of 2007. The wind-powered generation RFP pre-bid meeting was held on January 27, 2005. Final bids were due on March 10, 2005. The selection committee has compiled a short list of bidders and is proceeding with proposal evaluation.

On March 30, 2005, IPC issued a formal RFP seeking bids for the construction of an 88 MW peaking resource. IPC is asking for bids for the construction of a generating facility to expand its generation capabilities to meet peak loads when electricity supplies are low and wholesale costs are high. The plant is expected to be on-line in 2007. IPC held a pre-bid conference on April 21, 2005. The Notice of Intent to Bid deadline is May 5, 2005. Actual proposals are due May 19, 2005.

Energy Efficiency Tariff Rider: The Energy Efficiency Rider is a separate fee charged to customers. The funds generated from the fee are used to promote energy efficiency and summer peak reduction programs. Currently, the Energy Efficiency Rider is 0.5 percent of total base revenues. On December 6, 2004, IPC filed an application with the IPUC requesting to increase the Energy Efficiency Rider to 1.5 percent of total base revenues effective June 1, 2005, with a subsequent increase to 2.4 percent of total base revenues effective June 1, 2007. The requested June 1, 2005 change would increase the amounts collected from customers by $5 million. Public comments concerning IPC's application were required to be filed with the IPUC by February 16, 2005. IPC expects the IPUC will issue an order in the proceeding later in 2005.

Relicensing of Hydroelectric Projects
IPC, like other utilities that operate nonfederal hydroelectric projects on qualified waterways, obtains licenses for its hydroelectric projects from the FERC. These licenses last for 30 to 50 years depending on the size, complexity, and cost of the project. IPC recently received new licenses for five of its middle Snake River projects and the Malad project. IPC's hydroelectric project license for the Hells Canyon Complex will expire in 2005 and the Swan Falls project license will expire in 2010. IPC is actively pursuing the relicensing of these projects, a process that may continue for the next ten to 15 years.

Middle Snake River Projects: The middle Snake River projects consist of the Bliss, Upper Salmon Falls, Lower Salmon Falls, Shoshone Falls and CJ Strike projects. On August 4, 2004, IPC received the FERC license orders for each of the middle Snake River projects. Each license is for a 30-year duration effective August 1, 2004. A central component of each license order is a Settlement Agreement between IPC and the U.S. Fish and Wildlife Service regarding five snail species that inhabit the middle Snake River, which are listed as threatened or endangered species under the Endangered Species Act (ESA). As a basis for the settlement, IPC and the U.S. Fish and Wildlife Service agreed that additional studies and analyses are needed in order to accurately assess the effect, if any, that the middle Snake River projects may have on one or more of the listed snail species. The Settlement Agreement provides 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 complete, IPC, in consultation with the U.S. Fish and Wildlife Service, will develop a plan that addresses project operation and the protection of listed snails for the remainder of the new license terms.

On September 2, 2004, two conservation groups, American Rivers and Idaho Rivers United, filed petitions for rehearing of the orders issuing the licenses for the middle Snake River projects. These petitions ask the FERC to vacate the licensing orders and request a determination from the U.S. Fish and Wildlife Service that the middle Snake River projects jeopardize the listed snail species. On October 4, 2004, the FERC issued an Order Granting Rehearing for Further Consideration to provide additional time to consider the matters raised by the rehearing requests. On March 4, 2005, the FERC issued an order denying the conservation groups' rehearing request. On April 28, 2005, American Rivers and Idaho Rivers United appealed this order to the U.S. Court of Appeals for the Ninth Circuit.

On September 17, 2004, Idaho Rivers United filed a complaint against the U.S. Fish and Wildlife Service in the U.S. District Court for the District of Idaho seeking judicial review of the biological opinion issued by the U.S. Fish and Wildlife Service on May 14, 2004 on the effect of the relicensing of the middle Snake River projects on the listed snail species. The complaint alleges that the U.S. Fish and Wildlife Service action in entering into and relying on the Settlement Agreement as a basis for issuing a no jeopardy determination in the biological opinion was arbitrary, capricious and contrary to law and asks the court to reverse the biological opinion and remand it to the U.S. Fish and Wildlife Service for further consideration. Neither the FERC nor IPC are parties to the action. On November 25, 2004, the U.S. Fish and Wildlife Service filed a motion to dismiss the complaint. On February 4, 2005, the court granted this motion and dismissed the complaint. Idaho Rivers United appealed this order to the U.S. Court of Appeals for the Ninth Circuit.

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

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

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

Cost estimates for the plans to implement required PM&E measures are $10 million in capital and $2 million in additional annual operation and maintenance expense. Most of the capital expenditures will occur within the first five years of the licenses. Since the plans have not yet been accepted by the FERC, the cost estimates are preliminary. Additionally, cost estimates do not include any PM&E measures that may be required as a result of the Settlement Agreement snail studies and analysis described above.

At March 31, 2005, $10 million of middle Snake River project relicensing and compliance costs were in electric plant in service. The majority of these costs, which were incurred prior to the completion of IPC's recent Idaho general rate case, were approved for recovery in rates. The remaining costs and any future costs will be submitted to regulators for recovery through the rate-making process.

