Edgar Filing: IDACORP INC

UNITED STATES SECURITIES AND EXCHANGE COMMISSION

UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D. C. 20549
FORM 10-Q

(Mark One)

X	QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES

EXCHANGE ACT OF 1934

For the quarterly period ended March 31, 2006

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

For the transition period from

	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

Former name, former address and former fiscal year, if changed since last report.

Indicate by check mark whether the registrants (1) have filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrants were required to file such reports), and (2) have been subject to such filing requirements for the past 90 days. Yes X No ___

Indicate by check mark whether the registrants are large accelerated filers, accelerated filers, or non-accelerated filers.

IDACORP, Inc.:
	Large accelerated filer	X	Accelerated filer	Non-accelerated filer
Idaho Power Company:
	Large accelerated filer		Accelerated filer	Non-accelerated filer	X

Indicate by check mark whether the registrants are shell companies (as defined in Rule 12b-2 of the Exchange Act). Yes ___ No X

Number of shares of Common Stock outstanding as of March 31, 2006:

IDACORP, Inc.:	42,792,810
Idaho Power Company:	39,150,812, all held by IDACORP, Inc.

This combined Form 10-Q represents separate filings by IDACORP, Inc. and Idaho Power Company. Information contained herein relating to an individual registrant is filed by that registrant on its own behalf. Idaho Power Company makes no representations as to the information relating to IDACORP, Inc.'s other operations.

Idaho Power Company meets the conditions set forth in General Instructions H(1)(a) and (b) of Form 10-Q and is therefore filing this Form with the reduced disclosure format.

COMMONLY USED TERMS
AFDC	-	Allowance for Funds Used During Construction
Cal ISO	-	California Independent System Operator
CalPX	-	California Power Exchange
Energy Act	-	Energy Policy Act of 2005
EPS	-	Earnings per share
ESA	-	Endangered Species Act
FASB	-	Financial Accounting Standards Board
FERC	-	Federal Energy Regulatory Commission
FIN	-	Financial Accounting Standards Board Interpretation
Fitch	-	Fitch, Inc.
FPA	-	Federal Power Act
GAAP	-	Accounting Principles Generally Accepted in the United States of America
Ida-West	-	Ida-West Energy, a subsidiary of IDACORP, Inc.
IDWR	-	Idaho Department of Water Resources
IE	-	IDACORP Energy, a subsidiary of IDACORP, Inc.
IFS	-	IDACORP Financial Services, a subsidiary of IDACORP, Inc.
IPC	-	Idaho Power Company, a subsidiary of IDACORP, Inc.
IPUC	-	Idaho Public Utilities Commission
IRP	-	Integrated Resource Plan
ITI	-	IDACORP Technologies, Inc., a subsidiary of IDACORP, Inc.
kW	-	Kilowatt
maf	-	Million acre feet
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
NEPA	-	National Environmental Policy Act of 1996
OPUC	-	Oregon Public Utility Commission
PCA	-	Power Cost Adjustment
PM&E	-	Protection, Mitigation and Enhancement
PURPA	-	Public Utility Regulatory Policies Act of 1978
RFP	-	Request for Proposal
RTO	-	Regional Transmission Organization
S&P	-	Standard & Poor's Ratings Services
SFAS	-	Statement of Financial Accounting Standards
SO₂	-	Sulfur Dioxide
Valmy	-	North Valmy Steam Electric Generating Plant
VIEs	-	Variable Interest Entities

INDEX

Page
Part I. Financial Information:
	Item 1. Financial Statements (unaudited)
		IDACORP, Inc.:
			Condensed Consolidated Statements of Income	1
			Condensed Consolidated Balance Sheets	2-3
			Condensed Consolidated Statements of Cash Flows	4
			Condensed Consolidated Statements of Comprehensive Income	5
		Idaho Power Company:
			Condensed Consolidated Statements of Income	7
			Condensed Consolidated Balance Sheets	8-9
			Condensed Consolidated Statements of Capitalization	10
			Condensed Consolidated Statements of Cash Flows	11
			Condensed Consolidated Statements of Comprehensive Income	12
		Notes to Condensed Consolidated Financial Statements		13-25
		Reports of Independent Registered Public Accounting Firm		26-27

	Item 2. Management's Discussion and Analysis of Financial
		Condition and Results of Operations		28-47

	Item 3. Quantitative and Qualitative Disclosures About Market Risk			47-48

	Item 4. Controls and Procedures			48

Part II. Other Information:

	Item 1. Legal Proceedings			49

	Item 1A. Risk Factors			49

	Item 2. Unregistered Sales of Equity Securities and Use of Proceeds			49

	Item 6. Exhibits			49-55

Signatures				56

FORWARD-LOOKING INFORMATION

This Form 10-Q contains "forward-looking statements" intended to qualify for the safe harbor from liability established by the Private Securities Litigation Reform Act of 1995. Forward-looking statements should be read with the cautionary statements and important factors included in this Form 10-Q at Part I, Item 2, "Management's Discussion and Analysis of Financial Condition and Results of Operations - Forward-Looking Information." Forward-looking statements are all statements other than statements of historical fact, including without limitation those that are identified by the use of the words "anticipates," "believes," "estimates," "expects," "intends," "plans," "predicts," "projects," "may result," "may continue" and similar expressions.

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

				Three Months Ended March 31,
				2006		2005
				(thousands of dollars except for
				per share amounts)
Operating Revenues:
	Electric utility:
		General business		$	162,183	$	146,370
		Off-system sales			104,241		32,212
		Other revenues			850		12,286
			Total electric utility revenues		267,274		190,868
	Other				6,367		5,314
		Total operating revenues			273,641		196,182

Operating Expenses:
	Electric utility:
		Purchased power			55,925		44,078
		Fuel expense			26,969		25,096
		Power cost adjustment			43,467		(4,417)
		Other operations and maintenance			61,564		55,098
		Depreciation			24,549		24,919
		Taxes other than income taxes			5,571		5,227
			Total electric utility expenses		218,045		150,001
	Other				11,799		11,284
			Total operating expenses		229,844		161,285

Operating Income (Loss):
	Electric utility				49,229		40,867
	Other				(5,432)		(5,970)
		Total operating income			43,797		34,897

Other Income					4,689		4,273

Earnings (Losses) of Unconsolidated Equity-method
Investments					(51)		663

Other Expenses					1,421		1,103

Interest Expense:
	Interest on long-term debt				14,084		14,075
	Other interest				1,090		455
		Total interest expense			15,174		14,530

Income Before Income Taxes					31,840		24,200

Income Tax Expense					6,364		1,134

Net Income				$	25,476	$	23,066

Weighted Average Common Shares Outstanding (000's)					42,473		42,210
Earnings Per Share of Common Stock (basic and diluted)				$	0.60	$	0.55
Dividends Paid Per Share of Common Stock				$	0.30	$	0.30

The accompanying notes are an integral part of these statements.

IDACORP, Inc.
Condensed Consolidated Balance Sheets
(unaudited)

			March 31,		December 31,
			2006		2005
Assets			(thousands of dollars)

Current Assets:
	Cash and cash equivalents		$	60,888	$	52,356
	Receivables:
		Customer		124,082		97,476
		Allowance for uncollectible accounts		(33,118)		(33,078)
		Employee notes		2,809		2,951
		Other		18,759		22,631
	Energy marketing assets			11,873		23,859
	Accrued unbilled revenues			30,524		38,905
	Materials and supplies (at average cost)			36,571		32,289
	Fuel stock (at average cost)			11,766		11,739
	Prepayments			15,326		18,450
	Deferred income taxes			24,755		23,922
	Regulatory assets			2,680		3,064
	Other			2,915		2,956
		Total current assets		309,830		297,520

Investments				199,190		191,623

Property, Plant and Equipment:
	Utility plant in service			3,495,734		3,477,067
	Accumulated provision for depreciation			(1,382,265)		(1,364,640)
		Utility plant in service - net		2,113,469		2,112,427
	Construction work in progress			172,912		153,124
	Utility plant held for future use			2,910		2,906
	Other property, net of accumulated depreciation			47,202		45,802
		Property, plant and equipment - net		2,336,493		2,314,259

Other Assets:
	American Falls and Milner water rights			31,585		31,585
	Company-owned life insurance			35,342		35,401
	Energy marketing assets - long-term			14,068		22,189
	Regulatory assets			380,323		415,177
	Long-term receivables (net of allowance of $1,878)			3,832		4,015
	Employee notes			2,597		2,862
	Goodwill			3,428		3,428
	Other			46,163		46,067
		Total other assets		517,338		560,724

		Total	$	3,362,851	$	3,364,126

The accompanying notes are an integral part of these statements.

IDACORP, Inc.
Condensed Consolidated Balance Sheets
(unaudited)

				March 31,		December 31,
				2006		2005
Liabilities and Shareholders' Equity				(thousands of dollars)

Current Liabilities:
	Current maturities of long-term debt			$	16,787	$	16,307
	Notes payable				59,800		60,100
	Accounts payable				51,448		83,744
	Energy marketing liabilities				12,577		24,093
	Taxes accrued				97,344		72,652
	Interest accrued				20,884		14,616
	Other				29,486		22,073
		Total current liabilities			288,326		293,585

Other Liabilities:
	Deferred income taxes				494,642		521,855
	Energy marketing liabilities - long-term				14,068		22,189
	Regulatory liabilities				370,703		345,109
	Other				132,687		132,557
		Total other liabilities			1,012,100		1,021,710

Long-Term Debt					1,021,103		1,023,580

Commitments and Contingencies (Note 5)

Shareholders' Equity:
	Common stock, no par value (shares authorized 120,000,000;
		42,792,810 and 42,656,393 shares issued, respectively)			594,419		598,706
	Retained earnings				449,994		437,284
	Accumulated other comprehensive loss				(3,091)		(3,425)
	Treasury stock (0 and 24,063 shares at cost,
		respectively)			-		(998)
	Unearned compensation				-		(6,316)
		Total shareholders' equity			1,041,322		1,025,251

			Total	$	3,362,851	$	3,364,126

The accompanying notes are an integral part of these statements.

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

				Three Months Ended
				March 31,
				2006		2005
				(thousands of dollars)
Operating Activities:
	Net income			$	25,476	$	23,066
	Adjustments to reconcile net income to net cash provided by
		operating activities:
		Unrealized losses from energy marketing activities			-		279
		Depreciation and amortization			30,595		30,611
		Deferred income taxes and investment tax credits			(26,912)		2,644
		Changes in regulatory assets and liabilities			50,420		(7,873)
		Undistributed earnings of subsidiaries			(3,413)		(3,021)
		Provision for uncollectible accounts			42		(479)
		Other non-cash adjustments to net income			(1,055)		-
		Change in:
			Accounts receivables and prepayments		(20,725)		10,795
			Accounts payable and other accrued liabilities		(28,317)		(26,586)
			Taxes accrued		24,691		1,930
			Other current assets		3,827		247
			Other current liabilities		11,864		11,824
		Other assets			(1,078)		(980)
		Other liabilities			849		1,140
			Net cash provided by operating activities		66,264		43,597
Investing Activities:
	Additions to property, plant and equipment				(48,967)		(40,725)
	Sale of non-utility assets				4		591
	Sale of emission allowances				9,921		-
	Investments in unconsolidated affiliates				(7,820)		-
	Purchase of available-for-sale securities				(4,326)		(74,606)
	Sale of available-for-sale securities				4,775		106,915
	Purchase of held-to-maturity securities				(153)		(787)
	Maturity of held-to-maturity securities				190		1,153
	Other assets				1,172		2
		Net cash used in investing activities			(45,204)		(7,457)
Financing Activities:
	Retirement of long-term debt				(2,054)		(2,832)
	Dividends on common stock				(12,766)		(12,665)
	Change in short-term borrowings				(300)		17,430
	Issuance of common stock				2,793		-
	Other assets				45		(92)
	Other liabilities				(246)		-
		Net cash provided by (used in) financing activities			(12,528)		1,841
Net increase in cash and cash equivalents					8,532		37,981
Cash and cash equivalents at beginning of period					52,356		23,403
Cash and cash equivalents at end of period				$	60,888	$	61,384

Supplemental Disclosure of Cash Flow Information:
	Cash paid during the period for:
		Income taxes		$	12,357	$	2
		Interest (net of amount capitalized)		$	8,336	$	5,859

The accompanying notes are an integral part of these statements.

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

				Three Months Ended
				March 31,
				2006		2005
				(thousands of dollars)

Net Income				$	25,476	$	23,066

Other Comprehensive Income (Loss):
	Unrealized gains (losses) on securities:
		Unrealized holding gains (losses) arising during the period,
			net of tax of $459 and ($274)		674		(524)
		Reclassification adjustment for gains included
			in net income, net of tax of ($218) and ($234)		(340)		(364)
			Net unrealized gains (losses)		334		(888)

Total Comprehensive Income				$	25,810	$	22,178

The accompanying notes are an integral part of these statements.

(This page intentionally left blank)

Idaho Power Company
Condensed Consolidated Statements of Income
(unaudited)

			Three Months Ended
			March 31,
			2006				2005
			(thousands of dollars)
Operating Revenues:
	General business		$	162,183	$	146,370
	Off-system sales			104,241		32,212
	Other revenues			850		11,878
		Total operating revenues		267,274		190,460

Operating Expenses:
	Operation:
		Purchased power		55,925		44,078
		Fuel expense		26,969		25,096
		Power cost adjustment		43,467		(4,417)
		Other		47,770		41,219
	Maintenance			13,794		13,441
	Depreciation			24,549		24,919
	Taxes other than income taxes			5,571		5,227
		Total operating expenses		218,045		149,563

Income from Operations				49,229		40,897

Other Income (Expense):
	Allowance for equity funds used during construction			1,464		1,455
	Earnings of unconsolidated equity-method investment			3,313		3,901
	Other income			2,885		2,705
	Other expense			(1,677)		(1,677)
		Total other income		5,985		6,384

Interest Charges:
	Interest on long-term debt			13,400		13,176
	Other interest			1,105		860
	Allowance for borrowed funds used during construction			(844)		(736)
		Total interest charges		13,661		13,300

Income Before Income Taxes				41,553		33,981

Income Tax Expense				16,532		12,472

Net Income			$	25,021	$	21,509

The accompanying notes are an integral part of these statements.

