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 June 30, 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 June 30, 2006:

IDACORP, Inc.:	42,805,106
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, Inc., 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	1-2
			Condensed Consolidated Balance Sheets	3-4
			Condensed Consolidated Statements of Cash Flows	5
			Condensed Consolidated Statements of Comprehensive Income	6
		Idaho Power Company:
			Condensed Consolidated Statements of Income	7-8
			Condensed Consolidated Balance Sheets	9-10
			Condensed Consolidated Statements of Capitalization	11
			Condensed Consolidated Statements of Cash Flows	12
			Condensed Consolidated Statements of Comprehensive Income	13
		Notes to Condensed Consolidated Financial Statements		14-29
		Reports of Independent Registered Public Accounting Firm		30-31

	Item 2. Management's Discussion and Analysis of Financial
		Condition and Results of Operations		32-54

	Item 3. Quantitative and Qualitative Disclosures About Market Risk			54-55

	Item 4. Controls and Procedures			55

Part II. Other Information:

	Item 1. Legal Proceedings			56

	Item 1A. Risk Factors			56

	Item 2. Unregistered Sales of Equity Securities and Use of Proceeds			56

	Item 4. Submission of Matters to a Vote of Security Holders			57

	Item 6. Exhibits			57-63

Signatures				64

*Exhibit Index				65

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 June 30,
				2006		2005
				(thousands of dollars except for
				per share amounts)
Operating Revenues:
	Electric utility:
		General business		$	159,210	$	150,583
		Off-system sales			75,598		38,872
		Other revenues			6,040		10,253
			Total electric utility revenues		240,848		199,708
	Other				1,787		1,582
		Total operating revenues			242,635		201,290
Operating Expenses:
	Electric utility:
		Purchased power			74,808		36,929
		Fuel expense			21,954		24,369
		Power cost adjustment			4,600		12,415
		Other operations and maintenance			69,840		65,717
		Gain on sale of emission allowance			(8,126)		-
		Depreciation			24,633		25,193
		Taxes other than income taxes			6,329		5,302
			Total electric utility expenses		194,038		169,925
	Other				3,046		3,229
			Total operating expenses		197,084		173,154
Operating Income (Loss):
	Electric utility				46,810		29,783
	Other				(1,259)		(1,647)
		Total operating income			45,551		28,136
Other Income					5,080		3,216
Losses of Unconsolidated Equity-method Investments					(2,208)		(951)
Other Expenses					2,655		1,193
Interest Expense:
	Interest on long-term debt				14,200		14,292
	Other interest expense				1,175		810
		Total interest expense			15,375		15,102
Income Before Income Taxes					30,393		14,106
Income Tax Expense					7,720		1,513
Income from Continuing Operations					22,673		12,593
Losses from Discontinued Operations (net of tax)					(2,817)		(3,142)
Net Income				$	19,856	$	9,451
Weighted Average Common Shares Outstanding - Basic (000's)					42,557		42,230
Earnings Per Share of Common Stock (basic):
	Income from Continuing Operations			$	0.53	$	0.30
	Losses from Discontinued Operations			$	(0.06)	$	(0.08)
	Earnings Per Share of Common Stock (basic)			$	0.47	$	0.22
Weighted Average Common Shares Outstanding - Diluted (000's)					42,702		42,292
Earnings Per Share of Common Stock (diluted):
	Income from Continuing Operations			$	0.53	$	0.30
	Losses from Discontinued Operations			$	(0.06)	$	(0.08)
	Earnings Per Share of Common Stock (diluted)			$	0.47	$	0.22
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 Statements of Income
(unaudited)

				Six Months Ended June 30,
				2006		2005
				(thousands of dollars except for
				per share amounts)
Operating Revenues:
	Electric utility:
		General business		$	321,393	$	296,953
		Off-system sales			179,839		71,085
		Other revenues			6,890		22,538
			Total electric utility revenues		508,122		390,576
	Other				2,853		2,240
		Total operating revenues			510,975		392,816
Operating Expenses:
	Electric utility:
		Purchased power			130,733		81,007
		Fuel expense			48,923		49,465
		Power cost adjustment			48,067		7,998
		Other operations and maintenance			131,513		120,816
		Gain on sale of emission allowance			(8,235)		-
		Depreciation			49,182		50,112
		Taxes other than income taxes			11,900		10,529
			Total electric utility operations		412,083		319,927
	Other				6,863		6,255
			Total operating expenses		418,946		326,182
Operating Income (Loss):
	Electric utility				96,039		70,649
	Other				(4,010)		(4,015)
		Total operating income			92,029		66,634
Other Income					9,749		7,368
Losses of Unconsolidated Equity-method Investments					(2,259)		(288)
Other Expenses					4,076		2,296
Interest Expense:
	Interest on long-term debt				28,284		28,366
	Other interest expense				2,204		1,282
		Total interest expenses			30,488		29,648
Income Before Income Taxes					64,955		41,770
Income Tax Expense					15,327		3,535
Income from Continuing Operations					49,628		38,235
Losses from Discontinued Operations (net of tax)					(4,296)		(5,718)
Net Income				$	45,332	$	32,517

Weighted Average Common Shares Outstanding - Basic (000's)					42,515		42,220
Earnings Per Share of Common Stock (basic):
	Income from Continuing Operations			$	1.17	$	0.91
	Losses from Discontinued Operations			$	(0.10)	$	(0.14)
	Earnings Per Share of Common Stock (basic)			$	1.07	$	0.77
Weighted Average Common Shares Outstanding - Diluted (000's)					42,642		42,289
Earnings Per Share of Common Stock (diluted):
	Income from Continuing Operations			$	1.16	$	0.91
	Losses from Discontinued Operations			$	(0.10)	$	(0.14)
	Earnings Per Share of Common Stock (diluted)			$	1.06	$	0.77
Dividends Paid Per Share of Common Stock				$	0.60	$	0.60

The accompanying notes are an integral part of these statements.

IDACORP, Inc.
Condensed Consolidated Balance Sheets
(unaudited)

			June 30,		December 31,
			2006		2005
Assets			(thousands of dollars)

Current Assets:
	Cash and cash equivalents		$	53,871	$	52,356
	Receivables:
		Customer		60,676		94,469
		Allowance for uncollectible accounts		(6,921)		(33,078)
		Employee notes		2,681		2,951
		Other		7,219		21,377
	Energy marketing assets			13,308		23,859
	Accrued unbilled revenues			37,291		38,905
	Materials and supplies (at average cost)			34,677		30,451
	Fuel stock (at average cost)			17,409		11,739
	Deferred income taxes			25,557		23,922
	Prepayments			14,026		17,876
	Regulatory assets			1,984		3,064
	Other			4,766		2,956
	Assets held for sale			5,085		6,673
		Total current assets		271,629		297,520

Investments				195,828		191,593

Property, Plant and Equipment:
	Utility plant in service			3,532,237		3,477,067
	Accumulated provision for depreciation			(1,401,453)		(1,364,640)
		Utility plant in service - net		2,130,784		2,112,427
	Construction work in progress			189,141		149,814
	Utility plant held for future use			2,810		2,906
	Other property, net of accumulated depreciation			28,948		29,294
		Property, plant and equipment - net		2,351,683		2,294,441

Other Assets:
	American Falls and Milner water rights			31,585		31,585
	Company-owned life insurance			35,048		35,401
	Energy marketing assets - long-term			11,251		22,189
	Regulatory assets			376,537		415,177
	Long-term receivables (net of allowance of $1,878)			3,832		4,015
	Employee notes - long-term			2,563		2,862
	Other			42,714		43,377
	Assets held for sale			27,066		25,966
		Total other assets		530,596		580,572

		Total Assets	$	3,349,736	$	3,364,126

The accompanying notes are an integral part of these statements.