Malad Project: On March 25, 2005, IPC received a new 30-year operating license for the Malad project. The new license is effective March 1, 2005 and includes license article requirements to address project operations, minimum flow release point changes to benefit aquatic species, ESA snail protection and monitoring, habitat enhancements, fish passage, recreation enhancements and historic properties. IPC is developing project plans, schedules and cost estimates for each article. The FERC's financial impacts analysis in the new license estimates the annual costs of measures and operations-related expenses, as licensed, will be $2 million.

At March 31, 2005, $3 million of Malad project relicensing costs were included in electric plant in service. Relicensing costs and costs related to the new license will be submitted to regulators for recovery through the rate-making process.

Hells Canyon Complex: The most significant ongoing relicensing effort is the Hells Canyon Complex, which provides approximately two-thirds of IPC's hydroelectric generating capacity and 40 percent of its total generating capacity. IPC developed the license application for the Hells Canyon Complex through a collaborative process involving representatives of state and federal agencies and business, environmental, tribal, customer, local government and local landowner interests. The license application was filed in July 2003 and accepted by the FERC for filing in December of 2003. The current license for the Hells Canyon Complex expires in July 2005. If a new license is not then issued, IPC will operate the project under an annual license issued by the FERC until the new multi-year license is issued. The application includes the continuation of existing, as well as proposed new measures intended to protect, mitigate and enhance fish and wildlife, protect recreational opportunities and preserve other aspects of environmental quality. The costs of these PM&E measures, as estimated in the license application, are approximately $106 million in the first five years of a license and $218 million over the following 25 years, for a total estimated cost of $324 million over a 30-year license. These cost estimates do not include estimated costs of proposed water quality measures included in the license application. These measures are the subject of ongoing state processes under Section 401 of the Clean Water Act. IPC estimates that costs associated with these water quality measures may result in an additional cost of $62 million, for a total estimated cost of $386 million. These estimated costs could increase as a result of the Hells Canyon ESA Consultation/Settlement Process (see discussion below).

In response to the filing of the license application in July 2003, various federal and state agencies, Native American Indian Tribes and other participants in the Hells Canyon Complex relicensing process filed initial comments to the license application, some of which contained additional proposed PM&E measures. IPC's preliminary estimate of the potential cost of these additional proposed measures, assuming all of the proposed measures are included as conditions in a final license, which IPC believes is unlikely, is approximately $2.5 billion over a period up to 50-years. This would result in an approximate 28 percent increase to existing base rates. These cost estimates are preliminary as federal, state, tribal and private parties participating in the relicensing proceeding are not required to file their final comments, recommendations, terms, conditions and prescriptions with the FERC until later in the relicensing process. The FERC will then consider these final comments, recommendations, terms, conditions and prescriptions under the Federal Power Act, the National Environmental Policy Act of 1969, as amended (NEPA) and other applicable federal laws, and include those conditions in the final license that the FERC determines are necessary and required to protect, mitigate and enhance those resources affected by the operation and management of the project. As such, the actual costs of the PM&E measures associated with the relicensing of the Hells Canyon Complex will not be known until the new license is issued by the FERC.

At March 31, 2005, $69 million of Hells Canyon Complex relicensing costs were included in construction work in progress. The relicensing costs are recorded and held in construction work in progress until a new multi-year license is issued by the FERC, at which time the charges are transferred to electric plant in service. Relicensing costs and costs related to a new license, as discussed above, will be submitted to regulators for recovery through the rate-making process.

NEPA Process:
NEPA requires that the FERC independently evaluate the environmental effects of relicensing the Hells Canyon Complex as proposed under the final license application (the proposed action) and also consider reasonable alternatives to the proposed action. Consistent with the requirements of NEPA, the FERC Staff will prepare an environmental impact statement for the Hells Canyon project, which the FERC will use to determine whether, and under what conditions, to issue a new license for the project. The environmental impact statement will describe and evaluate the probable effects, if any, of the proposed action and the other alternatives considered. As part of the NEPA process, the FERC initiated a scoping process to support preparation of the environmental impact statement and help ensure that all pertinent issues are identified and analyzed.

On October 20, 2003, the FERC issued Scoping Document 1 to provide interested parties with information on the relicensing of the project and solicit comments and suggestions for a preliminary list of issues and alternatives that might be addressed in the environmental impact statement. The FERC also held four scoping meetings in the fall and winter of 2003 to offer parties the opportunity for input on the scope of the environmental impact statement. Based upon comments and information received in response to Scoping Document 1, on November 24, 2004, the FERC Staff issued Scoping Document 2, which provides a tentative schedule for the environmental impact statement preparation including the filing of additional information on February 19, 2005; issuance of the Ready for Environmental Analysis Notice in February 2005; and issuance of the draft environmental impact statement in September 2005. Scoping Document 2 notes, however, that the dates for issuance of the Ready for Environmental Analysis Notice and draft environmental impact statement may change as necessary to allow the FERC to consider additional information needed to process the license application. IPC and a number of other parties participating in the Hells Canyon ESA Consultation/Settlement Process (see "Consultation/Settlement Process" discussion below) have requested that the FERC revise the schedule to enable the parties to pursue a comprehensive settlement agreement for the relicensing of the Hells Canyon Complex. IPC is working with the other interested parties to reach an agreement in principle on the relicensing issues by September 2005, which will inform and focus the FERC in its preparation of the draft environmental impact statement for the NEPA and relicensing process. The FERC granted IPC's request for a deferral on February 8, 2005, and extended the due date for filing recommendations and conditions until November 2005. The Ready for Environmental Analysis Notice is now scheduled for May 2005 and the draft environmental impact statement is scheduled to be issued in April 2006.