Idaho Power Company
Condensed Consolidated Balance Sheets
(unaudited)

				March 31,		December 31,
				2006		2005
Assets				(thousands of dollars)

Electric Plant:
	In service (at original cost)			$	3,495,734	$	3,477,067
	Accumulated provision for depreciation				(1,382,265)		(1,364,640)
		In service - net			2,113,469		2,112,427
	Construction work in progress				170,995		149,814
	Held for future use				2,910		2,906

			Electric plant - net		2,287,374		2,265,147

Investments and Other Property					79,929		68,049

Current Assets:
	Cash and cash equivalents				57,799		49,335
	Receivables:
		Customer			75,758		49,830
		Allowance for uncollectible accounts			(873)		(833)
		Notes			3,058		3,273
		Employee notes			2,809		2,951
		Related parties			443		637
		Other			4,551		7,399
	Accrued unbilled revenues				30,524		38,905
	Materials and supplies (at average cost)				34,508		30,451
	Fuel stock (at average cost)				11,766		11,739
	Prepayments				14,387		17,532
	Regulatory assets				2,680		3,064

			Total current assets		237,410		214,283

Deferred Debits:
	American Falls and Milner water rights				31,585		31,585
	Company-owned life insurance				35,342		35,401
	Regulatory assets				380,323		415,177
	Employee notes				2,597		2,862
	Other				42,137		42,187

			Total deferred debits		491,984		527,212

	Total			$	3,096,697	$	3,074,691

The accompanying notes are an integral part of these statements.

Idaho Power Company
Condensed Consolidated Balance Sheets
(unaudited)

				March 31,		December 31,
				2006		2005
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			373,546		361,256
		Accumulated other comprehensive loss			(3,091)		(3,425)

			Total common stock equity		949,942		937,318

	Long-term debt				982,713		983,720

			Total capitalization		1,932,655		1,921,038

Current Liabilities:
	Long-term debt due within one year				1,064		-
	Accounts payable				48,605		79,433
	Notes and accounts payable to related parties				482		153
	Taxes accrued				98,047		72,994
	Interest accrued				20,106		14,105
	Deferred income taxes				2,210		3,064
	Other				27,478		19,182

			Total current liabilities		197,992		188,931

Deferred Credits:
	Deferred income taxes				481,038		507,880
	Regulatory liabilities				370,703		345,109
	Other				114,309		111,733

			Total deferred credits		966,050		964,722


Commitments and Contingencies (Note 5)

			Total	$	3,096,697	$	3,074,691

The accompanying notes are an integral part of these statements.

Idaho Power Company
Condensed Consolidated Statements of Capitalization
(unaudited)

				March 31,				December 31,
				2006		%		2005			%
				(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				373,546				361,256
	Accumulated other comprehensive loss				(3,091)				(3,425)
		Total common stock equity			949,942		49		937,318	49

Long-Term Debt:
	First mortgage bonds:
		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
		5.30% Series due 2035			60,000				60,000
			Total first mortgage bonds		785,000				785,000

	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
	Note guarantee due within one year				(1,064)				-
	Unamortized premium/discount - net				(3,268)				(3,325)

			Total long-term debt		982,713		51		983,720	51

Total Capitalization				$	1,932,655		100	$	1,921,038	100

The accompanying notes are an integral part of these statements.

Idaho Power Company
Condensed Consolidated Statements of Cash Flows
(unaudited)

				Three Months Ended
				March 31,
				2006		2005
				(thousands of dollars)
Operating Activities:
	Net income			$	25,021	$	21,509
	Adjustments to reconcile net income to net cash provided by
		operating activities:
		Depreciation and amortization			25,998		26,676
		Deferred income taxes and investment tax credits			(26,564)		2,083
		Changes in regulatory assets and liabilities			50,420		(7,873)
		Undistributed earnings of subsidiary			(3,313)		(3,021)
		Provision for uncollectible accounts			42		(479)
		Other non-cash adjustments to net income			(1,464)		-
		Gain on sale of assets			(109)		-
		Change in:
			Accounts receivables and prepayments		(19,411)		11,813
			Accounts payable		(26,851)		(26,488)
			Taxes accrued		25,053		20,864
			Other current assets		4,052		890
			Other current liabilities		11,958		12,512
		Other assets			(1,162)		(1,106)
		Other liabilities			2,381		(238)
			Net cash provided by operating activities		66,051		57,142

Investing Activities:
	Additions to utility plant				(48,126)		(38,719)
	Purchase of available-for-sale securities				(4,326)		(74,606)
	Sale of available-for-sale securities				4,775		106,915
	Sale of emission allowances				9,921		-
	Investments in unconsolidated affiliate				(7,820)		-
	Other assets				738		104
		Net cash used in investing activities			(44,838)		(6,306)

Financing Activities:
	Dividends on common stock				(12,731)		(12,665)
	Other assets				45		(92)
	Other liabilities				(63)		-
		Net cash used in financing activities			(12,749)		(12,757)

Net increase in cash and cash equivalents					8,464		38,079
Cash and cash equivalents at beginning of period					49,335		17,679

Cash and cash equivalents at end of period				$	57,799	$	55,758

Supplemental Disclosure of Cash Flow Information:
	Cash paid (received) during the period for:
		Income taxes paid to (received from) parent		$	21,809	$	(7,037)
		Interest (net of amount capitalized)		$	7,112	$	4,989

The accompanying notes are an integral part of these statements.

Idaho Power Company
Condensed Consolidated Statements of Comprehensive Income
(unaudited)

				Three Months Ended
				March 31,
				2006		2005
				(thousands of dollars)

Net Income				$	25,021	$	21,509

Other Comprehensive Income (Loss):
	Unrealized gains (losses) on securities:
		Unrealized holding gains (losses) arising during the period,
			net of tax of $459 and ($274)		674		(524)
		Reclassification adjustment for gains included
			in net income, net of tax of ($218) and ($234)		(340)		(364)
			Net unrealized gains (losses)		334		(888)

Total Comprehensive Income				$	25,355	$	20,621

The accompanying notes are an integral part of these statements.

IDACORP, INC. AND IDAHO POWER COMPANY
NOTES TO CONDENSED 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). These Notes to the Condensed 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 formed in 1998 whose principal operating subsidiary is IPC. IDACORP is subject to the provisions of the Public Utility Holding Company Act of 2005, which provides certain access to books and records to the Federal Energy Regulatory Commission (FERC) and state utility regulatory commissions and imposes certain record retention and reporting requirements on IDACORP. The Public Utility Holding Company Act of 1935 was repealed, effective February 8, 2006.

IPC is an electric utility with a service territory covering approximately 24,000 square miles in southern Idaho and eastern Oregon. IPC is regulated by the 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 subsidiaries include:

IDACORP Financial Services, Inc. (IFS) - holder of affordable housing and other real estate investments;
IdaTech, LLC (IdaTech) - developer of integrated fuel cell systems, over 95 percent owned by IDACORP's wholly-owned subsidiary IDACORP Technologies, Inc. (ITI);
IDACOMM, Inc. (IDACOMM) - provider of telecommunications services and commercial Internet services;
Ida-West Energy (Ida-West) - operator of small hydroelectric generation projects that satisfy the requirements of the Public Utility Regulatory Policies Act of 1978 (PURPA); and
IDACORP Energy (IE), a marketer of electricity and natural gas, which wound down its operations during 2003.

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

Through IFS, IDACORP also holds significant variable interests in VIEs for which it is not the primary beneficiary. These VIEs are historic rehabilitation and affordable housing developments in which IFS holds limited partnership interests ranging from five to 99 percent. These investments were acquired between 1996 and 2005. IFS' maximum exposure to loss in these developments was $96 million at March 31, 2006.

Financial Statements
In the opinion of IDACORP and IPC, the accompanying unaudited condensed consolidated financial statements contain all adjustments necessary to present fairly their consolidated financial positions as of March 31, 2006, and consolidated results of operations for the three months ended March 31, 2006 and 2005 and consolidated cash flows for the three months ended March 31, 2006 and 2005. 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, 2005. The results of operations for the interim periods are not necessarily indicative of the results to be expected for the full year.

Stock-Based Compensation
Effective January 1, 2006, IDACORP and IPC adopted Statement of Financial Accounting Standards No. 123 (revised 2004), "Share-Based Payment" (SFAS 123R) using the modified prospective application method. SFAS 123R changes measurement, timing and disclosure rules relating to share-based payments, requiring that the fair value of all share-based payments be expensed.

The adoption of SFAS 123R did not have a material impact on IDACORP's or IPC's financial statements for the three months ended March 31, 2006. IDACORP's and IPC's Condensed Consolidated Statements of Income for the three months ended March 31, 2005 do not reflect any changes from the adoption of SFAS 123R. The following table illustrates what net income and earnings per share would have been had the fair value recognition provisions of SFAS 123 been applied to stock-based employee compensation in 2005.

			March 31, 2005
			(thousands of dollars except
			for per share amounts)
IDACORP
Net income, as reported				$	23,066
Add: Stock-based employee compensation expense included in
	reported net income, net of related tax effects				175
Deduct: Stock-based employee compensation expense
	determined under fair value based method for all awards,
	net of related tax effects				415
		Pro forma net income		$	22,826

EPS of common stock:
	Basic and diluted - as reported			$	0.55
	Basic and diluted - pro forma				0.54

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

For purposes of these 2005 pro forma calculations, the estimated fair value of the options, restricted stock and performance shares is being amortized to expense over the vesting period. The fair value of the restricted stock and performance shares was the market price of the stock on the date of grant. The fair value of an option award was estimated at the date of grant using a binomial option-pricing model. Expenses related to forfeited awards were reversed in the period in which the forfeit occurred.

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

The diluted EPS computation excluded 675,400 common stock options in 2006 and 1,051,114 in 2005 because the options' exercise prices were greater than the average market price of the common stock during those periods. In total, 1,410,765 options were outstanding at March 31, 2006, with expiration dates between 2010 and 2016.

Reclassifications
Certain prior year amounts have been reclassified to conform to the current year presentation. Net income and shareholders' equity were not affected by these reclassifications.

2. INCOME TAXES:

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. IDACORP's effective rate for the three months ended March 31, 2006 was 20.0 percent, compared to 4.7 percent for the three months ended March 31, 2005. IPC's effective tax rate for the three months ended March 31, 2006 was 39.8 percent, compared to 36.7 percent for the three months ended March 31, 2005. The differences in estimated annual effective tax rates are primarily due to the increase in pre-tax earnings at IDACORP and IPC, the loss of the capitalized overhead tax deduction at IPC, timing and amount of regulatory flow-through tax adjustments at IPC and slightly lower tax credits from IFS.

Status of Audit Proceedings
In March 2005, the Internal Revenue Service (IRS) began its examination of IDACORP's 2001 through 2003 tax years. In October 2005, the Idaho State Tax Commission (ISTC) also began its examination of the same 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.

As of March 31, 2006 the IRS had substantially completed its issue development and research for 2001-2003, with the exception of the capitalized overhead cost method discussed below. However, the examination is not complete and management cannot predict which examined items may be adjusted by the IRS. The ISTC issued its examination report and assessment for 2001-2003 on March 30, 2006. The adjustments made by the ISTC were minor as was the assessment of tax and interest.

Capitalized Overhead Costs: On August 2, 2005, the IRS and the Treasury Department issued guidance interpreting the meaning of "routine and repetitive" for purposes of the simplified service cost and simplified production methods of the Internal Revenue Code section 263A uniform capitalization rules. The guidance was issued in the form of a revenue ruling (Rev. Rul. 2005-53) and proposed and temporary regulations. The regulations are effective for tax years ending on or after August 2, 2005, and the revenue ruling applies for all prior open years. Both pieces of guidance take a more restrictive view of the definition of self-constructed assets produced by a taxpayer on a "routine and repetitive" basis than did treasury regulations in effect at the time IPC changed to the simplified service cost method.

Generally, section 263A requires the capitalization of all direct costs and those indirect costs, known as "mixed service costs", which directly benefit or are incurred by reason of the production of property by a taxpayer. The treasury regulations for section 263A provide several "safe-harbor" methods taxpayers may adopt in order to comply with the statute. The simplified service cost method is one of the methods available for the calculation of indirect overhead (mixed service costs) cost capitalization. IPC changed to the simplified service cost method for both the self-construction of utility plant and production of electricity beginning with its 2001 federal income tax return.

For IPC, the simplified service cost method produces a current tax deduction for costs capitalized to electricity production that are capitalized into fixed assets for financial accounting purposes. Deferred income tax expense has not been provided for this deduction because the prescribed regulatory tax accounting treatment does not allow for inclusion of such deferred tax expense in current rates. Rate regulated enterprises are required to recognize such adjustments as regulatory assets if it is probable that such amounts will be recovered from customers in future rates.

For fiscal years 2002 through 2004, the simplified service cost method decreased IPC's income tax expense by $60 million and resulted in cash refunds from federal and state tax authorities of $75 million. For years 2004 and prior open tax years, if IPC cannot satisfy the guidance in Rev. Rul. 2005-35 it would be required to use another method of uniform capitalization, which is expected to be less favorable to IPC than the simplified service cost method. A less favorable method could result in a one time charge to earnings and reduced cash flow that could be partially offset by carryover tax credits, accelerated tax depreciation, changes in tax regulations and state regulatory recovery.

The temporary regulations are effective for IPC's 2005 and future tax years and, as drafted, preclude IPC from using this method for self-constructed assets. In the third quarter of 2005 IPC reversed its previously accrued 2005 tax deduction for capitalized overhead costs for both financial reporting and estimated tax payment purposes, and has not accrued a deduction for 2006. IPC is currently evaluating alternatives for a new uniform capitalization method.

3. COMMON STOCK:

During the three months ended March 31, 2006, IDACORP entered into the following transactions involving its common stock:

61,168 original issue shares were granted to participants in the 2000 Long-Term Incentive and Compensation Program and
75,249 original issue shares were issued under the Dividend Reinvestment and Stock Purchase Plan and the Employee Savings Plan.

On January 1, 2006, IDACORP adopted SFAS 123R. SFAS 123R requires that any amounts of unearned compensation related to stock-based compensation be eliminated against common equity. Prior to January 1, 2006, IDACORP had aggregated its unearned compensation balances with treasury stock on its consolidated balance sheets.

4. FINANCING:

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

				March 31,		December 31,
				2006		2005
First mortgage bonds:
	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
	5.30% Series due 2035				60,000		60,000
			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					(3,268)		(3,325)
Debt related to investments in affordable housing					46,474		48,481
Other subsidiary debt					7,639		7,686
	Total				1,037,890		1,039,887
Current maturities of long-term debt					(16,787)		(16,307)

			Total long-term debt	$	1,021,103	$	1,023,580

(a)		Humboldt County Pollution Control Revenue bonds are secured by first mortgage bonds, bringing the total first
		mortgage bonds outstanding at March 31, 2006 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 a registration statement that can be used for the issuance of an aggregate principal amount of $240 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 that mature in less than two years or that are of an equal or higher interest rate, or prior lien bonds.

As of March 31, 2006, IPC could issue under the mortgage approximately $452 million of additional first mortgage bonds based on retired first mortgage bonds and $584 million of additional first mortgage bonds based on unfunded property additions. As of March 31, 2006, unfunded property additions were approximately $973 million. 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, workmen's 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.

At March 31, 2006, IFS had $46 million of debt related to investments in affordable housing with interest rates ranging from 3.65 percent to 8.59 percent, due between 2006 and 2010. The investments in affordable housing developments that collateralize this debt had a net book value of $73 million at March 31, 2006. IFS' $14 million Series 2003-1 tax credit note is non-recourse to both IFS and IDACORP. The $8 million Series 2003-2 tax credit note and other outstanding debt are recourse only to IFS.