IDACORP, Inc.
Condensed Consolidated Balance Sheets
(unaudited)

				June 30,		December 31,
				2006		2005
Liabilities and Shareholders' Equity				(thousands of dollars)

Current Liabilities:
	Current maturities of long-term debt			$	15,949	$	16,307
	Notes payable				45,200		60,100
	Accounts payable				71,730		80,324
	Energy marketing liabilities				13,937		24,093
	Taxes accrued				86,971		72,652
	Interest accrued				14,770		14,616
	Other				32,385		19,577
	Liabilities held for sale				3,921		5,916
		Total current liabilities			284,863		293,585

Other Liabilities:
	Deferred income taxes				483,018		519,563
	Energy marketing liabilities - long-term				11,251		22,189
	Regulatory liabilities				372,289		345,109
	Other				125,193		124,833
	Liabilities held for sale				7,648		10,051
		Total other liabilities			999,399		1,021,745

Long-Term Debt					1,016,133		1,023,545

Commitments and Contingencies (Note 5)

Shareholders' Equity:
	Common stock, no par value (shares authorized 120,000,000;
		42,868,718 and 42,656,393 shares issued, respectively)			599,059		598,706
	Retained earnings				457,078		437,284
	Accumulated other comprehensive income (loss)				(4,811)		(3,425)
	Treasury stock (63,612 and 24,063 shares at cost, respectively)				(1,985)		(998)
	Unearned compensation				-		(6,316)
		Total shareholders' equity			1,049,341		1,025,251

			Total	$	3,349,736	$	3,364,126

The accompanying notes are an integral part of these statements.

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

				Six Months Ended
				June 30,
				2006		2005
				(thousands of dollars)
Operating Activities:
	Net income			$	45,332	$	32,517
	Adjustments to reconcile net income to net cash provided by
		operating activities:
		Unrealized (gains) losses from energy marketing activities			(234)		359
		Depreciation and amortization			60,339		61,635
		Deferred income taxes and investment tax credits			(35,056)		(4,380)
		Changes in regulatory assets and liabilities			61,143		4,826
		Undistributed earnings of subsidiaries			(4,607)		(6,255)
		Provision for uncollectible accounts			(133)		(157)
		Gain on sales of assets			(7,547)		-
		Other non-cash adjustments to net income			(1,957)		13
		Change in:
			Accounts receivable and prepayments		26,095		(4,102)
			Accounts payable and other accrued liabilities		(10,470)		(21,985)
			Taxes accrued		14,317		6,161
			Other current assets		(8,416)		(14,203)
			Other current liabilities		10,003		9,229
		Other assets			(1,978)		(2,500)
		Other liabilities			(317)		4,839
			Net cash provided by operating activities		146,514		65,997
Investing Activities:
	Additions to property, plant and equipment				(102,465)		(90,434)
	Investments in affordable housing				-		(4,024)
	Sale of emission allowances				10,865		-
	Investments in unconsolidated affiliates				(11,520)		-
	Purchase of available-for-sale securities				(9,428)		(77,774)
	Sale of available-for-sale securities				10,607		110,638
	Purchase of held-to-maturity securities				(1,245)		(947)
	Maturity of held-to-maturity securities				981		1,553
	Other assets				857		(309)
		Net cash used in investing activities			(101,348)		(61,297)
Financing Activities:
	Issuance of long-term debt				-		4,992
	Retirement of long-term debt				(7,901)		(9,497)
	Dividends on common stock				(25,521)		(25,326)
	Change in short-term borrowings				(14,900)		12,530
	Issuance of common stock				4,816		1,474
	Other assets				(8)		(370)
	Other liabilities				(137)		-
		Net cash used in financing activities			(43,651)		(16,197)
Net increase (decrease) in cash and cash equivalents					1,515		(11,497)
Cash and cash equivalents at beginning of period					52,356		23,403
Cash and cash equivalents at end of period				$	53,871	$	11,906
Supplemental Disclosure of Cash Flow Information:
	Cash paid during the period for:
		Income taxes		$	34,623	$	710
		Interest (net of amount capitalized)		$	29,317	$	28,351
	Non-cash investing activities
		Additions to property, plant and equipment		$	9,481	$	4,562

The accompanying notes are an integral part of these statements.

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

				Three Months Ended
				June 30,
				2006		2005
				(thousands of dollars)

Net Income				$	19,856	$	9,451

Other Comprehensive Income (Loss):
	Unrealized gains (losses) on securities:
		Unrealized holding gains (losses) arising during the period,
			net of tax of ($523) and ($315)		(922)		(619)
		Reclassification adjustment for gains included
			in net income, net of tax of ($512) and ($159)		(798)		(247)
			Net unrealized gains (losses)		(1,720)		(866)

Total Comprehensive Income				$	18,136	$	8,585

				Six Months Ended
				June 30,
				2006		2005
				(thousands of dollars)

Net Income				$	45,332	$	32,517

Other Comprehensive Income (Loss):
	Unrealized gains (losses) on securities:
		Unrealized holding gains (losses) arising during the period,
			net of tax of ($65) and ($589)		(248)		(1,143)
		Reclassification adjustment for gains included
			in net income, net of tax of ($730) and ($393)		(1,138)		(611)
			Net unrealized gains (losses)		(1,386)		(1,754)

Total Comprehensive Income				$	43,946	$	30,763

The accompanying notes are an integral part of these statements.

Idaho Power Company
Condensed Consolidated Statements of Income
(unaudited)

			Three Months Ended
			June 30,
			2006				2005
			(thousands of dollars)
Operating Revenues:
	General business		$	159,210	$	150,583
	Off-system sales			75,598		38,872
	Other revenues			6,040		9,433
		Total operating revenues		240,848		198,888

Operating Expenses:
	Operation:
		Purchased power		74,808		36,929
		Fuel expense		21,954		24,369
		Power cost adjustment		4,600		12,415
		Other		48,200		45,413
		Gain on sale of emission allowance		(8,126)		-
	Maintenance			21,640		19,519
	Depreciation			24,633		25,193
	Taxes other than income taxes			6,329		5,302
		Total operating expenses		194,038		169,140

Income from Operations				46,810		29,748

Other Income (Expense):
	Allowance for equity funds used during construction			1,646		1,088
	Earnings of unconsolidated equity-method investment			491		1,288
	Other income			3,030		2,919
	Other expense			(2,580)		(2,053)
		Total other income		2,587		3,242

Interest Expense:
	Interest on long-term debt			13,531		13,379
	Other interest			1,358		1,029
	Allowance for borrowed funds used during construction			(941)		(656)
		Total interest expense		13,948		13,752

Income Before Income Taxes				35,449		19,238

Income Tax Expense				13,837		6,362

Net Income			$	21,612	$	12,876

The accompanying notes are an integral part of these statements.

Idaho Power Company
Condensed Consolidated Statements of Income
(unaudited)

			Six Months Ended
			June 30,
			2006				2005
			(thousands of dollars)
Operating Revenues:
	General business		$	321,393	$	296,953
	Off-system sales			179,839		71,085
	Other revenues			6,890		21,310
		Total operating revenues		508,122		389,348

Operating Expenses:
	Operation:
		Purchased power		130,733		81,007
		Fuel expense		48,923		49,465
		Power cost adjustment		48,067		7,998
		Other		96,079		86,632
		Gain on sale of emission allowances		(8,235)		-
	Maintenance			35,434		32,960
	Depreciation			49,182		50,112
	Taxes other than income taxes			11,900		10,529
		Total operating expenses		412,083		318,703

Income from Operations				96,039		70,645

Other Income (Expense):
	Allowance for equity funds used during construction			3,110		2,543
	Earnings of unconsolidated equity-method investment			3,804		5,189
	Other income			5,916		5,623
	Other expense			(4,257)		(3,729)
		Total other income		8,573		9,626

Interest Expense:
	Interest on long-term debt			26,931		26,555
	Other interest			2,464		1,889
	Allowance for borrowed funds used during construction			(1,786)		(1,392)
		Total interest expense		27,609		27,052

Income Before Income Taxes				77,003		53,219

Income Tax Expense				30,370		18,834

Net Income			$	46,633	$	34,385

The accompanying notes are an integral part of these statements.