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

In July 2004, the FERC requested formal consultation with the National Marine Fisheries Service regarding the effects of interim Hells Canyon Complex operations on ESA-listed species and issued a notice to all interested parties of an ESA consultation meeting on September 9, 2004 to discuss how to proceed with consultation, including how to integrate the ongoing Hells Canyon Complex relicensing settlement discussion into the consultation process.

On September 7, 2004, IPC submitted a letter to the FERC regarding the September 9, 2004 consultation meeting, advising that IPC, the National Marine Fisheries Service and the U.S. Fish and Wildlife Service had explored opportunities to address ESA issues associated with the interim operations and the relicensing of the Hells Canyon Complex through a negotiated settlement process.

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

In late September 2004, IPC, the National Marine Fisheries Service, the U.S. Fish and Wildlife Service and other parties, including the states of Idaho and Oregon, the U.S. Forest Service, several Native American Indian Tribes, American Rivers, Idaho Rivers United, and Idaho irrigation and industrial entities interested in the relicensing of the Hells Canyon Complex met to continue discussions relative to the initiation of the Hells Canyon ESA Consultation/Settlement Process. As a result of that meeting, the parties established a Hells Canyon Complex settlement process in the fall of 2004, which includes a Settlement Working Group, a facilitator and separated FERC Staff. The initial objective of the Settlement Working Group was to address interim operations and anadromous fish species listed under the ESA in an effort to provide agreed upon measures to the FERC by April 2005. The primary objective of the Settlement Working Group, however, is to negotiate and develop a comprehensive settlement agreement to support the relicensing of the project, with a goal of achieving an agreement in principle by September 2005. Parties participating in the Settlement Working Group include IPC, the National Marine Fisheries Service, the U.S. Fish and Wildlife Service, the U.S. Bureau of Land Management, the U.S. Bureau of Reclamation, the U.S. Department of Agriculture - Forest Service, the State of Oregon, the State of Idaho, the Nez Perce Tribe, the Shoshone-Paiute Tribes, the Shoshone-Bannock Tribes, the Burns-Paiute Tribe, American Rivers, Idaho Rivers United, the Idaho Water Users Association, the Payette River Water Users Association, the Pioneer, Settlers and Nampa and Meridian irrigation districts, the Committee of Nine, the Idaho Farm Bureau, the Columbia River Inter-Tribal Fish Commission, the Idaho Council on Industry and the Environment, the J. R. Simplot Company and other industrial customers of IPC.

Following expedited negotiations, on January 7, 2005, IPC filed an agreement on interim operations (Interim Agreement) with the FERC. The Interim Agreement has been executed by IPC, American Rivers, Idaho Rivers United, the National Marine Fisheries Service, the U.S. Fish and Wildlife Service, the U.S. Department of Agriculture - Forest Service, the U.S. Bureau of Land Management, the Oregon Departments of Fish and Wildlife and Environmental Quality, the Nez Perce Tribe, the Shoshone-Bannock Tribes and the Shoshone-Paiute Tribes. The Interim Agreement is intended to address issues relating to operations of the Hells Canyon Complex and ESA-listed species in advance of the issuance of a new license while the parties to the settlement process negotiate a comprehensive settlement agreement. In accordance with the provisions of the Interim Agreement, IPC has agreed to implement certain measures until a new license is issued for the Hells Canyon Complex including monitoring flows above the Hells Canyon Complex to protect existing rights, the leasing and passing of certain U.S. Bureau of Reclamation flow augmentation water, continuing its fall chinook plan, identifying and monitoring potential stranding sites from March 1 through May 31 of each year and continuing to fund its hatchery program. IPC has also agreed to implement certain additional measures on an annual basis, provided that the parties remain engaged in settlement discussions intended to resolve long-term relicensing issues including, subject to certain variables, flow augmentation to aid anadromous fish migration, the shaping of U.S. Bureau of Reclamation storage water, establishing procedures to collect the data and information necessary in the relicensing settlement discussions, identifying, developing and reviewing potential structural modifications to address dissolved oxygen, total dissolved gas and seasonal water temperatures, providing water quality information to support consultations under Section 401 of the Clean Water Act and sharing information regarding native resident and anadromous fish passage through the Hells Canyon Complex. The signatories agree that the measures in the Interim Agreement are intended to provide reasonable protection for ESA-listed species during the term of the Interim Agreement and also establish a basis for comprehensive settlement discussions to continue. The Settlement Working Group, with the continuing assistance of the facilitator and separated FERC Staff commenced negotiations on the long-term settlement agreement in January 2005. Due to the number and complexity of the issues, it is anticipated that the parties to the settlement process will be required to devote substantial resources and time to the settlement effort in order to achieve the objective of reaching agreement by the fall of 2005.

Additional Information Requests:
The relicensing process permits interveners to submit additional study requests to the FERC. In the Hells Canyon Complex relicensing process, additional study requests were submitted in response to the FERC's Notice of Tendering Application issued on July 31, 2003. The FERC received a total of 123 additional study requests. On May 4, 2004, the FERC Staff responded to the additional study requests issuing to IPC a total of 14 Additional Information Requests.