Credit Facilities
IDACORP has a $150 million five-year credit facility that expires on March 31, 2010. At March 31, 2006, no loans were outstanding on IDACORP's credit facility and $60 million of commercial paper was outstanding.

At March 31, 2006, IPC had regulatory authority to incur up to $250 million of short-term indebtedness. IPC has a $200 million five-year credit facility that expires on March 31, 2010. At March 31, 2006, no loans were outstanding on IPC's credit facility and no commercial paper was outstanding.

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, 2006. 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 Financial Accounting Standards Board Interpretation No. 45, "Guarantor's Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others," and did not have a material effect on IDACORP's financial statements.

LEGAL PROCEEDINGS

Reference is made to IDACORP's and IPC's Annual Report on Form 10-K for the year ended December 31, 2005, for a discussion of all material pending legal proceedings to which IDACORP and IPC and their subsidiaries were parties as of the date of such report. The following discussion provides a summary of these pending legal proceedings and material developments that occurred in the proceedings during the period covered by this report with respect to the previously reported proceedings referred to above and describes any new material proceedings instituted during the period covered by this report.

Proceedings Relating to the Western Power Market

IDACORP, IPC and/or IE are involved in a number of proceedings which relate to the western power markets.

Public Utility District No. 1 of Grays Harbor County, Washington: On December 16, 2005, the Honorable Robert H. Whaley, sitting by designation in the U.S. District Court for the Southern District of California, issued an Order Setting Status Conference wherein, rather than expressly ruling on IDACORP, IPC and IE's motion to dismiss Grays Harbor's amended complaint, he ruled that either Grays Harbor or the Companies may, within 45 days of the date of the order, petition the FERC to weigh in on this case in light of "the extensive hearings . . . already undertaken by FERC in the Northwest refund proceeding" which may be relevant to this case. On January 27, 2006 Grays Harbor and the Companies jointly filed a stipulation requesting that the court stay the action and extend the time in which the parties may petition the FERC by sixty days to March 31, 2006, stating that the parties felt the case was appropriate for mediation prior to further proceedings. On January 31, 2006, the court approved the stipulation staying the case until March 31, 2006 and setting a status conference for April 14, 2006. The parties selected a mediator, and the initial mediation session occurred on April 24, 2006. Following the April 24 session, a second mediation session was scheduled for May 17, 2006. The parties have filed a joint stipulation extending the stay in the case through May 31, 2006 and rescheduling the status conference to a date after June 1, 2006. The Companies intend to vigorously defend their position in this proceeding and believe this matter will not have a material adverse effect on their consolidated financial positions, results of operations or cash flows.

Port of Seattle: On March 7, 2006, the U.S. Court of Appeals for the Ninth Circuit heard argument on the Port of Seattle's appeal of the U.S. District Court for the Southern District of California's dismissal of its complaint with prejudice. On March 30, 2006, the Ninth Circuit issued an order denying the Port of Seattle's appeal and dismissing the case. If there are any efforts by the Port of Seattle to seek rehearing or reconsideration, or to pursue further appeals, the Companies intend to continue vigorously defending their position in this proceeding. The Companies believe this matter will not have a material adverse effect on their consolidated financial positions, results of operations or cash flows.

Wah Chang: Following the October 18, 2005 consolidation of Wah Chang's appeal to the U.S. Court of Appeals for the Ninth Circuit of the dismissal of the case with Wah Chang v. Duke Energy Trading and Marketing and a revised briefing schedule, IDACORP, IPC and IE filed an answering brief on November 30, 2005 and Wah Chang filed its reply brief on January 6, 2006. The appeal has now 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 this matter will not have a material adverse effect on their consolidated financial positions, results of operations or cash flows.

City of Tacoma: The City of Tacoma's March 10, 2005 appeal to the U.S. Court of Appeals for the Ninth Circuit of the dismissal of the case by Judge Whaley 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 this matter will not have a material adverse effect on their consolidated financial positions, results of operations or cash flows.

Wholesale Electricity Antitrust Cases I & II: In these cross-actions against multiple defendants including IE and IPC which, following remand, are back in the California Superior Court in San Diego, the Court granted preliminary approval of the Reliant Settlement on January 6, 2006 and scheduled a hearing to consider final approval for April 28, 2006. The court did not rule on the Reliant Settlement at the April 28, 2006 hearing and scheduled another hearing for July 14, 2006. If the Court does not grant final approval of the Reliant Settlement, Reliant may choose to reactivate its cross-complaint against the defendants including IE and IPC. Similarly, should the Court for any reason fail to approve the Reliant Settlement, IE and IPC may withdraw from the stipulation agreement dismissing the Reliant cross-complaint against IE and IPC with prejudice, by giving ten days' advance written notice. The Companies intend to vigorously defend their position in this proceeding and believe this matter will not have a material adverse effect on their consolidated financial positions, results of operations or cash flows.

Western Energy Proceedings at the FERC:

California Refund: In December 2005, IE and IPC reached a tentative agreement with the California Parties settling matters encompassed by the California Refund proceeding including IE's and IPC's cost filing and refund obligation. On January 20, 2006, IE and IPC and the California Parties jointly filed a request with the FERC asking that the FERC defer ruling on IE's and IPC's cost filing for thirty days so the parties could complete and file the settlement agreement with the FERC. On January 26, 2006, the FERC granted the requested deferral and required that the settlement be filed by February 17, 2006. On February 17, 2006, IE and IPC jointly filed with the California Parties (Pacific Gas & Electric Company, San Diego Gas & Electric Company, Southern California Edison, the California Public Utilities Commission, the California Electricity Oversight Board, the California Department of Water Resources and the California Attorney General) an Offer of Settlement with the FERC. Final comments on the settlement were filed by March 20, 2006. If the settlement is approved by the FERC, IE and IPC would assign $24.25 million of the rights to accounts receivable from the California Independent System Operator and California Power Exchange (CalPX) to the California Parties to pay into an escrow account for refunds to settling parties. Amounts from that escrow not used for settling parties and $1.5 million of the remaining IE and IPC receivables which are to be retained by the CalPX would be available to fund, at least partially, payment of the claims of any non-settling parties if they prevail in the remaining litigation of this matter. Approximately $10.25 million of the remaining IE and IPC receivables would be released to IE and IPC. Non-settling parties had until March 9, 2006 to elect to become an additional settling party. The majority of non-settling parties chose to opt-out of the settlement. The FERC has not yet ruled on the Offer of Settlement. On March 27, 2006, the FERC issued an order rejecting the cost filing made by IPC and IE on September 14, 2005. On April 26, 2006, IPC and IE filed a request for rehearing of the FERC's order rejecting their cost filing. IE and IPC are unable to predict the outcome of these matters.

California Power Exchange Chargeback: Based upon the Offer of Settlement filed with the FERC on February 17, 2006 between the California Parties and IE and IPC and discussed above in "California Refund", the California Parties supported a motion filed by IE and IPC with the FERC seeking an Order Directing Return of Chargeback Amounts currently held by the California Power Exchange totaling $2.27 million. The FERC has not yet ruled on the Order Directing Return of Chargeback Amounts.

Market Manipulation: The Offer of Settlement filed with the FERC on February 17, 2006 between the California Parties and IE and IPC and discussed above in "California Refund", if approved, would terminate the investigations the FERC initiated without finding of wrongdoing by IE or IPC, and would provide for the disposition of the "gaming" settlement.

Pacific Northwest Refund: On September 24, 2001, the FERC Administrative Law Judge submitted recommendations and findings to the FERC finding that prices in the Pacific Northwest during the December 25, 2000 through June 20, 2001 time period should be governed by the Mobile-Sierra standard of public interest rather than the just and reasonable standard, that the Pacific Northwest spot markets were competitive and that no refunds should be allowed. The FERC approved these recommendations on June 25, 2003 and multiple parties then appealed to the Ninth Circuit Court of Appeals. IE and IPC were parties in the FERC proceeding and are participating in the appeal. Briefing on the appeal was completed on May 25, 2005; however, no date has been set for oral argument. IE and IPC are unable to predict the outcome of these matters.

Other Litigation

Shareholder Lawsuits: On March 29, 2006, the U.S. District Court for the District of Idaho (Judge Edward J. Lodge) issued an Order adopting the Report and Recommendation of Magistrate Judge Williams issued on September 14, 2005 granting the defendants' (IDACORP and certain of its officers and directors) motion to dismiss because plaintiffs failed to satisfy the pleading requirements for loss causation. However, Judge Lodge modified the Report and Recommendation and ruled that plaintiffs could file an amended complaint only as to the loss causation element. Plaintiffs filed an amended complaint on May 1, 2006. IDACORP and the other defendants intend to defend themselves vigorously against the allegations in the amended complaint. IDACORP cannot, however, predict the outcome of these matters.

Powerex: On March 30, 2006, the U.S. District Court for the District of Idaho dismissed this case, with prejudice, pursuant to an agreed resolution of the matter between Powerex and IE and IDACORP. The resolution did not have a material adverse effect on IDACORP's consolidated financial position, results of operations or cash flows.

Western Shoshone National Council: On April 10, 2006, the Western Shoshone National Council (which purports to be the governing body of the Western Shoshone Nation) and certain of its individual tribal members filed a First Amended Complaint and Demand for Jury Trial in the U.S. District Court for the District of Nevada, naming IPC and other unrelated entities as defendants.

Plaintiffs allege that IPC's ownership interest in certain land, minerals, water or other resources was converted and fraudulently conveyed from lands in which the plaintiffs had historical ownership rights and Indian title dating back to the 1860's or before. Although it is unclear from the complaint, it appears plaintiffs' claims relate primarily to lands within the state of Nevada. Plaintiffs seek a judgment declaring their title to land and other resources, disgorgement of profits from the sale or use of the land and resources, a decree declaring a constructive trust in favor of the plaintiffs of IPC's assets connected to the lands or resources, an accounting of money or things of value received from the sale or use of the lands or resources, monetary damages in an unspecified amount for waste and trespass and a judgment declaring that IPC has no right to possess or use the lands or resources.

On May 1, 2006, IPC filed an Answer to plaintiffs' First Amended Complaint denying all liability to the plaintiffs and asserting certain affirmative defenses including collateral estoppel and res judicata, preemption, impossibility and impractibility, failure to join all real and necessary parties, and various defenses based on untimeliness. IPC intends to vigorously defend its position in this proceeding, but is unable to predict the outcome of this matter.

6. REGULATORY MATTERS:

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

		March 31,		December 31,
		2006		2005
Idaho PCA current year:
	Deferral (accrual) for the 2006-2007 rate year	$	(39,514)	$	3,684
Idaho PCA true-up awaiting recovery:
	Authorized May 2005		23,393		28,567
Oregon deferral:
	2001 costs		7,996		8,411
	2005 costs		2,736		2,880
	Total deferral (accrual)	$	(5,389)	$	43,542

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 12, 2006, IPC filed its 2006-2007 PCA with the IPUC with a proposed effective date of June 1, 2006. The application proposed to reduce the PCA component of customers' rates from the existing level, which is currently recovering $76.7 million above base rates, to a level that is $46.8 million below current base rates. If approved, this filing would reduce rates by approximately $123.5 million.

On April 13, 2006, IPC filed testimony requesting review of one component of the PCA referred to as the load growth adjustment rate, as agreed to in the stipulation of the parties settling the 2005 general rate case. The load growth adjustment rate provides a reduction to power supply expenses for PCA purposes when loads grow from levels included in IPC's base rates. IPC maintains that this reduction to expenses should be equal to the relative increase in revenues received as a result of load growth. The IPUC has not yet established its procedures for addressing this issue.

On June 1, 2005, IPC implemented the 2005-2006 PCA, which held the PCA component of customers' rates at the existing level recovering $71 million above base rates. By IPUC order, the PCA included $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. The PCA deferred recovery of approximately $28 million of power supply costs, or 4.75 percent, for one year to help mitigate the impacts of other rate increases. The $28 million was included in the 2006-2007 PCA filing, and IPC earned a two percent carrying charge on the balance.

Oregon: On April 28, 2006, IPC filed for an accounting order with the OPUC to defer net power supply costs for the period of May 1, 2006 through April 30, 2007 in anticipation of higher than "normal" power supply expenses. "Normal" power supply expenses were set at a negative number (meaning that under normal water conditions IPC should be able to sell enough surplus energy to pay for all fuel and purchased power expenses and still have revenue left over to offset other costs) in the 2004 Oregon general rate case, which IPC is contesting. The forecasted system net power supply expenses included in this deferral filing were $64 million, which is $65.9 million higher than the normalized power supply expenses established in the Oregon general rate case. IPC requested authorization to defer an estimated $3.3 million, the Oregon jurisdictional share of the $65.9 million. IPC also requested that it earn its Oregon authorized rate of return on the deferred balance and recover the amount through rates in future years, as approved by the OPUC.

On March 2, 2005, IPC filed for an accounting order with the OPUC to defer net power supply costs for the period of March 2, 2005 through February 28, 2006 in anticipation of continued low water conditions. The forecasted net power supply costs included in this filing were $169 million, of which $3 million related to the Oregon jurisdiction. IPC proposed 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. On July 1, 2005, IPC, the OPUC staff, and the Citizen's Utility Board entered into a stipulation requesting that the OPUC accept IPC's proposed methodology. 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. The OPUC issued Order 05-870 on July 28, 2005, approving the stipulation. On April 19, 2006, IPC filed a request for review and acknowledgement of its deferred net power supply costs for the period of March 2, 2005 through February 28, 2006. The deferral amount was quantified by IPC to be $2.7 million.

The timing of future recovery of Oregon power supply cost deferrals is subject to an Oregon statute that specifically limits rate amortizations of deferred costs to six percent per year. IPC is currently amortizing through rates power supply costs associated with the western energy situation of 2001. Full recovery of the 2001 deferral is not expected until 2009, at which time the rate amortization of the 2005 - 2006 deferral could begin. A 2006 - 2007 deferral would have to be amortized sequentially following the full recovery of the authorized 2005 - 2006 deferral.

Emission Allowances
In June 2005, IPC filed applications with the IPUC and OPUC requesting blanket authorization for the sale of excess SO₂emission allowances and an accounting order. The IPUC issued Order 29852 on August 22, 2005, authorizing the sale and interim accounting treatment. Pursuant to the Order, the IPUC staff was to conduct workshops and make a recommendation as to the appropriate ratemaking treatment. The parties held workshops and settlement discussions on November 7, 2005, November 23, 2005, February 7, 2006 and March 23, 2006. The OPUC issued Order 05-983 on September 13, 2005, stating that IPC did not need a blanket order to sell emission allowances and approved the interim accounting treatment.