Idaho Power Company
Condensed Consolidated Balance Sheets
(unaudited)

				June 30,		December 31,
				2006		2005
Assets				(thousands of dollars)

Electric Plant:
	In service (at original cost)			$	3,532,237	$	3,477,067
	Accumulated provision for depreciation				(1,401,453)		(1,364,640)
		In service - net			2,130,784		2,112,427
	Construction work in progress				189,141		149,814
	Held for future use				2,810		2,906

			Electric plant - net		2,322,735		2,265,147

Investments and Other Property					81,992		68,049

Current Assets:
	Cash and cash equivalents				40,101		49,335
	Receivables:
		Customer			53,623		49,830
		Allowance for uncollectible accounts			(721)		(833)
		Notes			3,084		3,273
		Employee notes			2,681		2,951
		Related parties			303		637
		Other			3,163		7,399
	Accrued unbilled revenues				37,291		38,905
	Materials and supplies (at average cost)				34,677		30,451
	Fuel stock (at average cost)				17,409		11,739
	Prepayments				13,677		17,532
	Regulatory assets				1,984		3,064

			Total current assets		207,272		214,283

Deferred Debits:
	American Falls and Milner water rights				31,585		31,585
	Company-owned life insurance				35,048		35,401
	Regulatory assets				376,537		415,177
	Employee notes				2,563		2,862
	Other				41,505		42,187

			Total deferred debits		487,238		527,212

	Total			$	3,099,237	$	3,074,691

The accompanying notes are an integral part of these statements.

Idaho Power Company
Condensed Consolidated Balance Sheets
(unaudited)

				June 30,		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			382,403		361,256
		Accumulated other comprehensive loss			(4,811)		(3,425)

			Total common stock equity		957,079		937,318

	Long-term debt				982,770		983,720

			Total capitalization		1,939,849		1,921,038

Current Liabilities:
	Long-term debt due within one year				1,064		-
	Accounts payable				70,575		79,433
	Notes and accounts payable to related parties				473		153
	Taxes accrued				82,622		72,994
	Interest accrued				14,261		14,105
	Deferred income taxes				1,355		3,064
	Other				32,485		19,182

			Total current liabilities		202,835		188,931

Deferred Credits:
	Deferred income taxes				471,024		507,880
	Regulatory liabilities				372,289		345,109
	Other				113,240		111,733

			Total deferred credits		956,553		964,722


Commitments and Contingencies (Note 5)

			Total	$	3,099,237	$	3,074,691

The accompanying notes are an integral part of these statements.

Idaho Power Company
Condensed Consolidated Statements of Capitalization
(unaudited)

				June 30,				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				382,403				361,256
	Accumulated other comprehensive loss				(4,811)				(3,425)
		Total common stock equity			957,079		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				(3,211)				(3,325)

			Total long-term debt		982,770		51		983,720	51

Total Capitalization				$	1,939,849		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)

				Six Months Ended
				June 30,
				2006		2005
				(thousands of dollars)
Operating Activities:
	Net income			$	46,633	$	34,385
	Adjustments to reconcile net income to net cash provided by
		operating activities:
		Depreciation and amortization			50,891		53,824
		Deferred income taxes and investment tax credits			(34,564)		(4,987)
		Changes in regulatory assets and liabilities			61,143		4,826
		Undistributed earnings of subsidiary			(3,804)		(6,254)
		Provision for uncollectible accounts			(133)		(157)
		Other non-cash adjustments to net income			(3,109)		-
		Gain on sale of assets			(7,800)		-
		Change in:
			Accounts receivables and prepayments		4,954		2,967
			Accounts payable		(9,624)		(21,946)
			Taxes accrued		9,628		9,309
			Other current assets		(8,402)		(13,466)
			Other current liabilities		10,837		9,909
		Other assets			(2,082)		(2,263)
		Other liabilities			1,412		2,428
			Net cash provided by operating activities		115,980		68,575

Investing Activities:
	Additions to utility plant				(101,149)		(86,213)
	Purchase of available-for-sale securities				(9,428)		(77,774)
	Sale of available-for-sale securities				10,607		110,638
	Sale of emission allowances				10,865		-
	Investments in unconsolidated affiliate				(11,520)		-
	Other assets				873		252
		Net cash used in investing activities			(99,752)		(53,097)

Financing Activities:
	Dividends on common stock				(25,487)		(25,326)
	Other assets				(8)		(369)
	Other liabilities				33		-
		Net cash used in financing activities			(25,462)		(25,695)

Net decrease in cash and cash equivalents					(9,234)		(10,217)
Cash and cash equivalents at beginning of period					49,335		17,679

Cash and cash equivalents at end of period				$	40,101	$	7,462

Supplemental Disclosure of Cash Flow Information:
	Cash paid during the period for:
		Income taxes paid to parent		$	56,717	$	15,366
		Interest (net of amount capitalized)		$	26,357	$	25,803
	Non-cash investing activities:
		Additions to utility plant		$	9,481	$	4,562

The accompanying notes are an integral part of these statements.

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

				Three Months Ended
				June 30,
				2006		2005
				(thousands of dollars)

Net Income				$	21,612	$	12,876

Other Comprehensive Income (Loss):
	Unrealized gains (losses) on securities:
		Unrealized holding gains (losses) arising during the period,			(922)		(619)
			net of tax of ($523) and ($315)
		Reclassification adjustment for gains included
			in net income, net of tax of ($512) and ($159)		(798)		(247)
			Net unrealized gains (losses)		(1,720)		(866)

Total Comprehensive Income				$	19,892	$	12,010

				Six Months Ended
				June 30,
				2006		2005
				(thousands of dollars)

Net Income				$	46,633	$	34,385

Other Comprehensive Income (Loss):
	Unrealized gains (losses) on securities:
		Unrealized holding gains (losses) arising during the period,			(248)		(1,143)
			net of tax of ($65) and ($589)
		Reclassification adjustment for gains included
			in net income, net of tax of ($730) and ($393)		(1,138)		(611)
			Net unrealized gains (losses)		(1,386)		(1,754)

Total Comprehensive Income				$	45,247	$	32,631

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.

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.

At June 30, 2006, IDACORP's other subsidiaries included:

IDACORP Financial Services, Inc. (IFS) - holder of affordable housing and other real estate investments;
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);
IDACORP Energy (IE) - a marketer of electricity and natural gas, which wound down its operations during 2003;
IdaTech, LLC (IdaTech) - developer of integrated fuel cell systems, over 99 percent owned by IDACORP's wholly-owned subsidiary IDACORP Technologies, Inc. (ITI); and
IDACOMM, Inc. (IDACOMM) - provider of telecommunications services and commercial Internet services.

On July 20, 2006, IDACORP completed the sale of all of the outstanding common stock of ITI to IdaTech UK Limited, a wholly-owned subsidiary of Investec Group Investments (UK) Limited.

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 $94 million at June 30, 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 June 30, 2006, and consolidated results of operations for the three and six months ended June 30, 2006 and 2005 and consolidated cash flows for the six months ended June 30, 2006 and 2005. These adjustments are of a normal and recurring nature. 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 and six months ended June 30, 2006.

IDACORP's and IPC's Condensed Consolidated Statements of Income for the three and six months ended June 30, 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 (in thousands of dollars, except for per share amounts).

			Three months		Six months
			ended		ended
			June 30, 2005		June 30, 2005
IDACORP:
Net income, as reported			$	9,451	$	32,517
Add: Stock-based employee compensation expense included in
	reported net income, net of related tax effects			147		322
Deduct: Total stock-based employee compensation expense determined
	under fair value based method for all awards, net of related tax effects			341		756
		Pro forma net income	$	9,257	$	32,083
EPS of common stock:
	Basic and diluted - as reported		$	0.22	$	0.77
	Basic and diluted - pro forma			0.22		0.76

IPC:
Net income, as reported			$	12,876	$	34,385
Add: Stock-based employee compensation expense included in
	reported net income, net of related tax effects			46		144
Deduct: Total stock-based employee compensation expense determined
	under fair value based method for all awards, net of related tax effects			208		509
		Pro forma net income	$	12,714	$	34,020

For purposes of these 2005 pro forma calculations, the estimated fair value of the options, restricted stock and performance shares is 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 forfeiture 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 following table presents the computation of IDACORP's basic and diluted earnings per share for the three and six months ended June 30, 2006 and 2005 (in thousands, except for per share amounts):

					Three months ended				Six months ended
					June 30,				June 30,
					2006		2005		2006		2005

Numerator:
	Income from continuing operations				$	22,673	$	12,593	$	49,628	$	38,235

Denominator:
	Weighted-average common shares
		outstanding - basic*				42,557		42,230		42,515		42,220
	Effect of dilutive securities:
		Options				90		48		83		54
		Restricted Stock				55		14		44		15
			Weighted-average common shares
				outstanding - diluted*		42,702		42,292		42,642		42,289

Basic earnings per share from continuing operations					$	0.53	$	0.30	$	1.17	$	0.91
Diluted earnings per share from continuing operations					$	0.53	$	0.30	$	1.16	$	0.91

*Weighted average shares outstanding excludes non-vested shares issued under stock compensation plans.