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

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

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

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

On September 13, 2004, IPC filed a request with the FERC requesting that it defer taking action on the pending rehearing request because IPC and other interested parties had commenced the Hells Canyon ESA Consultation/ Settlement Process discussed above. IPC did not request, however, that the FERC defer action on the July 30, 2004 request for additional time. By letter dated October 20, 2004, the FERC Staff denied some of the requests for additional time and provided limited relief as to others.

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

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

At March 31, 2005, $1 million of Swan Falls project relicensing costs were included in construction work in progress. The relicensing costs are recorded and held in construction work in progress until a new multi-year license is issued by the FERC, at which time the charges are transferred to electric plant in service. Relicensing costs and costs related to a new license will be submitted to regulators for recovery through the rate-making process.

Regional Transmission Organization
In December 1999, the FERC, in Order No. 2000, said that all companies with transmission assets must file with the FERC to form RTOs or explain why they cannot do so. By encouraging the formation of RTOs, the FERC sought to further facilitate the formation of efficient, competitive wholesale electricity markets. In a recent developmental action, the Bonneville Power Administration, PacifiCorp and IPC filed a request to the FERC for a declaratory order stipulating that Grid West need not be an RTO under FERC Order No. 2000. The filing also seeks clarification of several formation issues including the withdrawal rights of transmission owners and various market design features.

The operational impact of Grid West, formerly RTO West, on IPC presently and for the near future should be minimal. No IPC facilities will be subject to Grid West operation until after operational authority is granted. IPC will have periodic opportunities to decide whether or not to continue participation. At the final step, signing a transmission agreement will be voluntary for IPC.

IPC has spent funds supporting the development of Grid West, and expects to continue funding this development as long as it remains a participating utility. Funding of this effort has taken two forms. First, funds have been loaned to Grid West, for the purpose of meeting its developmental expenses. IPC expects this loan to be repaid by Grid West when it commences operation. Second, IPC has incurred incremental internal costs from participating in the developmental effort, which are mostly related to travel and legal consultation. IPC has accumulated these costs in deferred expense accounts. The total accumulated cost for both types of funding through the first quarter of 2005 was approximately $3 million. At this time, IPC expects full recovery of the total accumulated expense through rates.

OTHER MATTERS:

Southwest Intertie Project
IPC began developing the Southwest Intertie Project (SWIP) in 1988. IPC's investment consists predominantly of a federal permit for a specific transmission corridor in Nevada and Idaho and also private rights-of-way in Idaho. The SWIP rights-of-way extend from Midpoint substation in south-central Idaho south through eastern Nevada to the Dry Lake area northeast of Las Vegas, Nevada. On March 31, 2005, IPC entered into an agreement with White Pine Energy Associates, LLC (White Pine), an affiliate of LS Power Development, LLC, which provides White Pine a three year exclusive option to purchase the SWIP rights-of-way from IPC. The option may be exercised in part or as a whole and, if fully exercised, will result in a net pre-tax gain to IPC of approximately $6 million.

Reliability Management System
As a result of the 2003 electric blackout in the eastern United States, the FERC is requiring electric utilities to complete a survey on training practices in 2005. IPC submitted its survey response on January 31, 2005. Implementation of Blackout Report Recommendations and other FERC and North American Electric Reliability Council policies could increase operating costs, but the extent of this effect cannot be determined at this time.

New Accounting Pronouncements
See Note 1 to the Consolidated Financial Statements for discussion of recently issued accounting pronouncements.

Inflation
IDACORP and IPC believe that inflation has caused and will continue to cause increases in certain operating expenses and the replacement of assets at higher costs. Inflation affects the cost of labor, products and services required for operations, maintenance costs and capital improvements. While inflation has not had a significant impact on IDACORP's or IPC's operations, costs for products and services are subject to increases. IPC is subject to rate-of-return regulation and the impact of inflation on the level of cost recovery under regulation. Increases in utility costs and expenses due to inflation could have an adverse effect on earnings because of the need to obtain regulatory approval to recover such increased costs and expenses.

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

IDACORP and IPC are exposed to various market risks, including changes in interest rates, changes in 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, 2005.

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, 2005, IDACORP and IPC had $120 million and $67 million, respectively, in floating 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, 2005, interest rate expense would increase and pre-tax earnings would decrease by approximately $1 million for both IDACORP and IPC.

Fixed Rate Debt: As of March 31, 2005, IDACORP and IPC had outstanding fixed rate debt of $936 million and $865 million, respectively. The fair market value of this debt was $955 million and $882 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 $76 million for IPC if interest rates were to decline by one percentage point from their March 31, 2005 levels.

On April 20, 2005, IPC entered into a forward-starting interest rate swap agreement, totaling $60 million, in order to manage the risk of changes in interest rates affecting the amount of future interest payments. This interest rate swap agreement relates to the anticipated issuance of first mortgage bonds to refinance the $60 million 5.83% First Mortgage Bonds that mature in September 2005. Under the term of this agreement, the value of the interest rate swap is determined based upon IPC paying a fixed rate and receiving a variable rate based on LIBOR for a 30 year term beginning in September 2005. The interest rate swap agreement provides for a mandatory early settlement date of September 30, 2005. The agreement will be accounted for in accordance with SFAS 133. IPC expects to defer any gains or losses and related expenses for recovery through the regulatory process.

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, 2004.

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, 2004.

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 through 2009. 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 45, "Guarantor's Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others" and did not have a significant effect on IDACORP's financial statements.

Equity Price Risk
IDACORP and IPC's equity price risk has not changed materially from that reported in the Annual Report on Form 10-K for the year ended December 31, 2004.