As of April 1, 2006, IPC has sold 78,000 SO₂ emission allowances (out of a total of approximately 107,000 excess allowances) for approximately $81.6 million (before income taxes and expenses) on the open market. After subtracting transaction fees, the total amount of sales proceeds to be allocated to the Idaho jurisdiction is approximately $76.8 million ($46.8 million net of tax, assuming a tax rate of approximately 39 percent).

On April 7, 2006, IPC filed, on behalf of several parties, a stipulation with the IPUC which proposed a settlement of the Idaho ratemaking treatment of the sales proceeds. The stipulation, if approved by the IPUC, allows IPC to retain 10 percent, or approximately $4.7 million after tax, of the emission allowance net proceeds as a shareholder benefit. The remaining 90 percent is to be recorded as a customer benefit and included in the PCA.

The IPUC established a comment period (until April 24, 2006) for interested parties to comment on the stipulation. In the comments filed during the comment period, all of the commenters recommended that the IPUC accept the stipulation with the clarification that the customer benefit include the tax savings that will accrue when the credit is actually provided to customers through the PCA.

As a result, subject to approval by the IPUC, the remaining 90 percent of the sales proceeds ($69.1 million) plus a carrying charge will be recorded as a customer benefit and included as a line-item in the PCA true-up. The carrying charge will be calculated on $42.1 million, the net-of-tax amount allocable to Idaho jurisdiction customers. At the date of the order approving this stipulation, this customer benefit will be reflected in IPC's PCA as a credit to the PCA true-up balance for amortization in PCA rates during the June 1, 2007 through May 31, 2008 PCA rate year.

There is no current OPUC proceeding with respect to SO₂ emission allowances, and IPC cannot predict the outcome of any future OPUC ratemaking proceeding relating to this issue.

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 four reportable segments: utility operations, IFS, ITI and IDACOMM.

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. ITI is the parent company of IdaTech, a developer of fuel cell technology. IDACOMM provides telecommunications and commercial Internet services.

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

		Three months ended
		March 31, 2006				March 31, 2006
				Net income		Total
		Revenues		(loss)		Assets

Utility Operations		$	267,274	$	25,021	$	3,096,697
IFS			343		2,162		133,066
ITI			834		(1,983)		12,728
IDACOMM			4,467		308		25,068
Other			723		(32)		161,610
Eliminations			-		-		(66,318)
	Consolidated Total	$	273,641	$	25,476	$	3,362,851

		Three months ended
		March 31, 2005				December 31, 2005
				Net income		Total
		Revenues		(loss)		Assets

Utility Operations		$	190,868	$	21,509	$	3,074,691
IFS			335		2,495		139,306
ITI			1,075		(2,052)		12,968
IDACOMM			3,581		(164)		24,525
Other			323		1,278		184,038
Eliminations			-		-		(71,402)
	Consolidated Total	$	196,182	$	23,066	$	3,364,126

8. BENEFIT PLANS:

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

						Deferred					Postretirement
		Pension Plan				Compensation Plan					Benefits
		2006		2005		2006		2005			2006		2005
Service cost		$	3,619	$	3,282	$	368		$	292	$	376	$	389
Interest cost			5,585		5,281		582			538		862		991
Expected return on plan
	assets		(7,670)		(7,422)		-			-		(630)		(642)
Amortization of net
	obligation at transition		-		(32)		-			78		510		510
Amortization of prior
	service cost		166		193		61			57		(134)		(131)
Amortization of net loss			65		-		211			172		219		397

	Net periodic benefit cost	$	1,765	$	1,302	$	1,222		$	1,137	$	1,203	$	1,514

IDACORP and IPC have not contributed and do not expect to contribute to their pension plan in 2006.

9. STOCK-BASED COMPENSATION:

As of March 31, 2006, IDACORP has three share-based compensation plans. IDACORP's employee plans are the 2000 Long-Term Incentive and Compensation Plan (LTICP) and the 1994 Restricted Stock Plan (RSP). These plans are intended to align employee and shareholder objectives related to IDACORP's long-term growth. IDACORP also has one non-employee plan, the Director Stock Plan (DSP). The purpose of the DSP is to increase directors' stock ownership through stock-based compensation.

The LTICP for officers, key employees and directors permits the grant of nonqualified stock options, incentive stock options, stock appreciation rights, restricted stock, restricted stock units, performance units, performance shares and other awards. The RSP permits only the grant of restricted stock or performance-based restricted stock. At March 31, 2006, the maximum number of shares available under the LTICP and RSP were 1,484,113 and 80,131, respectively.

The compensation cost that has been charged against IDACORP's income for these plans was $0.4 million and $0.3 million in the first quarters of 2006 and 2005, respectively. The total income tax benefit recognized in the income statement for these plans was $0.2 million and $0.1 million, for the first quarters of 2006 and 2005, respectively. For all stock-based compensation awards, IDACORP allocates the portion related to IPC's employees to IPC. In both the first quarter of 2006 and 2005, IPC's allocated share of total compensation cost charged against income and total income tax benefit recognized were $0.2 million and $0.1 million, respectively. No equity compensation costs have been capitalized.

Stock awards: Restricted stock awards have vesting periods of up to four years. Restricted stock awards entitle the recipients to dividends and voting rights, and unvested shares are restricted to disposition and subject to forfeiture under certain circumstances. The fair value of restricted stock awards is measured based on the market price of the underlying common stock on the date of grant and charged to compensation expense over the vesting period based on the number of shares expected to vest.

Performance-based restricted stock awards have vesting periods of three years. Performance awards entitle the recipients to voting rights, and unvested shares are restricted to disposition, subject to forfeiture under certain circumstances, and subject to meeting specific performance conditions. Based on the attainment of the performance conditions, the ultimate award can range from zero to 150 percent of the target award. For awards granted prior to 2006, dividends were paid currently to recipients. Beginning with the 2006 awards, dividends will be accumulated and paid out only on shares that eventually vest.

The performance goals for the 2006 awards are independent of each other and equally weighted, and are based on two metrics, cumulative earnings per share (CEPS) and total shareholder return (TSR) relative to a peer group. The fair value of the CEPS portion is based on the market value at the date of grant, reduced by the loss in time-value of the estimated future dividend payments, using an expected quarterly dividend of $0.30. The fair value of the TSR portion is estimated using a statistical model that incorporates the probability of meeting performance targets based on historical returns relative to the peer group. Both performance goals are measured over the three-year vesting period and are charged to compensation expense over the vesting period based on the number of shares expected to vest.

A summary of the status of nonvested share awards as of March 31, 2006 and changes during the three months ended March 31, 2006, is presented below. IPC share amounts represent the portion of IDACORP amounts related to IPC employees:

	IDACORP			IPC
		Weighted-			Weighted-
		average			average
		Grant date			Grant date
	Shares	Fair value		Shares	Fair value
Nonvested shares at January 1, 2006	214,851	$	29.71	183,569	$	29.75
Shares granted	124,126		25.90	113,121		25.91
Shares forfeited	(50,180)		23.93	(35,628)		22.96
Shares vested	-		-	-		-
Nonvested shares at March 31, 2006	288,797	$	29.08	261,062	$	29.01

At March 31, 2006, IDACORP had $3.8 million of total unrecognized compensation cost related to nonvested share-based compensation that was expected to vest. IPC's share of this amount was $3.4 million. These costs are expected to be recognized over a weighted-average period of 2.6 years. IDACORP uses original issue and/or treasury shares for these awards.

Stock options: Stock option awards are granted with exercise prices equal to the market value of the stock on the date of grant. The options have a term of 10 years from the grant date and vest over a five-year period. Upon adoption of SFAS 123R on January 1, 2006, the fair value of each option is amortized into compensation expense using graded-vesting. Beginning in 2006, stock options are not a significant component of share-based compensation awards under the LTICP.

The fair values of all stock option awards have been estimated as of the date of the grant by applying a binomial option pricing model. The application of this model involves assumptions that are judgmental and sensitive in the determination of compensation expense. The key assumptions used in determining the fair value of options granted during the quarter ended March 31, 2006 were:

Dividend yield, based on current dividend and stock price on grant date	3.7%
Expected stock price volatility, based on IDACORP historical volatility	18 %
Risk-free interest rate based on U.S. Treasury composite rate	4.92%
Expected term based on the SEC "simplified" method	6.50 years

Stock option activity during the three months ended March 31, 2006 was as follows:

IDACORP
					Aggregate
		Weighted-	Weighted-		Average
		Number	Average		Remaining	Intrinsic
		of	Exercise		Contractual	Value
		Shares	Price		Term	(000s)
Outstanding at January 1, 2006		1,421,914	$	32.24
	Granted	9,905		31.86
	Exercised	-		-
	Forfeited	(18,194)		27.73
	Expired	(2,860)		39.20
Outstanding at March 31, 2006		1,410,765	$	32.28	6.48	$	4,294
Exercisable at March 31, 2006		918,653	$	33.90	5.86	$	2,232

IPC
					Aggregate
		Weighted-	Weighted-		Average
		Number	Average		Remaining	Intrinsic
		of	Exercise		Contractual	Value
		Shares	Price		Term	(000s)
Outstanding at January 1, 2006		1,094,137	$	32.03
	Granted	-		-
	Exercised	-		-
	Forfeited	-		-
	Expired	(2,600)		40.00
Outstanding at March 31, 2006		1,091,537	$	32.01	6.39	$	3,595
Exercisable at March 31, 2006		736,646	$	33.62	5.80	$	1,951

The following table presents information about options granted and vested during the three months ended March 31:

	IDACORP				IPC
	2006		2005		2006		2005
Weighted-average grant-date fair value	$	9.96	$	8.84	$	-	$	8.81
Fair value of shares vested (000's)	$	1,568	$	1,346	$	1,271	$	1,083

As of March 31, 2006, there was $1 million of total unrecognized compensation cost related to stock options. These costs are expected to be recognized over a weighted average period of one year. IDACORP uses original issue and/or treasury shares to satisfy exercised options.

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

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

We have reviewed the accompanying condensed consolidated balance sheet of IDACORP, Inc. and subsidiaries (the "Company") as of March 31, 2006, and the related condensed consolidated statements of income, comprehensive income, and cash flows for the three-month periods ended March 31, 2006 and 2005. 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 condensed 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, 2005, 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 6, 2006, we expressed an unqualified opinion on those consolidated financial statements. In our opinion, the information set forth in the accompanying condensed consolidated balance sheet as of December 31, 2005 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 8, 2006

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 condensed consolidated balance sheet and statement of capitalization of Idaho Power Company and subsidiary (the "Company") as of March 31, 2006, and the related condensed consolidated statements of income, comprehensive income, and cash flows for the three-month periods ended March 31, 2006 and 2005. 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, 2005, 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 6, 2006, we expressed an unqualified opinion on those consolidated financial statements. In our opinion, the information set forth in the accompanying condensed consolidated balance sheet and statement of capitalization as of December 31, 2005 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 8, 2006

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

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

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 subject to the provisions of the Public Utility Holding Company Act of 2005, which provides certain access to books and records to the Federal Energy Regulatory Commission (FERC) and state utility regulatory commissions and imposes certain record retention and reporting requirements on IDACORP. The Public Utility Holding Company Act of 1935 was repealed, effective February 8, 2006.

IPC is an electric utility with a service territory covering approximately 24,000 square miles in southern Idaho and eastern Oregon. IPC is regulated by the 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 subsidiaries include:

IDACORP Financial Services, Inc. (IFS) - holder of affordable housing and other real estate investments;
IdaTech, LLC (IdaTech) - developer of integrated fuel cell systems, over 95 percent-owned by IDACORP's wholly-owned subsidiary IDACORP Technologies, Inc. (ITI);
IDACOMM, Inc. (IDACOMM) - provider of telecommunications services and commercial Internet services;
Ida-West Energy Company (Ida-West) - operator of small hydroelectric generation projects that satisfy the requirements of the Public Utility Regulatory Policies Act of 1978 (PURPA); and
IDACORP Energy (IE) - marketer of electricity and natural gas, which wound down its operations in 2003.

This MD&A should be read in conjunction with the accompanying condensed consolidated financial statements. This discussion updates the MD&A included in the Annual Report on Form 10-K for the year ended December 31, 2005, and should be read in conjunction with that discussion.

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," "may result," "may 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 and regulatory audits, including those of the Federal Energy Regulatory Commission, the Idaho Public Utilities Commission, the Oregon Public Utility Commission, and the Internal Revenue Service 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;
Changes arising from the recently enacted Energy Policy Act of 2005;
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 and the recent dissolution of Grid West;
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;
Market conditions and 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.

EXECUTIVE OVERVIEW:

First Quarter 2006 Financial Results
IDACORP's earnings for the quarter were $25 million, a $2 million increase over the same period in 2005. Earnings per share were $0.60 in the first quarter of 2006 and $0.55 in the same period of 2005. IPC's improved performance was the key component in IDACORP's improvement. IPC's earnings increased from $22 million in 2005 to $25 million in 2006.

IPC's performance is attributable to much improved hydroelectric generating conditions. After six years of below normal water conditions, IPC's first quarter 2006 hydroelectric generation was above normal levels and more than double first quarter generation in 2005. Hydroelectric generation contributed 62 percent of the company's total system generation, as compared to 44 percent in 2005. IPC was able to sell surplus energy, which tripled off-system sales revenue and volumes, and significantly reduced net power supply costs. This resulted in a seven-cents-per-share benefit quarter-over-quarter. IPC's results also reflect the benefits of growth in general business customers, cooler temperatures and rate increases that went into effect in June 2005. These increases were offset by increased operating expenses associated with third party transmission of almost $2 million and a comparable amount of labor related expenses.

IDACORP's non-regulated subsidiaries, including the holding company, contributed two cents to earnings per share compared to four cents per share in the first quarter of 2005. In accordance with interim reporting requirements, the estimated annual effective income tax rate is used in determining income tax expense. The results from both periods reflect the beneficial effect of intra-period tax allocations recorded at the holding company.

Power Cost Adjustment filing
On April 12, 2006, IPC submitted its annual Power Cost Adjustment (PCA) filing to the IPUC which, if approved, will result in a $123.5 million annual reduction in rates of Idaho customers beginning June 1, 2006. The proposed reduction in rates comes as a direct benefit of the above-average snow pack in the mountains upstream of Brownlee Reservoir and lower-than-forecasted power supply costs in the 2005 - 2006 PCA year. In years when water is plentiful and IPC can fully utilize its extensive hydroelectric system, power production costs are lower and IPC can pass those benefits to its customers in the form of rate reductions. When water is in short supply as it was in the past six years, the higher costs of supplying power by other means also are shared with IPC's customers.

Proposed general rate case settlement
IPC filed a general rate case in October 2005, requesting the IPUC to approve an annual increase to its Idaho retail base rates of $44 million or 7.8 percent. Base rates primarily reflect IPC's cost of providing electrical service to its customers, including equipment, vehicles and infrastructure.