The diluted EPS computation excluded 653,200 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, 1,247,665 options were outstanding at June 30, 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.

New Accounting Pronouncements
FIN 48: In June 2006, the Financial Accounting Standards Board (FASB) issued FASB Interpretation No. 48, "Accounting for Uncertainty in Income Taxes - an interpretation of FASB Statement No. 109" (FIN 48), which clarifies the accounting for uncertainty in tax positions. FIN 48 requires that IDACORP and IPC recognize in their financial statements the impact of a tax position if that position will more likely than not be sustained upon examination, including resolution of any related appeals or litigation processes, based on the technical merits of the position. The provisions of FIN 48 are effective for fiscal years beginning after December 15, 2006, with the cumulative effect of the change in accounting principle recorded as an adjustment to opening retained earnings. IDACORP and IPC are currently evaluating the impact of adopting FIN 48 on their financial statements.

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 on continuing operations for the six months ended June 30, 2006, was 23.6 percent, compared to 8.5 percent for the six months ended June 30, 2005. IPC's effective tax rate for the six months ended June 30, 2006, was 39.4 percent, compared to 35.4 percent for the six months ended June 30, 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 simplified service cost method 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 June 30, 2006, the IRS had substantially completed its issue development and research for the 2001-2003 tax years, 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 the 2001-2003 tax years 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 six months ended June 30, 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 Plan and 12,767 shares were issued pursuant to the exercise of stock options under the same plan.
A total of 138,390 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 stock-based compensation be charged 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):

				June 30,		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					(3,211)		(3,325)
Debt related to investments in affordable housing					40,675		48,481
Other subsidiary debt					7,591		7,686
Less: Liabilities held for sale					(18)		(35)
	Total				1,032,082		1,039,852
Current maturities of long-term debt					(15,949)		(16,307)

			Total long-term debt	$	1,016,133	$	1,023,545

(a)		Humboldt County Pollution Control Revenue bonds are secured by first mortgage bonds, bringing the total first mortgage
		bonds outstanding at June 30, 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 June 30, 2006, IPC could issue under the mortgage approximately $452 million of additional first mortgage bonds based on retired first mortgage bonds and $645 million of additional first mortgage bonds based on unfunded property additions. As of June 30, 2006, unfunded property additions were approximately $1.1 billion. Property additions consist of electric or gas property, or property used in connection therewith. Property additions exclude securities, contracts or choses in action, merchandise and equipment for consumption or resale, materials and supplies, property used principally for production or gathering of natural gas and 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 all or substantially all of the assets of IPC.

At June 30, 2006, IFS had $41 million of debt related to investments in affordable housing with interest rates ranging from 3.65 percent to 8.38 percent, due between 2006 and 2010. The investments in affordable housing developments that collateralize this debt had a net book value of $68 million at June 30, 2006. IFS' $13 million Series 2003-1 tax credit note is non-recourse to both IFS and IDACORP. The $7 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 June 30, 2006, no loans were outstanding on IDACORP's credit facility and $45 million of commercial paper was outstanding.

At June 30, 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 June 30, 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 June 30, 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.

As part of the sale of its forward book of electricity trading contracts, IE had 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 was $20 million. During the second quarter this guarantee terminated and IE was refunded all outstanding margin deposits.

Regional Transmission Organization
Over the last several years, IPC has spent funds supporting the development of Grid West, a regional transmission organization. Through the second quarter of 2006, IPC had loaned Grid West $1.1 million and had accumulated $2.3 million of costs in a deferred expense account, anticipating future recovery through Grid West tariffs. IPC no longer expects reimbursement of the either amount through Grid West. IPC's accumulation of Grid West development costs in a deferred expense account is consistent with a 2004 accounting order that IPC 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. 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. The cases in both states are ongoing. 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.

LEGAL PROCEEDINGS

Reference is made to IDACORP's and IPC's Annual Report on Form 10-K for the year ended December 31, 2005, and Quarterly Report on Form 10-Q for the quarter ended March 31, 2006, for a discussion of all material pending legal proceedings to which IDACORP and IPC and their subsidiaries are parties. The following discussion provides a summary of material developments that occurred in those proceedings during the period covered by this report and of any new material proceedings instituted during the period covered by this report.

Proceedings Relating to the Western Power Markets
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 July 25, 2006, the case was dismissed with prejudice by the Honorable Robert H. Whaley, sitting by designation in the U.S. District Court for the Southern District of California, pursuant to an agreed resolution of the matter between Grays Harbor and IDACORP, IPC and IE. The settlement did not have a material adverse effect on IDACORP's consolidated financial position, results of operation 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 affirming the dismissal of the entire case. The dismissal of the case, with prejudice, became final on June 28, 2006, when the Port of Seattle elected not to file a certiorari petition to the U.S. Supreme Court.

Wah Chang
Following the October 18, 2005, consolidation of Wah Chang's appeal of the dismissal order to the U.S. Court of Appeals for the Ninth Circuit with an identical order in Wah Chang v. Duke Energy Trading and Marketing, IDACORP, IPC and IE filed an answering brief on November 30, 2005. Wah Chang filed its reply brief on January 6, 2006. Wah Chang's appeal to the U.S. Court of Appeals for the Ninth Circuit has now been fully briefed; however, no date has yet been set for oral argument. IDACORP, IPC and IE 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. IDACORP, IPC and IE 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 April 2002, several subsidiaries of Reliant Energy, Inc. (Reliant) and Duke Energy Corporation (Duke) filed cross-complaints against IE and IPC and numerous other participants in the California energy market. The cross-complaints sought indemnification for any liability that may arise from original complaints filed against Reliant and Duke with respect to charges of unlawful and unfair business practices in the California energy markets under California law. On November 9, 2005, both Duke and Reliant submitted to the Court stipulations with IE and IPC to conditionally dismiss, with prejudice, the cross-complaints, subject to reinstatement if proposed settlements between Duke and Reliant and the plaintiffs of the underlying actions were not approved by the Court. Neither IE nor IPC paid any amount to Duke or to Reliant to obtain these dismissals.

On December 14, 2005, the Court granted final approval of the Duke settlement with the plaintiffs. The Court's order granting final approval of the Duke settlement became final on March 14, 2006, as the Court's docket does not indicate that any appeal was filed. On January 6, 2006, the Court granted preliminary approval of the Reliant settlement with the plaintiffs in these cases. On March 30, 2006, oppositions and objections to the Reliant settlement were filed by certain parties under the Eggers case caption, including by the States of Montana and Idaho. Neither IPC nor IE is a party to the Eggers case, which seeks to recover damages on behalf of consumers in western states other than California. A hearing on final approval of the Reliant settlement was held on April 28, 2006. At the hearing, the Court ruled that the California class settlement would receive final approval contingent on a satisfactory showing that the notice to those class members was adequate. As for the Eggers case, the Court set a briefing schedule to provide evidence and oral argument regarding the State of Montana's treatment by its class representative and Montana's connection to the California energy market.

On May 30, 2006, the Court signed and approved the Judgment, Final Order, and Decree Granting Final Approval to the Reliant settlement. The Court also signed and approved the Order Granting Reliant's Motion for Good Faith Settlement Determination. The order approving the Reliant settlement became final on July 31, 2006. On July 14, 2006, the Court held a separate hearing to consider approval of the settlement of the Eggers action, and thereafter signed and approved the Judgment, Final Order and Decree Granting Final Approval to the Class Action Settlement in the Eggers case.