ITEM 4. CONTROLS AND PROCEDURES

Evaluation of disclosure controls and procedures:

IDACORP:
The Chief Executive Officer and Chief Financial Officer of IDACORP, based on their evaluation of IDACORP's disclosure controls and procedures (as defined in Exchange Act Rule 13a-15(e)) as of March 31, 2005, have concluded that IDACORP's disclosure controls and procedures are effective.

IPC:
The Chief Executive Officer and Chief Financial Officer of IPC, based on their evaluation of IPC's disclosure controls and procedures (as defined in Exchange Act Rule 13a-15(e)) as of March 31, 2005, have concluded that IPC's disclosure controls and procedures are effective.

Changes in internal control over financial reporting:

No change in IDACORP's or IPC's internal control over financial reporting occurred during the period covered by this Quarterly Report on Form 10-Q that has materially affected, or is reasonably likely to materially affect, IDACORP's or IPC's internal control over financial reporting.

PART II - OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS

Reference is made to Note 5 to the Consolidated Financial Statements in this Quarterly Report on Form 10-Q.

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

As part of their compensation, each director of IDACORP who is not an employee received a grant of 1,325 shares of common stock, equal to $40,000, on January 31, 2005. The stock was issued without registration under the Securities Act of 1933 in reliance upon Section 4(2) of the Act.

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, 2005	-	$	-
February 1 - February 28, 2005	11,925 (1)		30.17
March 1 - March 31, 2005	-		-
Total	11,925	$	30.17

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

Restrictions on Dividends:
A covenant under the IDACORP and IPC Credit Facilities as referred to below in Item 5 - "OTHER INFORMATION" requires IDACORP and IPC to maintain leverage ratios of consolidated indebtedness to consolidated total capitalization of no more than 65 percent at the end of each fiscal quarter. IPC's ability to pay dividends on its common stock held by IDACORP and IDACORP's ability to pay dividends on its common stock are limited to the extent payment of such dividends would cause their leverage ratios to exceed 65 percent. At March 31, 2005, the leverage ratios for both IDACORP and IPC were 52 percent.

IPC's articles of incorporation contain restrictions on the payment of dividends on its common stock if preferred stock dividends are in arrears. IPC has no preferred stock outstanding.

ITEM 5. OTHER INFORMATION

On May 3, 2005, IDACORP entered into a $150 million five-year credit agreement with various lenders, Wachovia Bank, National Association, as joint lead arranger and administrative agent and JP Morgan Chase Bank, NA, as joint lead arranger and syndication agent and Wachovia Capital Markets, LLC and J.P. Morgan Securities Inc., as joint lead arrangers and joint book runners. The new IDACORP facility replaced IDACORP's $150 million facility that was originally set to expire on March 16, 2007.

On May 3, 2005, IPC entered into a $200 million five-year credit agreement with various lenders, Wachovia Bank, National Association, as joint-lead arranger and administrative agent and JP Morgan Chase Bank, NA, as joint-lead arranger and syndication agent and Wachovia Capital Markets, LLC and J.P. Morgan Securities Inc., as joint lead arrangers and joint book runners. The new IPC facility replaced IPC's $200 million credit agreement that was originally set to expire on March 16, 2007.

The descriptions of the new credit facilities included in Part I, Item 2 "MD&A - LIQUIDITY AND CAPITAL RESOURCES - Financing Programs - Credit Facilities" and "-Debt Covenants" are incorporated herein by reference.

ITEM 6. EXHIBITS

*Previously Filed and Incorporated Herein by Reference

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

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

*3(a)(i)	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. File number 33-65720,as Exhibit 4(a)(ii).

*3(a)(ii)	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. File number 33-65720 as Exhibit 4(a)(iii).

*3(a)(iii)	Articles of Amendment to Restated Articles of Incorporation of IPC, as amended, as filed with the Secretary of State of Idaho on January 21, 2005. File number 1-3198, Form 8-K dated 1/20/05, as Exhibit 3.3.

*3(b)	Amended Bylaws of IPC amended on January 20, 2005, and presently in effect. File number 1-3198, Form 8-K dated 1/20/05, as Exhibit 3.2.

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

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

*3(d)(i)	Articles of Amendment to Articles of Incorporation of IDACORP, Inc. as filed with the Secretary of State of Idaho on March 9, 1998. File number 333-64737, as Exhibit 3.2.

*3(d)(ii)	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. File number 333-00139, as Exhibit 3(b).

*3(e)	Amended Bylaws of IDACORP, Inc., amended on January 20, 2005, and presently in effect. File number 1-14456, Form 8-K dated 1/20/05, as Exhibit 3.1.

*4(a)(i)	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. File number 2-3413, as Exhibit B-2.