On February 27, 2006, IPC, the IPUC staff and representatives of customer groups filed a proposed stipulation with the IPUC that, if approved, would settle this case. The stipulation calls for an $18.1 million increase, or 3.2 percent, in IPC's annual electric rates effective June 1, 2006. On March 1, 2006, the IPUC staff and a group representing irrigation customers filed testimony in support of the stipulation. IPC filed supporting testimony on March 20, 2006. A public hearing and a technical hearing on the settlement were held on April 11, 2006. If the stipulation is approved by the IPUC, IPC's overall rate of return will increase from the 7.85 percent currently authorized to 8.1 percent. An order approving the settlement is pending.

Proposed SO₂ emission allowances settlement
As of April 1, 2006, IPC has sold 78,000 SO₂ emission allowances (out of a total of approximately 107,000 excess allowances) for approximately $81.6 million (before income taxes and expenses) on the open market. After subtracting transaction fees the total amount of sales proceeds to be allocated to the Idaho jurisdiction is approximately $76.8 million.

On April 7, 2006 IPC filed, on behalf of several parties, a stipulation with the IPUC which proposed a settlement of the Idaho ratemaking treatment of the sales proceeds. The stipulation, if approved by the IPUC, allows IPC to retain 10 percent, or approximately $4.7 million net of income taxes, of the Idaho jurisdiction proceeds as a shareholder benefit. The remaining 90 percent, ($69.1 million) plus a carrying charge will be recorded as a customer benefit and included as a line item in the PCA true up for amortization in PCA rates during the June 1, 2007 through May 31, 2008 PCA rate period. The carrying charge will be calculated on $42.1 million, the net-of-tax amount allocable to Idaho jurisdiction customers. The case is fully submitted to the IPUC and an order is pending.

Aquifer recharge proposed settlement
In March 2006the Idaho legislature considered House Bill No. 800 (House Bill 800), which would have repealed certain provisions of an Idaho law unanimously passed in 1994 containing protections for the public benefit of low-cost hydroelectric generation. IPC strongly opposed House Bill 800 because, if it had become law, IPC's hydroelectric generation could be reduced and IPC would have to rely on more expensive generation or purchased power to meet customers' needs. This would have resulted in higher costs to IPC's customers. On March 30, 2006, the Senate defeated House Bill 800 by a vote of 21 to 14.

On April 11, 2006, IPC and the State of Idaho entered into a stipulation agreement regarding two water right permits. The permits allow for limited aquifer recharge and are held by the Idaho Water Resource Board. The two water right permits were issued in the early 1980's, prior to the 1984 Swan Falls Agreement.

IPC entered into the Swan Falls Agreement with the Governor and Attorney General of Idaho in October 1984 to resolve litigation relating to IPC's water rights at the Swan Falls project. In the early 1980's, IPC filed an action identifying approximately 7,500 water licenses and permits that had the potential to adversely impact IPC's hydropower water rights at the Swan Falls project. The Swan Falls Agreement resolved that litigation. One provision of the Swan Falls Agreement provided that the action against the 7,500 water licenses and permits would be dismissed with prejudice and that IPC's hydropower water rights on the middle Snake River would be subordinate to those dismissed water rights.

In the stipulation agreement, IPC and the state recognized that the two water right permits referred to above were named in the action brought by IPC and were subject to the Swan Falls Agreement and that IPC's water rights are therefore subordinate to these water right permits.

IPC cannot determine the financial impact of the stipulation agreement on IPC and its customers until such time, if ever, that recharge programs under the two water permits are established, but IPC believes that the potential maximum impact in a median water year may be approximately $30 million.

CRITICAL ACCOUNTING POLICIES AND ESTIMATES:

IDACORP's and IPC's discussion and analysis of their financial condition and results of operations are based upon their condensed 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 estimates 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 reviewed by the Audit Committee of the Board of Directors. These policies are discussed in more detail in the Annual Report on Form 10-K for the year ended December 31, 2005, 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, 2006. In this analysis, the results for 2006 are compared to the same period in 2005.

The following table presents the earnings (losses) for IDACORP's segments as well as the holding company:

		2006		2005
IPC - Utility operations		$	25,021	$	21,509
IDACORP Financial Services			2,162		2,495
IDACOMM			308		(164)
ITI			(1,983)		(2,052)
IDACORP Energy			(201)		(293)
Ida-West Energy			333		70
Holding company			(164)		1,501
	Total Earnings	$	25,476	$	23,066

Average common shares outstanding			42,473	42,210
Earnings per share		$	0.60	$	0.55

Utility Operations

Operating environment:
IPC is one of the nation's few investor-owned utilities with a predominantly hydroelectric generating base. Because of its reliance on hydroelectric generation, IPC's generation operations can be significantly affected by weather conditions. The availability of hydroelectric power depends on the amount of snow pack in the mountains upstream of IPC's hydroelectric facilities, springtime snow pack run-off, rainfall and other weather and stream flow management considerations. During low water years, when stream flows into IPC's hydroelectric projects are reduced, IPC's hydroelectric generation is reduced. This results in less generation from IPC's resource portfolio (hydroelectric, coal-fired and gas-fired) available for off-system sales and, most likely, an increased use of purchased power to meet load requirements. Both of these situations - a reduction in profitable off-system sales and an increased use of more expensive purchased power - result in increased net power supply costs. During high water years, increased off-system sales and the decreased need for more expensive purchased power reduce net power supply costs.

On a frequent basis, an operations plan is developed to provide guidance for generation resource utilization and energy market activities (off-system sales and power purchases). The plan incorporates forecasts for generation unit availability, reservoir storage and stream flows, gas and coal prices, customer loads, energy market prices and other pertinent inputs. Consideration is given to when to use IPC's available resources to meet forecast loads and when to transact in the energy market. The allocation of hydroelectric generation between heavy-load and light-load hours or calendar periods is considered in development of the operating plan. This allocation is intended to utilize the flexibility of the hydroelectric system to shift generation to high value periods, while operating within the constraints imposed on the system. IPC's energy risk management policy, unit operating requirements and other obligations provide the framework for the plan.

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

	MWh
	Hydroelectric	Thermal	Total system	Purchased
	Generation	Generation	Generation	Power	Total
2006	2,828	1,723	4,551	917	5,468
2005	1,382	1,777	3,159	846	4,005

The streamflow forecast released on May 5, 2006 by the National Weather Service's Northwest River Forecast Center indicates that Brownlee inflow for April through July 2006 is expected to total 9.0 million acre-feet (maf), or 143 percent of average. Snow pack accumulation for the Snake River Basin was 112 percent of average on May 7, 2006. Storage in selected federal reservoirs upstream of Brownlee as of May 7, 2006 was 104 percent of average. With current and forecasted stream flow conditions, IPC expects to generate between 8.5 and 10.5 million MWh from its hydroelectric facilities, compared to 6.2 million MWh in 2005.

General business revenue: The following table presents IPC's general business revenues, MWh sales and average number of customers and Boise, Idaho weather conditions for the three months ended March 31:

			2006		2005
Revenue
	Residential		$	88,436	$	78,776
	Commercial			43,030		39,892
	Industrial			29,888		27,013
	Irrigation			829		689
		Total	$	162,183	$	146,370

MWh
	Residential			1,416		1,328
	Commercial			912		888
	Industrial			876		832
	Irrigation			13		12
		Total		3,217		3,060

Customers (average)
	Residential			383,008		368,109
	Commercial			58,281		56,476
	Industrial			132		126
	Irrigation			17,953		17,792
		Total		459,374		442,503

Heating degree-days				2,413		2,360
Precipitation				4.37"		1.77"

Rates: Higher rates in effect in 2006 increased general business revenue $8 million over the same quarter last year. The increased 2006 rates result primarily from base rate increases that took effect in June 2005. Approximately $6 million of the general business revenue increase represents collections of previously recorded revenues from an irrigation load reduction program and rate case tax settlement. This revenue is offset by a reduction to other revenues in the same amount.
Usage: Weather variations positively impacted sales by approximately $2 million for the quarter. Temperatures were slightly colder than the first quarter of 2005.
Customers: General business customer growth improved revenue $6 million for the quarter, 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,
	2006			2005

Revenue	$	104,241	$	32,212
MWh sold		1,944		645
Revenue per MWh	$	53.62	$	49.93

Improved streamflow conditions increased total system generation and electricity available for surplus sales. Higher market prices also contributed to higher off-system sales revenue.

Other revenues: The following table presents the components of other revenues for the three months ended March 31:

		Three months ended
		March 31,
		2006		2005
Transmission services and property rental		$	7,116	$	8,894
Rate case tax settlement			(2,955)		2,813
Irrigation lost revenues			(3,311)		-
Provision for rate refund			-		171
	Total	$	850	$	11,878

In the first quarter of 2005, IPC recognized approximately $3 million of revenues related to an IPUC order regarding the calculation of IPC's taxes for purposes of test year income tax expense in the 2003 Idaho general rate case. Beginning in June 2005, this is being recovered in rates (and presented in general business revenue), with a corresponding reduction to other revenues. The net effect on other revenues was a $3 million decrease in the first quarter of 2006.

Also, beginning in June 2005, IPC began collecting and recording in general business revenues amounts related to an irrigation load reduction program. There was an offsetting reduction to other revenues of approximately $3.3 million for the first quarter of 2006.

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

	Three months ended
	March 31,
	2006		2005

Purchases	$	55,925	$	44,078
MWh purchased		917		846
Cost per MWh purchased	$	60.99	$	52.08

Higher market prices were the primary cause of the increase in purchased power expense.

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,
	2006			2005

Fuel expense	$	26,969	$		25,096
Thermal MWh generated		1,723			1,777
Cost per MWh	$	15.66	$		14.12

Fuel expense increased due primarily to higher prices for coal and increased rail transportation costs. The increased cost of coal is due to higher market demand, and the increased rail transportation costs are primarily driven by increased diesel fuel costs including an adjustable fuel surcharge.

PCA: PCA expense represents the effect of IPC's PCA regulatory mechanism, which is discussed in more detail below in "REGULATORY MATTERS - Deferred (Accrued) Net Power Supply Costs."

In 2006, the significant increase in hydroelectric production reduced net power supply costs (fuel and purchased power less off-system sales) below the amounts in the annual PCA forecasts. This resulted in the accrual of an expense representing amounts that will be returned to customers in subsequent rate years. As the accrued expenses are being returned in rates, the deferred balances are amortized.
The following table presents the components of PCA expense for the three months ended March 31:

		Three months ended
		March 31,
		2006			2005

Current year power supply cost accrual (deferral)		$	40,878	$	(15,926)
Amortization of prior year authorized balances			2,589		11,509
	Total power cost adjustment	$	43,467	$	(4,417)

Other operating and maintenance expenses: O&M expenses increased $6 million compared to 2005. The primary causes of this increase were $2 million increases in both labor-related expenses and electricity transmission expenses. Total O&M expenses in 2006 are expected to be between $250 and $260 million.

Non-utility operations

IFS
IFS contributed $2.2 million in the first quarter of 2006, compared to $2.5 million in the first quarter of 2005. IFS' income is derived principally from the generation of federal income tax credits and accelerated tax depreciation benefits related to its investments in affordable housing and historic rehabilitation developments. IFS generated $4.5 million of tax credits in the first quarter of 2006 and expects to continue delivering tax benefits at a level commensurate with the ongoing needs of IDACORP.

ITI
ITI lost $2.0 million in the first quarter of 2006, compared to a loss of $2.1 million in the first quarter of 2005, as IdaTech, ITI's operating subsidiary, continues its fuel cell development efforts.

IDACOMM
IDACOMM earned $0.3 million in the first quarter of 2006, compared to a $0.2 million loss in the first quarter of 2005. In 2006 IDACOMM completed the sale of fibers from its Las Vegas, Nevada inventory of fibers.

INCOME TAXES:

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. IDACORP's effective rate for the three months ended March 31, 2006 was 20.0 percent, compared to 4.7 percent for the three months ended March 31, 2005. IPC's effective tax rate for the three months ended March 31, 2006 was 39.8 percent, compared to 36.7 percent for the three months ended March 31, 2005. The differences in estimated annual effective tax rates are primarily due to the increase in pre-tax earnings at IDACORP and IPC, the loss of the capitalized overhead tax deduction at IPC, timing and amount of regulatory flow-through tax adjustments at IPC and slightly lower tax credits from IFS.

Status of audit proceedings
As discussed in Note 2 to IDACORP's and IPC's Condensed Consolidated Financial Statements, the Internal Revenue Service (IRS) examination of tax years 2001-2003 is ongoing. However, the examination is not complete and management cannot predict which examined items may be adjusted by the IRS or the financial impact of such adjustments. All issues related to this examination could be resolved by the end of 2006, with the possible exception of IPC's capitalized overhead cost method.

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 and IPC's consolidated financial position, results of operations, or cash flows.

Capitalized overhead costs
As discussed in Note 2 to IDACORP's and IPC's Condensed Consolidated Financial Statements, the IRS examination of IPC's simplified service cost method is ongoing. IPC is actively involved in pursuing resolution of this matter and is working diligently with the IRS in the examination process. At this time, IPC cannot predict the earnings or cash flow impacts that the revenue ruling, temporary regulations, or additional action by the IRS in this matter may have on 2006 or prior tax years. However, a less favorable method could result in a one time charge to earnings and reduced cash flow that could be partially offset by carryover tax credits, accelerated tax depreciation, changes in tax regulations and state regulatory recovery.

IPC is currently evaluating alternatives for a new uniform capitalization method for 2005 and subsequent years and expects to change to a new method with the filing of IDACORP's 2005 federal income tax return in the third quarter of 2006. It is expected that the new method will be less favorable than the simplified service cost method.

LIQUIDITY AND CAPITAL RESOURCES:

Operating cash flows
IDACORP's and IPC's operating cash flows for the three months ended March 31, 2006 were $66 million for both companies.

IDACORP's and IPC's operating cash flows increased $23 million and $9 million, respectively, compared to 2005. At IPC, a $25 million net increase in cash received from sales and purchases of wholesale electricity was substantially offset by increased income taxes paid to IDACORP. The increase in IDACORP's operating cash flows was primarily the result of the net increase in IPC's wholesale electricity sales, offset by a $12 million increase in income taxes paid to taxing authorities.

In 2006, net cash provided by operating activities will continue to be driven by IPC, where general business revenues, sales of excess energy to wholesale customers, and costs to supply power to general business customers have the greatest impact on operating cash flows.

Working capital
The increase in customer receivables from December 31, 2005 is due to the increase in sales of surplus energy. Taxes accrued increased due to an increase in pre-tax earnings. Accounts payable decreased primarily because of a reduction in the amount owed for purchased power.

Contractual obligations
There have been no material changes in contractual obligations, outside of the ordinary course of business, since December 31, 2005.

Credit ratings
S&P: On March 27, 2006, S&P announced that it had revised its general corporate credit rating outlooks for IDACORP and IPC to negative from stable. All other S&P credit ratings for IDACORP and IPC were reaffirmed. S&P stated that the negative outlooks reflect the potential for weakened financial metrics as a result of several factors, including possible passage of the water diversion legislation and uncertainty regarding the federal and state tax treatment and allocation of previous refunds of about $75 million (see "INCOME TAXES - Capitalized overhead costs" above and Note 2 to IDACORP's and IPC's Condensed Consolidated Financial Statements for a full discussion of capitalized overhead costs). A less substantial concern was the uncertainty regarding the relicensing of the Hells Canyon Complex.