IE and IPC will continue to vigorously defend their position in this proceeding until all appeal periods have expired and believe this matter will not have a material adverse effect on their consolidated financial positions, results of operations or cash flows.

California Refund
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 at the FERC. 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. After consideration of comments, the FERC approved the settlement on May 22, 2006. Under the terms of the settlement, IE and IPC assigned $24.25 million of the rights to accounts receivable from the California Independent System Operator (CalISO) 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 that are to be retained by the CalPX are 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. Any excess funds remaining at the end of the case are to be returned to IDACORP. Approximately $10.25 million of the remaining IE and IPC receivables was paid to IE and IPC under the Settlement.

On June 21, 2006, the Port of Seattle, Washington filed a request for rehearing of the FERC order approving the Settlement. On July 10, 2006, IDACORP and the California Parties filed a response to Port of Seattle's request for rehearing. On July 21, 2006, the FERC issued a tolling order in response to the Port of Seattle's request for rehearing, giving the FERC additional time to respond to the request. While IDACORP believes that this Settlement resolves all issues it may have related to the California Refund proceedings, it is possible that additional issues that affect IDACORP may arise in the future.

For some time the Ninth Circuit Court of Appeals held in abeyance consolidated petitions for review (in excess of 100) of FERC orders related to the California Refund proceeding. On September 21, 2004, the Ninth Circuit convened case management proceedings on these petitions and on October 22, 2004, severed a subset of issues for briefing related to: (1) which parties are subject to the FERC's refund jurisdiction under section 201(f) of the Federal Power Act; (2) the temporal scope of refunds under section 206 of the Federal Power Act; and (3) which categories of transaction are subject to refunds. Oral argument was held on April 12-13, 2005. On September 6, 2005, the Ninth Circuit issued a decision on the jurisdictional issues concluding that the FERC lacked refund authority over wholesale electric energy sales made by governmental entities and non-public utilities. On August 2, 2006, the Ninth Circuit issued its decision on the appropriate temporal reach and the type of transactions subject to FERC refund orders and concluded, among other things, that all transactions at issue in the case that occurred within or as a result of the CalPX and the Cal ISO were the proper subject of refund proceedings; refused to expand the refund proceedings into the bilateral markets including transactions with the California Department of Water Resources; approved the refund effective date as October 2, 2000, but also required FERC to consider whether refunds, including possibly market-wide refunds, should be required for an earlier time due to claims that some market participants had violated governing tariff obligations (although the decision did not specify when that time would start, the California Parties generally had sought further refunds starting May 1, 2000); and effectively expanded the scope of the refund proceeding to transactions within the CalPX and CalISO markets outside the 24-hour spot market and energy exchange transactions.

IDACORP believes that these decisions should have no material effect on IDACORP under the terms of the IDACORP Settlement with the California Parties approved by the FERC on May 22, 2006.

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 CalPX totaling $2.27 million. In the May 22, 2006 Order approving the Settlement, the FERC granted the IE and IPC motion for return of chargeback funds held by the CalPX. On June 1, 2006, IE received approximately $2.5 million from the CalPX representing the return of $2.27 million in chargeback funds plus interest.

Market Manipulation
Pursuant to 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 requests for rehearing of the California Parties and other settling parties of the FERC's approval of an earlier settlement with the FERC staff regarding allegations of "gaming" are deemed to be withdrawn. On May 22, 2006, the FERC issued an order approving the February 17, 2006, Offer of Settlement. If the FERC denies the few remaining requests for rehearing filed by non-settling parties of the FERC's approval of the "gaming" case settlement, the effect would be to terminate the FERC investigations as to IPC and IE regarding bidding behavior, physical withholding of power and "gaming" without finding of wrongdoing.

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. The Settlement approved by the FERC on May 22, 2006, resolves all claims the California Parties have against IE and IPC in the Pacific Northwest Refund proceeding. The settlement with Grays Harbor resolves all claims Grays Harbor has against IE and IPC in this proceeding. IE and IPC are unable to predict the outcome as to all other parties in this proceeding.

Other Litigation

Shareholder Lawsuit
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 had until May 1, 2006, to file an amended complaint only as to the loss causation element. On May 1, 2006, the plaintiffs filed an amended complaint. The defendants filed a motion to dismiss the amended complaint on June 16, 2006. The briefing schedule requires plaintiffs' response to defendants' motion to dismiss to be filed on or before August 14, 2006, and the defendants' response on or before August 28, 2006. IDACORP and the other defendants intend to defend themselves vigorously against the allegations. IDACORP cannot, however, predict the outcome of these matters.

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 impracticability, failure to join all real and necessary parties, and various defenses based on untimeliness. On June 19, 2006, IPC filed a motion to dismiss plaintiffs' First Amended Complaint, asserting, among other things, that the Court lacks subject matter jurisdiction and that plaintiffs failed to join an indispensable party (namely, the United States government). Plaintiffs must respond to the motion by August 18, 2006. IPC may then file a reply memorandum by September 29, 2006. IPC intends to vigorously defend its position in this proceeding, but is unable to predict the outcome of this matter.

6. REGULATORY MATTERS:

General Rate Cases
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 was held in June 2006. The parties are currently preparing briefs on the subject of market prices.

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

		June 30,		December 31,
		2006		2005
Idaho PCA current year:
	Deferral (accrual) for the 2006-2007 rate year	$	-	$	3,684
	Deferral (accrual) for the 2007-2008 rate year *		(47,064)		-
Idaho PCA true-up awaiting recovery (refund):
	Authorized May 2005		-		28,567
	Authorized May 2006		(19,265)		-
Oregon deferral:
	2001 costs		7,637		8,411
	2005 costs		2,790		2,880
	Total deferral (accrual)	$	(55,902)	$	43,542
* includes a $42.1 million credit for excess SO₂ emission allowance sales allocated to customers

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 May 25, 2006, the IPUC approved IPC's 2006-2007 PCA filing with an effective date of June 1, 2006. The filing reduced the PCA component of customers' rates from the existing level, which was recovering $76.7 million above then-existing base rates, to a level that is $46.8 million below those base rates, a decrease of 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. Other parties to the proceeding are scheduled to file testimony by September 15, 2006. A hearing is scheduled for October 30, 2006. The dollar impact of load growth adjustment rates is significant and increasing, based on continuing growth within IPC's territory. Any increase in the load growth adjustment rate as a result of this proceeding would magnify the impact.

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 2003 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. A settlement conference is scheduled for August 17, 2006.

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. On June 14, 2006, a settlement conference was held; however, settlement is pending further staff review.

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. 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 June 30, 2006, IPC has sold 78,000 SO₂ emission 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). Through allowance vintage year 2006, IPC has approximately 32,000 excess allowances remaining.

Pursuant to the IPUC order, the IPUC staff held several workshops and settlement discussions. On May 12, 2006, the IPUC approved a stipulation filed in April 2006 by IPC on behalf of several parties. The stipulation allows IPC to retain ten percent, or approximately $4.7 million after tax, of the emission allowance net proceeds as a shareholder benefit. 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. This customer benefit is included in IPC's PCA calculations as a credit to the PCA true-up balance and will be reflected 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:

IDACORP has identified two reportable segments: utility operations and IFS. ITI and IDACOMM, which had previously been identified as reportable segments, are now reported as discontinued operations (see Note 10).

The utility operations segment's primary sources of revenue are the regulated operations of IPC. IPC's regulated operations include the generation, transmission, distribution, purchase and sale of electricity. This segment also includes income from Bridger Coal Company, an unconsolidated joint venture also subject to regulation. The IFS segment represents that subsidiary's investments in affordable housing developments and historic rehabilitation projects. Operating segments not included above are below the quantitative thresholds for reportable segments and are included in the "All Other" category. This category is comprised of Ida-West's joint venture investments in small hydroelectric generation projects, the remaining activities of energy marketer IE, which wound down its operations in 2003, and IDACORP's holding company expenses.