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

	File number 1-MD, as Exhibit B-2-a, First, July 1, 1939
	File number 2-5395, as Exhibit7-a-3, Second, November 15, 1943
	File number 2-7237, as Exhibit7-a-4, Third, February 1, 1947
	File number 2-7502, as Exhibit7-a-5, Fourth, May 1, 1948
	File number 2-8398, as Exhibit7-a-6, Fifth, November 1, 1949
	File number 2-8973, as Exhibit7-a-7, Sixth, October 1, 1951
	File number 2-12941, as Exhibit2-C-8, Seventh, January 1, 1957
	File number 2-13688, as Exhibit4-J, Eighth, July 15, 1957
	File number 2-13689, as Exhibit4-K, Ninth, November 15, 1957
	File number 2-14245, as Exhibit4-L, Tenth, April 1, 1958
	File number 2-14366, as Exhibit2-L, Eleventh, October 15, 1958
	File number 2-14935, as Exhibit4-N, Twelfth, May 15, 1959
	File number 2-18976, as Exhibit4-O, Thirteenth, November 15, 1960
	File number 2-18977, as Exhibit4-Q, Fourteenth, November 1, 1961
	File number 2-22988, as Exhibit4-B-16, Fifteenth, September 15, 1964
	File number 2-24578, as Exhibit4-B-17, Sixteenth, April 1, 1966
	File number 2-25479, as Exhibit4-B-18, Seventeenth, October 1, 1966
	File number 2-45260, as Exhibit2(c), Eighteenth, September 1, 1972
	File number 2-49854, as Exhibit2(c), Nineteenth, January 15, 1974
	File number 2-51722, as Exhibit2(c)(i), Twentieth, August 1, 1974
	File number 2-51722, as Exhibit2(c)(ii), Twenty-first, October 15, 1974
	File number 2-57374, as Exhibit2(c), Twenty-second, November 15, 1976
	File number 2-62035, as Exhibit 2(c), Twenty-third, August 15, 1978
	File number 33-34222, as Exhibit 4(d)(iii), Twenty-fourth, September 1, 1979
	File number 33-34222, as Exhibit 4(d)(iv), Twenty-fifth, November 1, 1981
	File number 33-34222, as Exhibit 4(d)(v), Twenty-sixth, May 1, 1982
	File number 33-34222, as Exhibit 4(d)(vi), Twenty-seventh, May 1, 1986
	File number 33-00440, as Exhibit 4(c)(iv), Twenty-eighth, June 30, 1989
	File number 33-34222, as Exhibit 4(d)(vii), Twenty-ninth, January 1, 1990
	File number 33-65720, as Exhibit 4(d)(iii), Thirtieth, January 1, 1991
	File number 33-65720, as Exhibit 4(d)(iv), Thirty-first, August 15, 1991
	File number 33-65720, as Exhibit 4(d)(v), Thirty-second, March 15, 1992
	File number 33-65720, as Exhibit 4(d)(vi), Thirty-third, April 1, 1993
	File number 1-3198, Form 8-K dated 12/17/93, as Exhibit 4, Thirty-fourth, December 1, 1993
	File number 1-3198, Form 8-K dated 11/21/00, as Exhibit 4, Thirty-fifth, November 1, 2000
	File number 1-3198, Form 8-K dated 9/27/01, as Exhibit 4, Thirty-sixth, October 1, 2001
	File number 1-3198, Form 8-K dated 4/15/03, as Exhibit 4, Thirty-seventh, April 1, 2003
	File number 1-3198, Form 10-Q dated 6/30/03, as Exhibit 4(a)(iii), Thirty-eighth, May 15, 2003
	File number 1-3198, Form 10-Q for the quarter ended 9/30/03, as Exhibit 4(a)(iii), Thirty-ninth, October 1, 2003

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

*4(c)(i)	Agreement of IPC to furnish certain debt instruments. File number 33-65720, as Exhibit 4(f).

*4(c)(ii)	Agreement of IDACORP, Inc. to furnish certain debt instruments. File number 1-14465, Form 10-Q for the quarter ended 9/30/03, as Exhibit 4(c)(ii).

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

*4(e)	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. File number 1-14465, Form 8-K dated 9/15/98, as Exhibit 4.

*4(f)	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. File number 1-14465, Form 8-K dated 2/28/01, as Exhibit 4.1.

*4(g)	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. File number 1-14465, Form 8-K dated 2/28/01, as Exhibit 4.2.

*4(h)	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. File number 333-67748, as Exhibit 4.13.

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

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

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

*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. File number 1-3198, Form 10-Q for the quarter ended 6/30/00, as Exhibit 10(c).

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

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

*10(e)(i)	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. File number 2-62034, as Exhibit 5(s).

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

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

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

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

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

*10(f)	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. File number 2-68574, as Exhibit 5(z).

*10(g)	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. File number 2-64910, as Exhibit 5(y).

*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. File number 1-14465, 1-3198, Form 10-Q for the quarter ended 3/31/04, as Exhibit 10(h)(i).

*10(h)(ii) 1	2005 IDACORP, Inc. Executive Incentive Plan. File number 1-14465, 1-3198, Form 8-K dated 1/20/05, as Exhibit 10.2.

*10(h)(iii) 1	The 1994 Restricted Stock Plan for officers and key executives of IDACORP, Inc. and IPC effective July 1, 1994. File number 1-3198, Form 10-K for the year ended 12/31/94, as Exhibit 10(n)(iii).

*10(h)(iv) 1	Form of Restricted Stock Award Agreement. File number 1-14465, 1-3198, Form 10-Q for the quarter ended 9/30/04, as Exhibit 10(h)(iv).

*10(h)(v) 1	Form of Performance Share Award Agreement. File number 1-14465, 1-3198, Form 10-Q for the quarter ended 9/30/04, as Exhibit 10(h)(v).

*10(h)(vi) 1	The Revised Security Plan for Board of Directors - a non-qualified, deferred compensation plan effective August 1, 1996, revised March 8, 1999, as amended. File number 1-14465, 1-3198, Form 10-K for the year ended 12/31/98, as Exhibit 10(h)(iv).