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

	S&P		Moody's		Fitch
	IPC	IDACORP	IPC	IDACORP	IPC	IDACORP
Corporate Credit Rating	BBB+	BBB+	Baa 1	Baa 2	None	None
Senior Secured Debt	A-	None	A3	None	A-	None
Senior Unsecured Debt	BBB	BBB	Baa 1	Baa 2	BBB+	BBB
	(prelim)	(prelim)
			Baa 1/
Short-Term Tax-Exempt Debt	BBB/A-2	None	VMIG-2	None	None	None
Commercial Paper	A-2	A-2	P-2	P-2	F-2	F-2
Credit Facility	None	None	Baa 1	Baa 2	None	None
Rating Outlook	Negative	Negative	Stable	Stable	Stable	Stable

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

Capital requirements
IDACORP's internal cash generation after dividends is expected to provide less than the full amount of total capital requirements for 2006 through 2008. 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 approximately 43 percent of 2006 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 approximately 43 percent of 2006 capital requirements is an increase from the 34 percent reported in IDACORP's and IPC's Annual Report on Form 10-K for the year ended December 31, 2005. This increase is primarily due to improved hydroelectric generating conditions and to the stipulation (subject to IPUC approval) that settles the ratemaking treatment of the proceeds from the sales of excess SO₂ emission allowances. If approved, that stipulation would defer to the 2007-2008 PCA year the allocation to Idaho customers of their $69.1 million share of the proceeds. In addition, IPC paid approximately $28 million in income taxes in the first quarter of 2006 on the $71 million received from the sale of excess SO₂ emission allowances in 2005. These income taxes reduced IDACORP's 2006 forecast for internally generated cash. Excluding the payment of these income taxes, IDACORP's internally generated cash after dividends would have provided approximately 50 percent of 2006 capital requirements. Emission allowances are discussed below in "REGULATORY MATTERS."

Utility construction program: Utility construction expenditures were $48 million for the three months ended March 31, 2006 compared to $39 million for the three months ended March 31, 2005. IPC's total construction expenditures are expected to be $720 million, excluding AFDC, from 2006 through 2008. Variations in the timing and amounts of capital expenditures will result from regulatory and environmental factors, load growth and other resource acquisition needs, including relicensing expenditures.

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

Subsidiary Alternatives
IDACORP is continuing to evaluate its strategic alternatives with respect to IdaTech and IDACOMM. Alternatives being considered include the possible sale or merger of each company. IDACORP expects to substantially complete this process by the end of 2006, but cannot currently predict the impact these actions may have on its consolidated financial position, earnings or cash flows.

Financing Programs
Credit facilities: IDACORP has a $150 million five-year credit agreement with various lenders (IDACORP Facility), which is used for general corporate purposes and commercial paper back-up and 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.

IPC has a $200 million five-year credit agreement with various lenders (IPC Facility), which is used for general corporate purposes and commercial paper back-up and will terminate on March 31, 2010. 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.

At March 31, 2006, no loans were outstanding under the IDACORP Facility or IPC Facility.

The IDACORP Facility and the IPC Facility both 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. At March 31, 2006, the leverage ratios for both IDACORP and IPC were 51 percent. At March 31, 2006, IDACORP was in compliance with all other covenants of the IDACORP Facility and IPC was in compliance with all other covenants of the IPC Facility.

See "LIQUIDITY AND CAPITAL RESOURCES - Financing Programs - Credit Facilities" in IDACORP's and IPC's Annual Report on Form 10-K for the year ended December 31, 2005 for a discussion of the terms of the IDACORP Facility and the IPC Facility.

Long-term financings: 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 and Stock Purchase Plan, rather than purchasing this stock on the open market. Beginning in August 2005, IDACORP also began using original issue common stock for its 401(k) plan. In the first quarter of 2006, IDACORP issued 75,249 shares.

LEGAL AND ENVIRONMENTAL ISSUES:

Legal and Other Proceedings
Reference is made to IDACORP's and IPC's Annual Report on Form 10-K for the year ended December 31, 2005, for a discussion of all material pending legal proceedings to which IDACORP and IPC and their subsidiaries were parties as of that time. The following discussion provides a summary of material developments that occurred in these proceedings during the period covered by this report and also provides a summary of any new material proceedings instituted during the period covered by this report.

Public Utility District No. 1 of Grays Harbor County, Washington: On December 16, 2005, the Honorable Robert H. Whaley, sitting by designation in the U.S. District Court for the Southern District of California, issued an Order Setting Status Conference wherein, rather than expressly ruling on IDACORP, IPC and IE's motion to dismiss Grays Harbor's amended complaint, he ruled that either Grays Harbor or the companies may, within 45 days of the date of the order, petition the FERC to weigh in on this case in light of "the extensive hearings . . . already undertaken by FERC in the Northwest refund proceeding" which may be relevant to this case. On January 27, 2006 Grays Harbor and the companies jointly filed a stipulation requesting that the court stay the action and extend the time in which the parties may petition the FERC by sixty days to March 31, 2006, stating that the parties felt the case was appropriate for mediation prior to further proceedings. On January 31, 2006, the court approved the stipulation staying the case until March 31, 2006 and setting a status conference for April 14, 2006. The parties selected a mediator, and the initial mediation session occurred on April 24, 2006. Following the April 24^th session, a second mediation session was scheduled for May 17, 2006. The parties have filed a joint stipulation extending the stay in the case through May 31, 2006 and rescheduling the status conference to a date after June 1, 2006. The Companies intend to vigorously defend their position in this proceeding and believe this matter will not have a material adverse effect on their consolidated financial positions, results of operations or cash flows.

Wah Chang: Following the October 18, 2005 consolidation of Wah Chang's appeal to the U.S. Court of Appeals for the Ninth Circuit of the dismissal of the case with Wah Chang v. Duke Energy Trading and Marketing and a revised briefing schedule, IDACORP, IPC and IE filed an answering brief on November 30, 2005 and Wah Chang filed its reply brief on January 6, 2006. The appeal has now 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 this matter will not have a material adverse effect on their consolidated financial positions, results of operations or cash flows.

City of Tacoma: The City of Tacoma's March 10, 2005 appeal to the U.S. Court of Appeals for the Ninth Circuit of the dismissal of the case by Judge Whaley 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 this matter will not have a material adverse effect on their consolidated financial positions, results of operations or cash flows.

Wholesale Electricity Antitrust Cases I & II: In these cross-actions against multiple defendants including IE and IPC which, following remand, are back in the California Superior Court in San Diego, the Court granted preliminary approval of the Reliant Settlement on January 6, 2006 and scheduled a hearing to consider final approval for April 28, 2006. The Court did not rule on the Reliant Settlement at the April 28, 2006 hearing and scheduled another hearing for July 14, 2006. If the Court does not grant final approval of the Reliant Settlement, Reliant may choose to reactivate its cross-complaint against the defendants including IE and IPC. Similarly, should the Court for any reason fail to approve the Reliant Settlement, IE and IPC may withdraw from the stipulation agreement dismissing the Reliant cross-complaint against IE and IPC with prejudice, by giving ten days' advance written notice. The Companies intend to vigorously defend their position in this proceeding and believe this matter will not have a material adverse effect on their consolidated financial positions, results of operations or cash flows.

Western Energy Proceedings at the FERC:

1. California Refund
In December 2005, IE and IPC reached a tentative agreement with the California Parties settling matters encompassed by the California Refund proceeding including IE's and IPC's cost filing and refund obligation. On January 20, 2006, IE and IPC and the California Parties jointly filed a request with the FERC asking that the FERC defer ruling on IE's and IPC's cost filing for thirty days so the parties could complete and file the settlement agreement with the FERC. On January 26, 2006, the FERC granted the requested deferral and required that the settlement be filed by February 17, 2006. On February 17, 2006, IE and IPC jointly filed with the California Parties (Pacific Gas & Electric Company, San Diego Gas & Electric Company, Southern California Edison, the California Public Utilities Commission, the California Electricity Oversight Board, the California Department of Water Resources and the California Attorney General) an Offer of Settlement with the FERC. Final comments on the settlement were filed by March 20, 2006. If the settlement is approved by the FERC, IE and IPC would assign $24.25 million of the rights to accounts receivable from the California Independent System Operator and California Power Exchange (CalPX) to the California Parties to pay into an escrow account for refunds to settling parties. Amounts from that escrow not used for settling parties and $1.5 million of the remaining IE and IPC receivables which are to be retained by the CalPX would be available to fund, at least partially, payment of the claims of any non-settling parties if they prevail in the remaining litigation of this matter. Approximately $10.25 million of the remaining IE and IPC receivables would be released to IE and IPC. Non-settling parties had until March 9, 2006 to elect to become an additional settling party. The majority of non-settling parties chose to opt out of the settlement. The FERC has not yet ruled on the Offer of Settlement. On March 27, 2006, the FERC issued an order rejecting the cost filing made by IPC and IE on September 14, 2005. On April 26, 2006, IPC and IE filed a request for rehearing of the FERC's order rejecting their cost filing. IE and IPC are unable to predict the outcome of these matters.

2. California Power Exchange Chargeback
Based upon the Offer of Settlement filed with the FERC on February 17, 2006 between the California Parties and IE and IPC and discussed above in "California Refund," the California Parties supported a motion filed by IE and IPC with the FERC seeking an Order Directing Return of Chargeback Amounts currently held by the California Power Exchange totaling $2.27 million. The FERC has not yet ruled on the Order Directing Return of Chargeback Amounts.

3. Market Manipulation
The Offer of Settlement filed with the FERC on February 17, 2006 between the California Parties and IE and IPC and discussed above in "California Refund," if approved, would terminate the investigations the FERC initiated without finding of wrongdoing by IE or IPC and would provide for the disposition of the "gaming" settlement.

4. Pacific Northwest Refund
On September 24, 2001, the FERC Administrative Law Judge submitted recommendations and findings to the FERC finding that prices in the Pacific Northwest during the December 25, 2000 through June 20, 2001 time period should be governed by the Mobile-Sierra standard of public interest rather than the just and reasonable standard, that the Pacific Northwest spot markets were competitive and that no refunds should be allowed. The FERC approved these recommendations on June 25, 2003 and multiple parties then appealed to the Ninth Circuit Court of Appeals. IE and IPC were parties in the FERC proceeding and are participating in the appeal. Briefing on the appeal was completed on May 25, 2005; however, no date has been set for oral argument. IE and IPC are unable to predict the outcome of these matters.

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 Condensed 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: Idaho has recently experienced six consecutive years 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 including declining Snake River base flows and declining levels in the Eastern Snake Plain Aquifer, a large underground aquifer that has been estimated to hold between 200 - 300 maf of water. These issues are of interest to IPC because of their potential impacts on generation at IPC's hydroelectric projects. 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 between Twin Falls and Lower Salmon Falls, which significantly contribute to base flow, declined at a rate of approximately 27 cfs per year over the same period. Low flow in the Snake River near Hagerman, Idaho continued to be observed during 2005, where several river gauges in that area recorded the lowest January - March Snake River flows since the early 1960's.

As a result of these declines in river flows, in 2003 several surface water users filed delivery calls with the Idaho Department of Water Resources (IDWR), demanding that it manage ground water withdrawals pursuant to the prior appropriation doctrine of "first in time is first in right" and curtail junior ground water rights that are depleting the aquifer and affecting flows to senior surface water rights. These delivery calls have resulted in several administrative actions before the IDWR and judicial actions before the State District Court in Ada and Gooding counties in Idaho challenging the constitutionality of state regulations used by the IDWR to conjunctively administer ground and surface water rights. One such action, filed in January 2005, involves seven surface water irrigation entities from above Milner Dam that submitted a delivery call letter to the Director of the IDWR 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. The Idaho Ground Water Appropriators, Inc., an Idaho non-profit corporation organized to promote and represent the interests of groundwater users, and the U.S. Bureau of Reclamation, the owner of American Falls Reservoir, petitioned to intervene in the delivery call action. Both petitions were granted.

Since IPC holds water rights that are dependent on the Snake River, spring flows and the overall condition of the Eastern Snake Plain Aquifer, IPC is participating 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.

One management option being explored is aquifer recharge, or using surface water supplies to increase ground water supplies by allowing the water to percolate into the aquifer in porous locations. Under certain circumstances aquifer recharge may impact senior water rights, including water rights held by IPC for hydropower purposes, and therefore conflict with state law. For that reason, IPC continues to participate in the processes that are considering solutions, such as aquifer recharge, to the conflict between ground and surface water interests in an effort to protect its existing hydroelectric generation water rights.
In February 2006, at the request of senior surface water interests, IPC entered into discussions with the State of Idaho, through the Office of the Governor, and senior surface water interests to explore opportunities for engaging in some limited aquifer recharge in 2006, provided any adverse impact to IPC's hydropower generation and its customers is adequately addressed. These discussions led to a proposal to implement a recharge pilot program in 2006. However, before that proposal could be finalized, on March 17, 2006, the House of Representatives of the State of Idaho passed House Bill No. 800 (House Bill 800), which proposed to repeal certain provisions of the Idaho Code that governed the use of natural water flow to recharge the Eastern Snake Plain Aquifer and would have subordinated certain hydropower water rights held by IPC to aquifer recharge. The introduction of House Bill 800 effectively concluded the discussions between IPC, senior surface water interests and the Governor's Office to implement a pilot recharge project.

IPC strongly opposed House Bill 800 because, if it had become law, IPC's hydroelectric generation could have been reduced and IPC would have to rely on more expensive generation or purchased power to meet customers' needs. This would have resulted in higher costs to IPC's customers. On March 30, 2006, the Senate defeated House Bill 800 by a vote of 21 to 14.

In the stipulation, IPC and the state recognized that the two water right permits referred to above were named in the action brought by IPC and were subject to the Swan Falls Agreement and that IPC's water rights are therefore subordinate to these water right permits.

IPC cannot determine the financial impact of the stipulation upon IPC and its customers until such time, if ever, that recharge programs under the two water permits are established, but IPC believes that the potential maximum impact in a median water year may be approximately $30 million.

Clean Air: The Environmental Protection Agency (EPA) issued 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 SO₂allowances to provide compliance for emissions attributable to IPC at all three of its jointly-owned coal-fired facilities and both of its natural gas-fired facilities.

The Clean Air Interstate Rule (CAIR) will cap emissions of SO₂ and nitrogen oxides in 28 eastern states and the District of Columbia. The CAIR does not impose any restrictions on emissions from any IPC facilities, and therefore, IPC does not foresee any adverse effects upon its operations.