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

		Utility					All				Consolidated
		Operations		IFS			Other		Eliminations1		Total
Three months ended June 30, 2006:
	Revenues	$	240,848		$	357	$	1,430	$	-	$	242,635
	Income (loss) from continuing operations		21,612			2,069		(1,008)		-		22,673

Three months ended June 30, 2005:
	Revenues	$	199,708		$	354	$	1,228	$	-	$	201,290
	Income (loss) from continuing operations		12,876			2,594		(2,877)		-		12,593

Total assets at June 30, 2006			3,099,237		$	135,147	$	176,959	$	(61,607)	$	3,349,736

Six months ended June 30, 2006:
	Revenues	$	508,122		$	699	$	2,154	$	-	$	510,975
	Income (loss) from continuing operations		46,633			4,231		(1,236)		-		49,628

Six months ended June 30, 2005:
	Revenues	$	390,576		$	689	$	1,551	$	-	$	392,816
	Income (loss) from continuing operations		34,385			5,089		(1,239)		-		38,235

Total assets at December 31, 2005		$	3,074,691		$	139,306	$	188,891	$	(38,762)	$	3,364,126

1Includes assets of ITI and IDACOMM which are presented as assets held for sale.

8. BENEFIT PLANS:

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

						Deferred				Postretirement
		Pension Plan				Compensation Plan				Benefits
		2006		2005		2006		2005		2006		2005
Service cost		$	3,619	$	3,282	$	368	$	293	$	376	$	338
Interest cost			5,585		5,282		582		537		862		774
Expected return on plan assets			(7,670)		(7,422)		-		-		(630)		(656)
Amortization of net
	obligation at transition		-		(31)		-		77		510		510
Amortization of prior service cost			166		192		61		57		(134)		(148)
Amortization of net loss			65		-		211		173		219		(3)
	Net periodic benefit cost	$	1,765	$	1,303	$	1,222	$	1,137	$	1,203	$	815

The following table shows the components of net periodic benefit costs for the six months ended June 30 (in thousands of dollars):

						Deferred				Postretirement
		Pension Plan				Compensation Plan				Benefits
		2006		2005		2006		2005		2006		2005
Service cost		$	7,238	$	6,564	$	736	$	585	$	752	$	727
Interest cost			11,170		10,563		1,164		1,075		1,724		1,765
Expected return on plan assets			(15,340)		(14,844)		-		-		(1,260)		(1,298)
Amortization of net
	obligation at transition		-		(63)		-		155		1,020		1,020
Amortization of prior service cost			332		385		122		114		(268)		(279)
Amortization of net loss			130		-		422		345		438		394
	Net periodic benefit cost	$	3,530	$	2,605	$	2,444	$	2,274	$	2,406	$	2,329

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

9. STOCK-BASED COMPENSATION:

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 June 30, 2006, the maximum number of shares available under the LTICP and RSP were 1,674,863 and 97,267, respectively. The following table shows the compensation cost recognized in income and the tax benefits resulting from these plans, as well as the amounts allocated to IPC for those costs associated with IPC's employees (in thousands of dollars):

	IDACORP						IPC
	Six months ended						Six months ended
	June 30,						June 30,
	2006			2005			2006		2005
Compensation cost	$	841	$		529	$		477	$	237
Income tax benefit	$	329	$		207	$		186	$	93

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 June 30, 2006, and changes during the six months ended June 30, 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	(107,733)		26.18	(90,386)		26.12
Shares vested	(18,842)		30.38	(18,842)		30.38
Nonvested shares at June 30, 2006	212,402	$	29.21	187,462	$	29.12

At June 30, 2006, IDACORP had $2.5 million of total unrecognized compensation cost related to nonvested share-based compensation that was expected to vest. IPC's share of this amount was $1.9 million. These costs are expected to be recognized over a weighted-average period of 2.32 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 six months ended June 30, 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 six months ended June 30, 2006, was as follows:

					Weighted
			Weighted-		Average	Aggregate
		Number	Average		Remaining	Intrinsic
		of	Exercise		Contractual	Value
		Shares	Price		Term	(000s)
IDACORP
Outstanding at January 1, 2006		1,421,914	$	32.24
	Granted	9,905		31.86
	Exercised	(12,767)		24.35
	Forfeited	(159,840)		28.43
	Expired	(11,547)		30.18
Outstanding at June 30, 2006		1,247,665	$	32.82	6.00	$	4,498
Exercisable at June 30, 2006		902,807	$	34.15	4.42	$	2,626



IPC
Outstanding at January 1, 2006		1,094,137	$	32.03
	Granted	-		-
	Exercised	(12,767)		24.35
	Forfeited	(139,833)		28.50
	Expired	(2,800)		39.96
Outstanding at June 30, 2006		938,737	$	32.64	5.87	$	3,576
Exercisable at June 30, 2006		724,680	$	33.77	4.53	$	2,296

The following table presents information about options granted and exercised during the six months ended June 30 (in thousands of dollars, except for weighted-average amounts):

	IDACORP				IPC
	2006		2005		2006		2005
Weighted-average grant-date fair value	$	9.96	$	8.84	$	-	$	8.81
Fair value of options vested		1,785		1,562		1,275		1,087
Intrinsic value of options exercised		123		-		123		-
Cash received from exercise		311		-		311		-
Tax benefits realized from exercise		48		-		48		-

As of June 30, 2006, there was $0.8 million of total unrecognized compensation cost related to stock options. These costs are expected to be recognized over a weighted average period of 2.35 years. IDACORP uses original issue and/or treasury shares to satisfy exercised options.

10. DISCONTINUED OPERATIONS:

In the second quarter of 2006, IDACORP decided to seek buyers for its fuel cell technology subsidiary ITI and its telecommunications subsidiary IDACOMM. IDACORP had been reviewing strategic alternatives for ITI and IDACOMM in order to focus on its core utility business. The planned disposals of these businesses meets the criteria established for reporting them as assets held for sale as defined by SFAS 144. SFAS 144 requires that a long-lived asset classified as held for sale be measured at the lower of its carrying amount or fair value, less costs to sell, and requires the holder to cease depreciation and amortization. Based on an analysis of the fair value of each subsidiary, no adjustments to the carrying values were required.

On July 20, 2006, IDACORP completed the sale of all of the outstanding common stock of ITI to IdaTech UK Limited, a wholly-owned subsidiary of Investec Group Investments (UK) Limited. IDACORP expects to record a gain of $0.24 to $0.26 per diluted share from this transaction in the third quarter of 2006.

The operating results of these businesses have been separately classified and reported as discontinued operations on IDACORP's condensed consolidated statements of income. A summary of the components of losses from discontinued operations is as follows (in thousands of dollars):

	Three months ended				Six months ended
	June 30,				June 30,
	2006		2005		2006		2005

Revenues	$	3,403	$	4,181	$	8,704	$	8,837
Operating expenses		(7,466)		(8,472)		(15,447)		(16,730)
Other income (expense) and deductions		(25)		134		(67)		272
Pre-tax losses		(4,088)		(4,157)		(6,810)		(7,621)
Income tax benefit		1,271		1,015		2,514		1,903
Losses from discontinued operations	$	(2,817)	$	(3,142)	$	(4,296)	$	(5,718)

The results of operations for the three and six months ended June 30, 2006 do not include depreciation expense of approximately $0.2 million that would be recorded if the related assets were classified as held and used.

The assets and liabilities of IDACOMM and ITI have been classified as held for sale on IDACORP's balance sheets at June 30, 2006, and December 31, 2005. A summary of the components of assets and liabilities held for sale on IDACORP's Consolidated Balance Sheets is as follows (in thousands of dollars):

			June 30,		December 31,
			2006		2005
Assets
	Current assets		$	5,085	$	6,673
	Property and investments			19,994		19,848
	Other assets			7,072		6,118
		Total assets	$	32,151	$	32,639

Liabilities
	Current liabilities		$	3,921	$	5,916
	Other liabilities			7,630		10,016
	Long-term debt			18		35
		Total liabilities	$	11,569	$	15,967

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 June 30, 2006, and the related condensed consolidated statements of income and comprehensive income for the three-month and six-month periods ended June 30, 2006 and 2005, and the condensed consolidated statements of cash flows for the six-month periods ended June 30, 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 the 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
August 7, 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 June 30, 2006, and the related condensed consolidated statements of income and comprehensive income for the three-month and six-month periods ended June 30, 2006 and 2005, and the condensed consolidated statements of cash flows for the six-month periods ended June 30, 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
August 7, 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.