*10(h)(vii) 1	IDACORP, Inc. Non-Employee Directors Stock Compensation Plan as amended on January 20, 2005. File number 1-14465, 1-3198, Form 8-K dated 1/20/05, as Exhibit 10.9.

*10(h)(viii)	Form of Change in Control Agreement between IDACORP, Inc. and Jan B. Packwood, J. LaMont Keen, James C. Miller, Darrel T. Anderson, Thomas R. Saldin and A. Bryan Kearney. File number 1-14465, Form 10-Q for the quarter ended 9/30/99, as Exhibit 10(h).

10(h)(ix) 1	IDACORP, Inc. 2000 Long-Term Incentive and Compensation Plan, as amended.

*10(h)(x) 1	Form of Stock Option Award Agreement. File number 1-14465, 1-3198, Form 10-Q for the quarter ended 9/30/04, as Exhibit 10(h)(x).

*10(h)(xi)1	IDACORP, Inc. 2000 Long-Term Incentive and Compensation Plan-Form of Restricted Stock Award Agreement (time vesting). File number 1-14465, 1-3198, Form 8-K dated 1/20/05, as Exhibit 10.4.

*10(h)(xii)1	IDACORP, Inc. 2000 Long-Term Incentive and Compensation Plan-Form of Restricted Stock Award Agreement (performance vesting). File number 1-14465, 1-3198, Form 8-K dated 1/20/05, as Exhibit 10.5.

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

*10(h)(xiv) 1	Form of Director Indemnification Agreement as signed by all Directors of IDACORP, Inc. File number 1-14465, 1-3198, Form 10-Q for the quarter ended 6/30/04, as Exhibit 10(h)(ix).

*10(h)(xv) 1	Employment Agreement, dated November 24, 2004, by and between IDACORP, Inc. and Luci K. McDonald. File number 1-14465, 1-3198, Form 8-K dated 11/24/04, as Exhibit 10.

*10(h)(xvi) 1	Consulting agreement, dated as of January 3, 2005, by and between Robert W. Stahman and IPC, including its parent IDACORP, Inc. and all subsidiaries and affiliates. File number 1-14465, 1-3198, Form 8-K dated 12/29/04, as Exhibit 10.

*10(h)(xvii)	IDACORP, Inc. and Idaho Power Company NEO 2005 Base Compensation Table. File number 1-14465, 1-3198, Form 8-K dated 1/20/05, as Exhibit 10.1.

*10(h)(xviii)	2005 IDACORP, Inc. Executive Incentive Plan NEO Award Opportunity Chart. File number 1-14465, 1-3198, Form 8-K dated 1/20/05, as Exhibit 10.3.

*10(h)(xix) 1	IDACORP, Inc. 2000 Long-Term Incentive and Compensation Plan Restricted Stock Awards (time vesting) to NEOs Chart. File number 1-14465, 1-3198, Form 8-K dated 1/20/05, as Exhibit 10.6.

*10(h)(xx) 1	IDACORP, Inc. 2000 Long-Term Incentive and Compensation Plan Restricted Stock Awards (performance vesting) to NEOs Chart. File number 1-14465, 1-3198, Form 8-K dated 1/20/05, as Exhibit 10.7.

*10(h)(xxi) 1	IDACORP, Inc. and Idaho Power Company 2005 Compensation for Non-Employee Directors of the Board of Directors. File number 1-14465, 1-3198, Form 8-K dated 1/20/05, as Exhibit 10.8.

*10(h)(xxii) 1	IDACORP, Inc. Non-Employee Directors Stock Compensation Plan, as amended on January 20, 2005. File number 1-14465, 1-3198, Form 8-K dated 1/20/05, as Exhibit 10.9.

*10(h)(xxiii) 1	Jan B. Packwood 2005 Restricted Stock Award Agreement. File number 1-14465, 1-3198, Form 8-K dated 1/20/05, as Exhibit 10.10.

*10(h)(xxiv)	Offer of employment letter dated July 9, 2004, to Thomas R. Saldin from IDACORP, Inc. File number 1-14465, 1-3198, Form 10-K for the year ended 12/31/04, as Exhibit 10(h)(xxiv).

*10(h)(xxv) 1	IDACORP, Inc. 2004 Executive Incentive Plan. File number 1-14465, 1-3198, Form 8-K dated 2/17/05, as Exhibit 10.1.

*10(h)(xxvi)	IDACORP, Inc. 2004 Executive Incentive Plan NEO Incentive Chart. File number 1-14465, 1-3198, Form 8-K dated 2/17/05, as Exhibit 10.2.

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

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

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

*10(j)	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. File number 33-65720, as Exhibit 10(m).

*10(j)(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. File number 33-65720, as Exhibit 10(m)(i).

*10(k)	Power Purchase Agreement between IPC and PPL Montana, LLC, dated March 1, 2003 and Revised Confirmation Agreement dated May 9, 2003. File number 1-3198, Form 10-Q for the quarter ended 6/30/03, as Exhibit 10(k).

10(l)	$150 Million Five-Year Credit Agreement, dated as of May 3, 2005, among IDACORP, Inc, various lenders, Wachovia Bank, National Association, as joint lead arranger and administrative agent and JP Morgan Chase Bank, NA, as joint lead arranger and syndication agent and Wachovia Capital Markets, LLC and J.P. Morgan Securities Inc., as joint lead arrangers and joint book runners.