The Clean Air Mercury Rule (CAMR) 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. Mercury emission allocations have been set at the state level, but the states have not allocated the allowances to individual utilities. States have until November 17, 2006 to submit to the EPA mercury plans establishing mercury emission standards and allowances for the power plants within their jurisdictions. IPC is actively monitoring developments on this issue and control equipment technology advances. It is anticipated that this rule may require additional emission controls and expenses at IPC's jointly-owned coal-fired facilities, although impacts on future plant operations, operating costs and generating capacity are not known at this time.

The possible enactment of national climate change legislation is something that IPC continues to monitor and evaluate. New climate change bills were introduced in the U.S. Senate and House of Representatives during March 2006. On April 4, 2006, the U.S. Senate Committee on Energy and Natural Resources sponsored a day-long hearing on the subject of global climate change. National climate change legislation, if enacted, could impose significant costs on IPC for compliance with restrictions on carbon emissions.

REGULATORY MATTERS:

General Rate Cases
Idaho: On October 28, 2005, IPC filed a general rate case with the IPUC based upon a 2005 test year. IPC asked for an annual increase to its Idaho retail base rates of $44 million, a 7.8 percent average increase. On February 27, 2006 IPC, the IPUC staff and representatives of customer groups filed a proposed stipulation with the IPUC that, if approved, would settle the general rate case. The stipulation calls for an $18.1 million increase, or 3.2 percent, in IPC's annual electric rates effective June 1, 2006, the day IPC also adjusts rates to reflect changes in the annual PCA.

The rate case filing was made with six months of actual operating expenses and six months of projected expenses. The actual increase in rates was lower than the requested amount due to three factors: (1) 2005 actual expenses were significantly less than those forecasted; (2) the overall rate of return agreed to was 8.1 percent compared to the 8.42 percent IPC requested (no specific return on equity was determined); and (3) net power supply costs were kept at levels currently existing in rates. If the stipulation is approved by the IPUC, IPC's overall rate of return will increase from the 7.85 percent currently authorized.

On March 1, 2006, the IPUC staff and the Irrigation Pumpers Association filed testimony in support of the stipulation. IPC filed supporting testimony on March 20, 2006. The IPUC conducted a technical hearing in Boise on April 11, 2006, and an order approving the settlement is pending.

Oregon: On September 21, 2004, IPC filed an application with the OPUC to increase general rates an average of 17.5 percent or approximately $4.4 million annually. A partial settlement resolved most issues in a manner consistent with the Idaho result. The most significant issue in this proceeding was the appropriate quantification of net power supply expenses for purposes of setting rates. The OPUC staff proposed that net power supply expenses for IPC be set at a negative number - meaning that IPC should be able to sell enough surplus energy to pay for all fuel and purchased power expenses and still have revenue left over to offset other costs. The bulk of IPC's rebuttal was directed at this position. A hearing was conducted on May 23, 2005. The OPUC issued its order in July 2005 authorizing an increase of $0.6 million in annual revenues for an average of 2.37 percent. The OPUC adopted the OPUC staff's argument for the negative net power supply costs, thus reducing IPC's initial rate request of $4.4 million by $2.4 million with this one adjustment.

On September 26, 2005, IPC filed a complaint with the Circuit Court of Marion County, Oregon asking the court to reverse the portion of the OPUC's general rate case order related to the determination of net power supply costs. On March 30, 2006 IPC filed its opening brief. Oral argument is scheduled for June 2006.

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

		March 31,		December 31,
		2006		2005
Idaho PCA current year:
	Deferral (accrual) for the 2006-2007 rate year	$	(39,514)	$	3,684
Idaho PCA true-up awaiting recovery:
	Authorized May 2005		23,393		28,567
Oregon deferral:
	2001 costs		7,996		8,411
	2005 costs		2,736		2,880
	Total deferral (accrual)	$	(5,389)	$	43,542

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 years' 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 12, 2006, IPC filed its 2006-2007 PCA with the IPUC with a proposed effective date of June 1, 2006. The application proposed to reduce the PCA component of customers' rates from the existing level, which is currently recovering $76.7 million above base rates to a level that is $46.8 million below current base rates. If approved, this filing would reduce rates by approximately $123.5 million.

The timing of future recovery of Oregon power supply cost deferrals is subject to an Oregon statute that specifically limits rate amortizations of deferred costs to six percent per year. IPC is currently amortizing through rates power supply costs associated with the western energy situation. Full recovery of the 2001 deferral is not expected until 2009, at which time the rate amortization of the 2005 - 2006 deferral could begin. A 2006 - 2007 deferral would have to be amortized sequentially following the full recovery of the authorized 2005 - 2006 deferral.

There is no current OPUC proceeding with respect to SO₂ emission allowances, and IPC cannot predict the outcome of any future OPUC ratemaking proceeding relating to this issue.

FERC Proceedings
On March 24, 2006, IPC submitted a revised Open Access Transmission Tariff (OATT) filing with the FERC requesting an increase in transmission rates. The purpose of the filing is to implement formula rates for the IPC OATT in order to more accurately reflect the costs that IPC incurs in providing transmission service. The filing requests an effective date of June 1, 2006, which the FERC could either grant or suspend and set the matter for hearing. In the filing IPC proposes to move from a fixed rate to a formula rate which allows for transmission rates to be updated each year based on FERC Form 1 data. The formula rate request includes a rate of return on equity of 11.25 percent. The proposed rates would produce an annual revenue increase of approximately $13 million based on 2004 test year data. Several parties have filed to intervene in the proceeding. IPC is unable to predict the outcome of this matter.

Integrated Resource Plan
Preparation has begun on the 2006 Integrated Resource Plan (IRP) with the initial meeting of the IRP Advisory Council held on October 20, 2005, and meetings continuing monthly. The planning period will change from a ten-year forecast to a 20-year forecast. The 2006 IRP is scheduled to be filed in June 2006; however it is likely that IPC will ask the IPUC and the OPUC for an extension of the filing deadline.

Peaking Resource: On January 9, 2006, IPC selected a Siemens-Westinghouse combustion turbine project in response to a request for proposal for construction of a natural gas-fired power plant, as identified in the 2004 IRP. The plant will be located at the Evander Andrews Power Complex near Mountain Home, Idaho and is planned to be online prior to the summer of 2008. The unit will provide approximately 166 MW of capacity to help meet summer load peaks and can provide greater capacity during cooler times of the year. On April 14, 2006, IPC filed an Application for a Certificate of Convenience and Necessity with the IPUC with a commitment estimate of $60 million. The application is based on a signed contract with Siemens-Westinghouse to construct the plant. The contract, valued at $50 million, is contingent on approval of the application by the IPUC. Related transmission interconnection and line upgrades will be constructed by IPC at an estimated cost of $23 million.

PURPA Wind Projects
As of March 2006, three wind projects, with a total nameplate capacity of 19.9 MW, are selling energy to IPC under approved PURPA agreements. An additional eleven wind projects, comprising 157.5 MW of wind generation, have approved PURPA agreements and are scheduled to come online during 2006 and 2007. The total nameplate capacity of PURPA wind projects with approved contracts is 177.4 MW. During April, IPC signed two more PURPA wind contracts adding an additional 29.4 MW. If approved by the IPUC, the total nameplate capacity of PURPA wind projects with approved contracts will increase to 206.8 MW.

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 is actively pursuing the relicensing of the Hells Canyon Complex and Swan Falls projects, a process that may continue for the next ten to fifteen years. Middle Snake project licenses were issued in 2004; however, as discussed below, a legal proceeding contesting the licenses is underway.

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. The current license for the Hells Canyon Complex expired at the end of July 2005. Until the new multi-year license is issued, IPC will operate the project under an annual license issued by the FERC. 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 2003.

On October 28, 2005, the FERC issued its Notice of Ready for Environmental Analysis (NREA), which requires the federal and state agencies, Native American tribes and other participants in the relicensing process to file preliminary comments, recommendations, terms, conditions and prescriptions under the FPA, the National Environmental Policy Act of 1969, as amended (NEPA), the Energy Act and other applicable federal laws. 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. Section 241 of the Energy Act modifies the existing hydroelectric relicensing process under the FPA and requires federal resource agencies with authority to impose mandatory conditions on licenses under Sections 4(e) or 18 of the FPA (conditions that the FERC must include in the license) to provide license applicants, and other parties to the licensing process, with evidentiary hearings on disputed issues of material fact related to proposed conditions. It also requires that such agencies accept more cost effective alternative conditions proposed by license applicants, or other parties, provided that the proposed alternative conditions will be no less protective of the resource or the reservation than the original condition recommended by the agency.

The federal and state agencies, Native American tribes and other interested parties filed their preliminary comments, recommendations, terms, conditions and prescriptions with the FERC on January 26, 2006. Consistent with the provisions of the FPA, IPC filed reply comments to these filings on April 11, 2006. The FERC will consider these filings as required by the FPA and NEPA and under its current schedule will issue a draft environmental impact statement in July 2006 and a final environmental impact statement in January 2007. The FERC will 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, including any mandatory conditions or prescriptions proposed under Sections 4(e) or 18 of the FPA.

The Energy Act, and the interim final rules issued on November 17, 2005, to implement the Act, require IPC, within 30 days of the agency's filing of their preliminary terms and conditions with the FERC, to file requests for evidentiary hearings on disputed issues of material fact relied upon by the federal agency for support of any term or condition and also file any proposed alternative conditions. On February 27, 2006, IPC filed requests for hearing on Section 4(e) conditions filed by the Department of the Interior through the Bureau of Land Management (BLM) and the Department of Agriculture through the U. S. Forest Service (USFS). These hearing requests related to travel and access management, law enforcement and emergency services, and recreation and land management conditions proposed by the BLM, and sandbar maintenance and restoration, wildlife habitat mitigation and management, noxious weed control, recreation resource management, and cultural resource management conditions filed by the USFS. On April 11, 2006, the BLM responded to the hearing requests. On April 14, 2006, the BLM referred IPC's requests for hearing to the Department of the Interior's Office of Hearings and Appeals. It is anticipated that evidentiary hearings will be held within 90 days of the referral. A pre-hearing conference on the BLM hearing requests occurred May 3, 2006. On April 13, 2006, the USFS filed a response to the hearing requests and is expected to provide for similar hearings within the Department of Agriculture. IPC is now preparing for the evidentiary proceedings contemplated by the Energy Act. IPC is also engaged in direct discussions with the agencies regarding possible settlements.

At March 31, 2006, $80 million of Hells Canyon Complex relicensing costs was 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 ratemaking process.

Swan Falls Project: The license for the Swan Falls hydroelectric project expires in 2010. On March 10, 2005, IPC initiated formal consultation with agencies, Native American tribes and the public regarding the relicensing of the Swan Falls project. IPC is in the process of compiling information and performing studies in preparation for filing an application for a new license with the FERC in 2008.

At March 31, 2006, $2 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 ratemaking process.

Middle Snake River Projects: IPC's 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. 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. IPC filed a motion to intervene in the appeal and the U.S. Fish and Wildlife Service filed a motion to be designated a respondent-intervenor. On June 15, 2005, the court granted these motions. By order dated October 4, 2005, the court extended the briefing schedule in the appeal. Pursuant to the extended schedule, American Rivers and Idaho Rivers United filed their briefs with the court on October 14, 2005 and the FERC filed its brief on December 16, 2005. IPC's and Fish and Wildlife's briefs were filed on January 27, 2006. American Rivers and Idaho Rivers United filed a reply brief and supplemental record on February 28, 2006. The U.S. Court of Appeals is now expected to set the matter for hearing.

Shoshone Falls Expansion
IPC has initiated the development of a Draft License Amendment Application (DLAA) to upgrade the Shoshone Falls hydroelectric project from 12 MW to 68 MW. The DLAA was distributed to involved parties on February 8, 2006 for a 90-day comment period. IPC plans to have the Final License Amendment Application ready for submittal to the FERC in July 2006.

Regional Transmission Organization
In December 1999, the FERC, in Order No. 2000, encouraged all companies with transmission assets to form regional transmission organizations (RTOs). By encouraging the formation of RTOs, the FERC sought to further facilitate the formation of efficient, competitive wholesale electricity markets. In response, several northwest utilities, including IPC, attempted formation of an RTO called RTO West, which eventually evolved into Grid West, a transmission management entity that would not necessarily become an RTO. In July 2005, the FERC acknowledged that Grid West would not need to satisfy their RTO requirements. The FERC did, however, acknowledge that Grid West governance was sufficiently independent to satisfy the independence requirements of an RTO, should Grid West decide to change its status in the future.

By September 2005, the Grid West technical design was complete and utilities began the process to commit the necessary funding to transfer corporate control to a new independent governing board and provide for continued development. Subsequently, two major funding entities, the Bonneville Power Administration and the British Columbia Transmission Corporation, declared they were unable to commit to the developmental funding. Grid West then developed a plan to accelerate implementation by limiting its scope to providing a few near-term services at potentially much lower cost than the original proposal. In March 2006, additional utilities withdrew support and it became apparent that Grid West would not succeed even with a very limited scope. On April 11, 2006 the Grid West board voted to prepare to dissolve the corporation.

IPC has spent funds supporting the development of Grid West. Funding of this effort has taken two forms. First, funds have been loaned to Grid West for the purpose of meeting its developmental expenses. The total accumulated loan through the first quarter of 2006 was approximately $1.1 million. IPC no longer expects this loan to be repaid by Grid West. Second, IPC has incurred incremental internal costs from participating in the developmental effort, which are mostly related to incremental travel and legal consultation. Prior to 2005, IPC had accumulated these costs in a deferred expense account, which totalsapproximately $2.3 million. IPC no longer expects these deferred expenses to be recovered by repayment through a Grid West tariff. IPC's accumulation of Grid West development costs in a deferred expense account is consistent with a 2004 accounting order that IPC requested and received from the FERC.

In April, 2006, IPC began the first step in an effort to pursue recovery of the Grid West development costs through retail rates. IPC filed requests with both the IPUC and OPUC for accounting orders addressing the deferral of costs related to the development of Grid West. The filings request that the IPUC and OPUC confirm that it is proper for IPC to transfer the costs to a regulatory assets account for possible amortization and recovery in future rates and IPC plans to file additional requests to begin to amortize and collect the development costs through rates. If IPC is unsuccessful with either the IPUC or OPUC or with the FERC, some or all of the $3.4 million will be expensed.

OTHER MATTERS:

Adopted Accounting Pronouncements
Effective January 1, 2006, IDACORP and IPC adopted Statement of Financial Accounting Standards No. 123 (revised 2004), "Share-Based Payment," (SFAS 123R) using the modified prospective application method. Prior to adopting SFAS 123R, the companies accounted for stock-based employee compensation under the recognition and measurement principles of Accounting Principles Board Opinion 25, "Accounting for Stock Issued to Employees," and related interpretations.

From 2003 through 2005, total compensation expense recorded for these plans was less than $1 million annually. The Companies did not modify outstanding share options prior to the adoption of SFAS 123R, and the fair value estimation model for options did not differ significantly.