At June 30, 2006, IDACORP's other subsidiaries included:

IDACORP Financial Services, Inc. (IFS) - holder of affordable housing and other real estate investments;
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);
IDACORP Energy (IE) - marketer of electricity and natural gas, which wound down its operations in 2003;
IdaTech, LLC (IdaTech) - developer of integrated fuel cell systems, over 99 percent-owned by IDACORP's wholly-owned subsidiary IDACORP Technologies, Inc. (ITI); and
IDACOMM, Inc. (IDACOMM) - provider of telecommunications services and commercial Internet services.

In the second quarter of 2006, IDACORP management designated the operations of ITI and IDACOMM as assets held for sale, as defined by Statement of Financial Accounting Standards No. 144. IDACORP's consolidated financial statements reflect the reclassification of the results of these businesses as discontinued operations for all periods presented. Discontinued operations are discussed in more detail in Note 10 to IDACORP's and IPC's Condensed Consolidated Financial Statements and later in the MD&A. On July 20, 2006, IDACORP completed the sale of all of the outstanding common stock of ITI to IdaTech UK Limited, a wholly-owned subsidiary of Investec Group Investments (UK) Limited.

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 the Quarterly Report on Form 10-Q for the quarter ended March 31, 2006, and should be read in conjunction with the discussions in those reports.

FORWARD-LOOKING INFORMATION:

In connection with the safe harbor provisions of the Private Securities Litigation Reform Act of 1995 (Reform Act), IDACORP and IPC are hereby filing cautionary statements identifying important factors that could cause actual results to differ materially from those projected in forward-looking statements (as such term is defined in the Reform Act) made by or on behalf of IDACORP or IPC in this Quarterly Report on Form 10-Q, in presentations, in response to questions or otherwise. Any statements that express, or involve discussions as to expectations, beliefs, plans, objectives, assumptions or future events or performance (often, but not always, through the use of words or phrases such as "anticipates," "believes," "estimates," "expects," "intends," "plans," "predicts," "projects," "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 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 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:

Second Quarter 2006 Financial Results
IDACORP's earnings for the quarter were $20 million, a $10 million increase over the same period in 2005. Diluted earnings per share were $0.47 in the second quarter of 2006 and $0.22 in the same period of 2005. Improved results at IPC were the key driver of IDACORP's increase. IPC's earnings increased from $13 million in 2005 to $22 million in 2006.

IPC's performance is attributable to much improved hydroelectric generating conditions and increased sales. After six years of below normal water conditions, IPC's second quarter 2006 hydroelectric generation was above normal levels and 56 percent higher than second quarter generation in 2005. Hydroelectric generation contributed 71 percent of IPC's total system generation, as compared to 55 percent in 2005. This additional hydroelectric generation reduced net power supply costs, providing a $0.07 per diluted share benefit quarter-over-quarter. Irrigation energy sales increased by 64 percent quarter-over-quarter due to warmer and drier weather. IPC's results also reflect the benefits of growth in general business customers, warmer temperatures and rate increases that went into effect in June 2005. Additionally, IPC recorded a $4.7 million ($0.11 per diluted share) after-tax benefit from the sale of excess emission allowances.

IDACORP's non-regulated subsidiaries and holding company expenses reduced earnings by five cents per diluted share, compared to an eight-cent per share reduction in the second 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 effect of intra-period tax allocations recorded at the holding company and in discontinued operations.

Power Cost Adjustment
On June 1, 2006, IPC implemented its annual Power Cost Adjustment (PCA), which will result in a $123.5 million reduction in the rates of Idaho customers. The 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.

General rate case settlement
On June 1, 2006, IPC implemented a 3.2 percent ($18 million annual) increase to its Idaho retail base rates. IPC had filed a general rate case with the IPUC in October 2005, and the IPUC approved a settlement agreement in May 2006. Base rates primarily reflect IPC's cost of providing electrical service to its customers, including equipment, vehicles and infrastructure. IPC's overall allowed rate of return in Idaho increased from 7.85 percent to 8.1 percent.

SO₂ emission allowances settlement
As of June 30, 2006, IPC has sold 78,000 excess SO₂ emission 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). Through allowance vintage year 2006, IPC has approximately 32,000 excess allowances remaining.

On May 12, 2006, the IPUC approved ratemaking treatment of the sales proceeds. The IPUC order 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 of the Idaho jurisdiction 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 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.

June and July 2006 High Temperatures
IPC's service territory, along with much of the western United States, experienced above-normal temperatures during the months of June and July 2006. New records were set for cooling degree-days, a measure of temperature impact on customer demand. Due to these above-normal conditions, a new summer peak of 3,050 MW was first set on June 27, 2006, and was subsequently surpassed on July 24, 2006 when a new summer peak of 3,084 MW was recorded. Since June 27, the previous system peak of 2,983 MW, which was set in 2002, has been exceeded 12 times. IPC was able to meet all of its load requirements during these periods of increased demand through its system generation and by increasing the amount of its purchased power. In addition, wildfires are prevalent in the western United States this summer, including in and around IPC's service territory. In late July 2006 wildfires threatened but did not harm two transmission lines near IPC's Hells Canyon complex.

Idaho Water Management Issues
Power generation at the IPC hydroelectric power plants on the Snake River is dependent upon the state water rights held by IPC and the long-term sustainability of the Snake River, tributary spring flows and the Eastern Snake Plain Aquifer that is connected to the River. IPC continues to participate in water management issues in Idaho that may affect those water rights and resources. This includes active participation in the Snake River Basin Adjudication, a judicial action initiated in 1987 to determine the nature and extent of water use in the Snake River Basin, various judicial and administrative proceedings relating to the conjunctive management of ground and surface water rights, and management and planning processes intended to reverse declining trends in river, spring, and aquifer levels and address the long-term water resource needs of the State. While none of the pending water management issues are expected to impact IPC's hydroelectric generation in the near term, IPC's ongoing participation in such issues will help ensure that water remains available over the long-term for use at IPC's hydropower projects on the Snake River.

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 GAAP. The preparation of these financial statements requires IDACORP and IPC to make estimates and judgments that affect the reported amounts of assets, liabilities, revenues and expenses and related disclosure of contingent assets and liabilities. On an ongoing basis, IDACORP and IPC evaluate these estimates including those 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 and six months ended June 30, 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:

		Three Months Ended					Six Months Ended
		June 30,					June 30,
		2006			2005		2006	2005
Continuing operations:
IPC - Utility operations		$	21,612	$	12,876	$	46,633	$	34,385
IDACORP Financial Services			2,069		2,594		4,231		5,089
Ida-West Energy			1,030		756		1,363		826
IDACORP Energy			90		(215)		(111)		(513)
Holding Company			(2,128)		(3,418)		(2,488)		(1,552)
Income from continuing operations			22,673		12,593		49,628		38,235
Losses from discontinued operations			(2,817)		(3,142)		(4,296)		(5,718)
	Net income	$	19,856	$	9,451	$	45,332	$	32,517

Average common shares outstanding (diluted)			42,702		42,292		42,642	42,289
Diluted earnings (loss) per share:
	Income from continuing operations	$	0.53	$	0.30	$	1.16	$	0.91
	Losses from discontinued operations	$	(0.06)	$	(0.08)	$	(0.10)	$	(0.14)
	Diluted earnings per share	$	0.47	$	0.22	$	1.06	$	0.77

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.

Operations plans are developed during the year to provide guidance for generation resource utilization and energy market activities (off-system sales and power purchases). The plans incorporate 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 plans. 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 plans.

The following table presents IPC's power supply for the three and six months periods ended June 30:

	MWh
	Hydroelectric	Thermal	Total system	Purchased
	Generation	Generation	Generation	Power	Total
Three months ended:
June 30, 2006	3,038	1,215	4,253	1,786	6,039
June 30, 2005	1,942	1,562	3,504	838	4,342

Six months ended:
June 30, 2006	5,866	2,938	8,804	2,703	11,507
June 30, 2005	3,324	3,339	6,663	1,684	8,347

The observed streamflow data released on August 1, 2006, by the National Weather Service's Northwest River Forecast Center indicates that Brownlee reservoir inflow for April through July 2006 was 8.95 million acre-feet (maf), or 142 percent of average. Storage in selected federal reservoirs upstream of Brownlee as of July 31, 2006, was 116 percent of average. With current and forecasted stream flow conditions, IPC expects to generate between 8.8 and 9.3 million MWh from its hydroelectric facilities, compared to 6.2 million MWh in 2005.