10(m)	$200 Million Five-Year Credit Agreement, dated as of May 3, 2005, among Idaho Power Company, various lenders, Wachovia Bank, National Association, as joint lead arranger and administrative agent and JP Morgan Chase Bank, NA, as joint lead arranger and syndication agent and Wachovia Capital Markets, LLC and J.P. Morgan Securities Inc., as joint lead arrangers and joint book runners.

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

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

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

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

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

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

15	Letter Re: Unaudited Interim Financial Information.

*21	Subsidiaries of IDACORP, Inc., File number 1-14465, 1-3198, Form 10-K for the year ended 12/31/04, as Exhibit 21.

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

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

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

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

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

32(b)	IPC Section 1350 certification.

99	Earnings press release for first quarter 2005.

1 Compensatory plan

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 5, 2005	By:	/s/	Jan B. Packwood
				Jan B. Packwood
				President and Chief Executive Officer

Date	May 5, 2005	By:	/s/	Darrel T. Anderson
				Darrel T. Anderson
				Senior Vice President - Administrative Services
				and Chief Financial Officer

IDAHO POWER COMPANY

(Registrant)

Date	May 5, 2005	By:	/s/	J. LaMont Keen
				J. LaMont Keen
				President and Chief Operating Officer

Date	May 5, 2005	By:	/s/	Darrel T. Anderson
				Darrel T. Anderson
				Senior Vice President - Administrative Services
				and Chief Financial Officer

EXHIBIT INDEX


Exhibit Number

10(h)(ix)		IDACORP, Inc. 2000 Long-Term Incentive and Compensation Plan, as amended.

10(l)		$150 Million Five-Year Credit Agreement, dated as of May 3, 2005, among IDACORP, Inc, various lenders, Wachovia Bank, National Association, as joint lead arranger and administrative agent and JP Morgan Chase Bank, NA, as joint lead arranger and syndication agent and Wachovia Capital Markets, LLC and J.P. Morgan Securities Inc., as joint lead arrangers and joint book runners.

10(m)		$200 Million Five-Year Credit Agreement, dated as of May 3, 2005, among Idaho Power Company, various lenders, Wachovia Bank, National Association, as joint lead arranger and administrative agent and JP Morgan Chase Bank, NA, as joint lead arranger and syndication agent and Wachovia Capital Markets, LLC and J.P. Morgan Securities Inc., as joint lead arrangers and joint book runners.

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

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

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

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

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

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

15		Letter Re: Unaudited Interim Financial Information.

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

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

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

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

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

32(b)		Section 1350 certification. (IPC)

99		Earnings press release for first quarter 2005.

	Exact name of registrants as specified	I.R.S. Employer
Commission File	in their charters, address of principal	Identification
Number	executive offices, zip code 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
	Websites: www.idacorpinc.com
www.idahopower.com

None

IDACORP, Inc.:	42,195,500
Idaho Power Company:	39,150,812, all held by IDACORP, Inc.

Page
Part I. Financial Information:
	Item 1. Financial Statements (unaudited)
		IDACORP, Inc.:
			Consolidated Statements of Income	1
			Consolidated Balance Sheets	2-3
			Consolidated Statements of Cash Flows	4
			Consolidated Statements of Comprehensive Income	5
		Idaho Power Company:
			Consolidated Statements of Income	7
			Consolidated Balance Sheets	8-9
			Consolidated Statements of Capitalization	10
			Consolidated Statements of Cash Flows	11
			Consolidated Statements of Comprehensive Income	12
		Notes to Consolidated Financial Statements		13-29
		Reports of Independent Registered Public Accounting Firm		30-31

	Item 2. Management's Discussion and Analysis of Financial
		Condition and Results of Operations		32-60

	Item 3. Quantitative and Qualitative Disclosures About Market Risk			61

	Item 4. Controls and Procedures			62

Part II. Other Information:

	Item 1. Legal Proceedings			62

	Item 2. Unregistered Sales of Equity Securities and Use of Proceeds			62-63

	Item 5. Other Information			63

	Item 6. Exhibits			63-68

Signatures				69

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

COMMONLY USED TERMS

Cal ISO	-	California Independent System Operator
CalPX	-	California Power Exchange
EPS	-	Earnings per share
FASB	-	Financial Accounting Standards Board
FERC	-	Federal Energy Regulatory Commission
FIN	-	Financial Accounting Standards Board Interpretation
FSP	-	Financial Accounting Standards Board Staff Position
IE	-	IDACORP Energy, a non-operating subsidiary of IDACORP, Inc.
IFS	-	IDACORP Financial Services, a subsidiary of IDACORP, Inc.
IPC	-	Idaho Power Company, a subsidiary of IDACORP, Inc.
IPUC	-	Idaho Public Utilities Commission
IRP	-	Integrated Resource Plan
MD&A	-	Management's Discussion and Analysis of Financial Condition and Results of Operations
Moody's	-	Moody's Investors Service
MW	-	Megawatt
MWh	-	Megawatt-hour
OPUC	-	Oregon Public Utility Commission
PCA	-	Power Cost Adjustment
PURPA	-	Public Utilities Regulatory Policy Act of 1978
RTO	-	Regional Transmission Organization
S&P	-	Standard & Poor's Ratings Services
SFAS	-	Statement of Financial Accounting Standards

Three Months Ended