Since 2001, the Companies have granted a mix of performance restricted stock, time-vesting restricted stock and stock options. In 2006, the Companies granted cumulative earnings per share- and total shareholder return-based performance shares, and time-vesting restricted stock and granted only a minimal amount of stock options. The adoption of SFAS 123R did not have a material effect on the Companies' financial statements, and, based on current levels of awards, is not expected to have a material effect in the future.

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

IDACORP and IPC are exposed to 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, 2006.

Interest Rate Risk
IDACORP and IPC manage interest expense and short- and long-term liquidity through 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, 2006, IDACORP and IPC had $125 million and $66 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, 2006, interest expense for the year ending December 31, 2006 would increase and pre-tax earnings would decrease by approximately $1 million for both IDACORP and IPC.

Fixed Rate Debt: As of March 31, 2006, IDACORP and IPC had outstanding fixed rate debt of $918 million and $865 million, respectively. The fair market value of this debt was $903 million and $850 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, 2006 levels.

Commodity Price Risk
Utility: IPC's commodity price risk has not changed materially from that reported in the Annual Report on Form 10-K for the year ended December 31, 2005.

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, 2005.

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. IE currently has outstanding $10 million in margin deposits. IE expects this amount to be refunded no later than the termination of the Indemnity Agreement in 2009. 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's 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, 2005.

ITEM 4. CONTROLS AND PROCEDURES

Disclosure controls and procedures:

IDACORP:
The Chief Executive Officer and the 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, 2006, have concluded that IDACORP's disclosure controls and procedures are effective.

IPC:
The Chief Executive Officer and the 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, 2006, have concluded that IPC's disclosure controls and procedures are effective.

Changes in internal control over financial reporting:

There have been no changes in IDACORP's or IPC's internal control over financial reporting during the quarter ended March 31, 2006 that have materially affected, or are 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 Condensed Consolidated Financial Statements in this Quarterly Report on Form 10-Q.

ITEM 1A. RISK FACTORS

The Risk Factors included in IDACORP's and IPC's Annual Report on Form 10-K for the year ended December 31, 2005 have not changed materially.

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 1,263 shares of common stock, equal to $40,000, on February 1, 2006. The stock was issued without registration under the Securities Act of 1933 in reliance upon Section 4(2) of the Act.

Restrictions on Dividends:
A covenant under the IDACORP and IPC Credit Facilities 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. See "MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS - LIQUIDITY AND CAPITAL RESOURCES - Financing Programs - Credit Facilities." 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, 2006, the leverage ratios for both IDACORP and IPC were 51 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 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, Form S-4, filed on 3/16/98, 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, Post-Effective Amendment No. 2 to Form S-3, filed on 6/30/89, 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, Form S-3, filed on 7/7/93, 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, Form S-3, filed on 7/7/93, 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, filed on 1/26/05, 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, filed on 1/26/05, 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 33-56071-99, Post-Effective Amendment No. 1 to Form S-8, filed on 10/1/98, as Exhibit 3(d).

*3(d)	Articles of Incorporation of IDACORP, Inc. File number 333-64737, Amendment No. 1 to Form S-3, filed on 11/4/98, 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, Amendment No. 1 to Form S-3, filed on 11/4/98, 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 333-00139-99, Post-Effective Amendment No. 1 to Form S-3, filed on 9/22/98, 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, filed on 1/26/05, 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 Exhibit 7-a-3, Second, November 15, 1943
	File number 2-7237, as Exhibit 7-a-4, Third, February 1, 1947
	File number 2-7502, as Exhibit 7-a-5, Fourth, May 1, 1948
	File number 2-8398, as Exhibit 7-a-6, Fifth, November 1, 1949
	File number 2-8973, as Exhibit 7-a-7, Sixth, October 1, 1951
	File number 2-12941, as Exhibit 2-C-8, Seventh, January 1, 1957
	File number 2-13688, as Exhibit 4-J, Eighth, July 15, 1957
	File number 2-13689, as Exhibit 4-K, Ninth, November 15, 1957
	File number 2-14245, as Exhibit 4-L, Tenth, April 1, 1958
	File number 2-14366, as Exhibit 2-L, Eleventh, October 15, 1958
	File number 2-14935, as Exhibit 4-N, Twelfth, May 15, 1959
	File number 2-18976, as Exhibit 4-O, Thirteenth, November 15, 1960
	File number 2-18977, as Exhibit 4-Q, Fourteenth, November 1, 1961
	File number 2-22988, as Exhibit 4-B-16, Fifteenth, September 15, 1964
	File number 2-24578, as Exhibit 4-B-17, Sixteenth, April 1, 1966
	File number 2-25479, as Exhibit 4-B-18, Seventeenth, October 1, 1966
	File number 2-45260, as Exhibit 2(c), Eighteenth, September 1, 1972
	File number 2-49854, as Exhibit 2(c), Nineteenth, January 15, 1974
	File number 2-51722, as Exhibit 2(c)(i), Twentieth, August 1, 1974
	File number 2-51722, as Exhibit 2(c)(ii), Twenty-first, October 15, 1974
	File number 2-57374, as Exhibit 2(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, filed on 12/20/93, as Exhibit 4, Thirty-fourth, December 1, 1993
	File number 1-3198, Form 8-K, filed on 11/21/00, as Exhibit 4, Thirty-fifth, November 1, 2000
	File number 1-3198, Form 8-K, filed on 10/1/01, as Exhibit 4, Thirty-sixth, October 1, 2001
	File number 1-3198, Form 8-K, filed on 4/16/03, as Exhibit 4, Thirty-seventh, April 1, 2003
	File number 1-3198, Form 10-Q for the quarter ended 6/30/03, filed on 8/7/03, as Exhibit 4(a)(iii), Thirty-eighth, May 15, 2003
	File number 1-3198, Form 10-Q for the quarter ended 9/30/03, filed on 11/6/03, as Exhibit 4(a)(iii), Thirty-ninth, October 1, 2003
	File number 1-3198, Form 8-K filed 5/10/05, as Exhibit 4, Fortieth, May 1, 2005.

*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, filed on 8/4/00, as Exhibit 4(b).

*4(c)(i)	Agreement of IPC to furnish certain debt instruments. File number 33-65720, Form S-3, filed on 7/7/93, 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, filed on 11/6/03, 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. Post-Effective Amendment No. 2 to Form S-3, File number 33-00440, filed on 6/30/89, 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, filed on 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, filed on 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, filed on 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, Form S-3, filed on 8/16/01, 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, filed on 8/4/00, 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, Form S-7, filed on 6/30/78, 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, Form S-7, filed on 6/30/78, as Exhibit 5(s).

*10(e)(ii)	Amendment, dated September 30, 1977, relating to agreement filed as Exhibit 10(e). File number 2-62034, Form S-7, filed on 6/30/78, as Exhibit 5(t).

*10(e)(iii)	Amendment, dated October 31, 1977, relating to agreement filed as Exhibit 10(e). File number 2-62034, Form S-7, filed on 6/30/78, 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, Form S-7 filed on 6/30/78, as Exhibit 5(v).

*10(e)(v)	Amendment, dated February 15, 1978, relating to agreement filed as Exhibit 10(e). File number 2-62034, Form S-7, filed on 6/30/78, as Exhibit 5(w).

*10(e)(vi)	Amendment, dated September 1, 1979, relating to agreement filed as Exhibit 10(e). File number 2-68574, Form S-7, filed on 7/23/80, 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, Form S-7, filed on 7/23/80, 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, Form S-7 filed on 6/29/79, 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, filed on 5/6/04 as Exhibit 10(h)(i).

*10(h)(ii) 1	2005 IDACORP, Inc. Executive Incentive Plan. File number 1-14465, 1-3198, Form 8-K, filed on 1/26/05, 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, filed on 3/10/95, 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, filed on 11/4/04, 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, filed on 11/4/04, 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, filed on 3/19/99, 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, filed on 1/26/05, as Exhibit 10.9.

*10(h)(viii)1	Form of Change in Control Agreement between IDACORP, Inc. and all Officers of IDACORP and IPC. File number 1-14465, Form 10-Q for the quarter ended 9/30/99, filed on 11/5/99, as Exhibit 10(h).

*10(h)(ix) 1	IDACORP, Inc. 2000 Long-Term Incentive and Compensation Plan, as amended as of March 17, 2005. File number 1-14465, 1-3198, Form 10-Q for the quarter ended 3/31/05, filed on 5/5/05, as Exhibit 10(h)(ix).

*10(h)(x) 1	IDACORP, Inc. 2000 Long-Term Incentive and Compensation Plan - Form of Stock Option Award Agreement. File number 1-14465, 1-3198, Form 10-Q for the quarter ended 9/30/04, filed on 11/4/04, 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, filed on 1/26/05, 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, filed on 1/26/05, 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, filed on 8/5/04, 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, filed on 8/5/04, as Exhibit 10(h)(ix).

*10(h)(xv)1	IDACORP, Inc. and Idaho Power Company NEO 2005 Base Compensation Table. File number 1-14465, 1-3198, Form 8-K, filed on 1/26/05, as Exhibit 10.1.

*10(h)(xvi)1	2005 IDACORP, Inc. Executive Incentive Plan NEO Award Opportunity Chart. File number 1-14465, 1-3198, Form 8-K, filed on 1/26/05, as Exhibit 10.3.

*10(h)(xvii) 1	IDACORP, Inc. 2000 Long-Term Incentive and Compensation Plan - 2005 Restricted Stock Awards (time vesting) to NEOs Chart. File number 1-14465, 1-3198, Form 8-K, filed on 1/26/05, as Exhibit 10.6.

*10(h)(xviii) 1	IDACORP, Inc. 2000 Long-Term Incentive and Compensation Plan - 2005 Restricted Stock Awards (performance vesting) to NEOs Chart. File number 1-14465, 1-3198, Form 8-K, filed on 1/26/05, as Exhibit 10.7.

*10(h)(xix) 1	IDACORP, Inc. and IPC 2005 Compensation for Non-Employee Directors of the Board of Directors. File number 1-14465, 1-3198, Form 8-K, filed on 1/26/05, as Exhibit 10.8.

*10(h)(xx) 1	Jan B. Packwood 2005 Restricted Stock Award Agreement. File number 1-14465, 1-3198, Form 8-K, filed on 1/26/05, as Exhibit 10.10.

*10(h)(xxi)1	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, filed on 3/9/05, as Exhibit 10(h)(xxiv).

*10(h)(xxii)1	IDACORP, Inc. and IPC 2006 NEO Base Compensation Table. File Number 1-14465, 1-3198, Form 8-K, filed on 1/25/06, as Exhibit 10.1.

*10(h)(xxiii) 1	IDACORP, Inc. 2006 Revised Executive Incentive Plan. File number 1-14465, 1-3198, Form 8-K, filed on 2/9/06, as Exhibit 10.1.

*10(h)(xxiv)1	IDACORP, Inc. 2006 Revised Executive Incentive Plan NEO Award Opportunity Chart. File number 1-14465, 1-3198, Form 8-K, filed on 2/9/06, as Exhibit 10.2

*10(h)(xxv)1	IPC 1994 Restricted Stock Plan - Form of Restricted Stock Agreement (time-vesting). File number 1-14465, 1-3198, Form 8-K, filed on 2/9/06, as Exhibit 10.3.

*10(h)(xxvi)1	IPC 1994 Restricted Stock Plan - 2006 Restricted Stock Awards (time-vesting) to NEOs Chart. File number 1-14465, 1-3198, Form 8-K, filed on 2/9/06, as Exhibit 10.4.

*10(h)(xxvii)1	IDACORP, Inc. 2000 Long-Term Incentive and Compensation Plan, Performance Share Award Agreement (performance with two goals). File number 1-14465, 1-3198, Form 8-K, filed on 3/17/06, as Exhibit 10.1.

*10(h)(xxviii)1	IDACORP, Inc. 2000 Long-Term Incentive and Compensation Plan Performance Share Awards (performance with two goals) to NEOs Chart. File number 1-14465, 1-3198, Form 8-K, filed on 3/17/06, as Exhibit 10.2.

10(h)(xxix)1	Idaho Power Company Security Plan for Senior Management Employees II, a non-qualified, deferred compensation plan, effective January 1, 2005.

10(h)(xxx)1	First Amendment to the Idaho Power Company Security Plan for Senior Management Employees, effective December 31, 2004.

10(h)(xxxi)1	Idaho Power Company Executive Deferred Compensation Plan, effective November 15, 2000.

10(h)(xxxii)1	First Amendment to the Idaho Power Company Executive Deferred Compensation Plan, effective October 1, 2003.

10(h)(xxxiii)1	Second Amendment to the Idaho Power Company Executive Deferred Compensation Plan, effective January 1, 2005.

10(h)(xxxiv)1	Third Amendment to the Idaho Power Company Executive Deferred Compensation Plan, effective January 1, 2005.

*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, Form S-3, filed on 7/7/93, 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, Form S-3, filed on 7/7/93, 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, Form S-3, filed on 7/7/93, 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, Form S-3, filed on 7/7/93, 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, Form S-3, filed on 7/7/93, 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, filed on 8/7/03, 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. File number 1-14465, 1-3198, Form 10-Q for the quarter ended 3/31/05, filed on 5/5/05, as Exhibit 10(l).

*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. File number 1-14465, 1-3198, Form 10-Q for the quarter ended 3/31/05, filed on 5/5/05, as Exhibit 10(m).

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, filed on 3/9/05, 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 2006.

1 Management contract or compensatory plan or arrangement

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 9, 2006	By:	/s/ Jan B. Packwood
			Jan B. Packwood
			President and Chief Executive Officer

Date	May 9, 2006	By:	/s/ Darrel T. Anderson
			Darrel T. Anderson
			Senior Vice President - Administrative Services
			and Chief Financial Officer

IDAHO POWER COMPANY

(Registrant)

Date	May 9, 2006	By:	/s/ J. LaMont Keen
			J. LaMont Keen
			President and Chief Executive Officer

Date	May 9, 2006	By:	/s/ Darrel T. Anderson
			Darrel T. Anderson
			Senior Vice President - Administrative Services
			and Chief Financial Officer

EXHIBIT INDEX

Exhibit Number

10(h)(xxix)1		Idaho Power Company Security Plan for Senior Management Employees II, a non-
		qualified, deferred compensation plan, effective January 1, 2005.

10(h)(xxx)1		First Amendment to the Idaho Power Company Security Plan for Senior Management
		Employees, effective December 31, 2004.

10(h)(xxxi)1		Idaho Power Company Executive Deferred Compensation Plan, effective November 15,
		2000.

10(h)(xxxii)1		First Amendment to the Idaho Power Company Executive Deferred Compensation Plan,
		effective October 1, 2003.

10(h)(xxxiii)1		Second Amendment to the Idaho Power Company Executive Deferred Compensation Plan,
		effective January 1, 2005.

10(h)(xxxiv)1		Third Amendment to the Idaho Power Company Executive Deferred Compensation Plan,
		effective January 1, 2005.

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 2006.

Three Months Ended