Generation from thermal plants has been lower than 2005 due primarily to an unanticipated outage at the Boardman plant, of which IPC owns a ten percent interest. The unit returned to service in late June. The Bennett Mountain combustion turbine experienced an outage on July 11, 2006, and is expected to return to service in September 2006. IPC expects to generate approximately 6.8 million MWh from its thermal facilities in 2006, compared to 7.3 million MWh in 2005.

IPC's system load peaks in the summer and winter, with the larger peak demand occurring in the summer. IPC's record system peak of 3,084 MW occurred on July 24, 2006. IPC was able to meet system load requirements and off-system sales requirements and had sufficient system reserves in place.

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 and six months ended June 30:

			Three Months Ended June 30,				Six Months Ended June 30,
			2006		2005		2006		2005
Revenue
	Residential		$	64,005	$	60,599	$	152,442	$	139,375
	Commercial			40,511		41,540		83,541		81,432
	Industrial			27,006		28,101		56,893		55,114
	Irrigation			27,688		20,343		28,517		21,032
		Total	$	159,210	$	150,583	$	321,393	$	296,953
MWh
	Residential			1,024		955		2,440		2,283
	Commercial			873		867		1,785		1,754
	Industrial			845		836		1,721		1,668
	Irrigation			593		361		607		373
		Total		3,335		3,019		6,553		6,078
Customers (average, in thousands)
	Residential			385,980		371,288		384,494		369,699
	Commercial			58,701		56,873		58,490		56,674
	Industrial			132		128		132		127
	Irrigation			18,106		17,984		18,030		17,888
		Total		462,919		446,273		461,146		444,388

Heating degree-days				588		715		3,001		3,075
Cooling degree-days				269		108		269		108
Precipitation (inches)				3.83		6.03		8.20		7.80

Heating and cooling degree-days are a common measure used in the utility industry to analyze the demand for electricity and indicate when a customer would use electricity for heating and air conditioning. A degree-day measures how much the average daily temperature varies from 65 degrees. Each degree of temperature above 65 degrees is counted as one cooling degree-day, and each degree of temperature below 65 degrees is counted as one heating degree-day.

General business revenue increased $9 million for the quarter, due primarily to:

Usage: Weather variations positively impacted sales by approximately $13 million. Conditions were much drier and warmer in the second quarter of 2006 than the second quarter of 2005, which was abnormally cool and wet.
Customers: General business customer growth improved revenue $5 million for the quarter, as IPC continues to experience strong customer growth in its service territory.
Rates: Lower rates decreased general business revenue $9 million from the same quarter last year. On June 1, 2006, IPC implemented a PCA that decreased rates by an average of 19.3 percent, which was partially offset by base rate increases of 1.8 percent on June 1, 2005, and 3.2 percent on June 1, 2006.

General business revenues increased $24 million year-to-date, due primarily to:

Usage: Weather variations positively impacted sales by approximately $15 million. Conditions were much drier and warmer in the second quarter of 2006 than the second quarter of 2005, which was abnormally cool and wet.
Customers: General business customer growth improved revenue $11 million for the quarter, as IPC continues to experience strong customer growth in its service territory.
Rates: Lower rates decreased general business revenue $2 million from the same quarter last year. On June 1, 2006, IPC implemented a PCA that decreased rates by an average of 19.3 percent, which was partially offset by base rate increases of 1.8 percent on June 1, 2005, and 3.2 percent on June 1, 2006.

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

	Three months ended					Six months ended
	June 30,					June 30,
	2006		2005			2006	2005

Revenue	$	75,598	$	38,872	$	179,839	$	71,085
MWh sold		2,343		1,037		4,286		1,682
Revenue per MWh	$	32.27	$	37.48	$	41.95	$	42.26

Improved streamflow conditions increased total system generation and electricity available for surplus sales. Revenues from higher sales volumes were moderated by lower prices caused by abundant energy in the region. Additional sales activities are the result of conforming to IPC's risk management policy, managing IPC's energy portfolio to meet customer load, and reacting to changes in market conditions to minimize net power supply costs.

Other revenues: The following table presents the components of other revenues for the three and six months ended June 30:

		Three months ended					Six months ended
		June 30,					June 30,
		2006			2005		2006	2005

Transmission services and property rental		$	10,313	$	9,657	$	17,429	$	18,551
Rate case tax settlement			(1,891)		655		(4,846)		3,467
Irrigation load reduction			(2,207)		(1,108)		(5,518)		(1,108)
Provision for rate refund			(175)		229		(175)		400
	Total	$	6,040	$	9,433	$	6,890	$	21,310

The decrease in the second quarter of 2006 is due primarily to the amortization of previously accrued revenues from 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. From September 2004 to May 2005, this revenue was being accrued. From June 2005 to May 2006, it was recovered in rates (and presented in general business revenue), with a corresponding reduction to other revenues.

Also, from June 2005 to May 2006, IPC was collecting and recording in general business revenues amounts related to an irrigation load reduction program. There was an offsetting reduction to other revenues.

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

	Three months ended					Six months ended
	June 30,					June 30,
	2006			2005		2006	2005

Purchases	$	74,808	$	36,929	$	130,733	$	81,007
MWh purchased		1,786		838		2,703		1,684
Cost per MWh purchased	$	41.88	$	44.07	$	48.36	$	48.09

Early water year indications suggested continued drought conditions for 2006, which prompted IPC to make forward purchases in conformance with its risk management policy. Additional purchase activities are the result of managing IPC's energy portfolio to meet customer load and reacting to changes in market conditions to minimize net power supply costs.

Fuel expense: The following table presents IPC's fuel expenses and generation at its thermal generating plants for the three and six months ended June 30:

	Three months ended					Six months ended
	June 30,					June 30,
	2006			2005		2006	2005

Fuel expense	$	21,954	$	24,369	$	48,923	$	49,465
Thermal MWh generated		1,215		1,562		2,938		3,339
Cost per MWh	$	18.07	$	15.60	$	16.65	$	14.82

The decrease in fuel expense is due primarily to lower output at IPC's thermal plants, which reduced expense $5 million, partially offset by a $3 million increase in expense from higher coal prices 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 effects of IPC's PCA regulatory mechanism and Oregon deferrals of net power supply costs, which are discussed in more detail below in "REGULATORY MATTERS - Deferred (Accrued) Net Power Supply Costs."

The significant increase in hydroelectric production reduced year-to-date 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 and six months ended June 30:

		Three months ended				Six months ended
		June 30,				June 30,
		2006			2005	2006		2005
Current year power supply cost accrual (deferral)		$	2,839	$	3,382	$	43,718	$	(12,544)
Amortization of prior year authorized balances			1,761		9,033		4,349		20,542
	Total power cost adjustment	$	4,600	$	12,415	$	48,067	$	7,998

Other operating and maintenance expenses: O&M expenses increased $4 million for the quarter and $11 million year-to-date, compared to 2005. The primary cause of the second quarter increase was increased labor expense of approximately $2 million. The year-to-date increase primarily resulted from a $5 million increase in labor-related expenses, a $3 million increase in thermal plant expenses and a $2 million increase in electricity transmission expenses. Total O&M expenses in 2006 are expected to be between $250 and $260 million.

Non-utility operations

IFS
IFS contributed $2.1 million in the second quarter of 2006, compared to $2.6 million in the second 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 $4.6 million of tax credits in the second quarter of 2006 ($9.1 million year-to-date) and expects to continue delivering tax benefits at a level commensurate with the ongoing needs of IDACORP.

Discontinued Operations
In the second quarter of 2006, IDACORP management designated the operations of ITI and IDACOMM as assets held for sale, as defined by Statement of Financial Accounting Standards No. 144. The operations of these entities are presented as discontinued operations in IDACORP's financial statements.

ITI lost $1.4 million in the second quarter of 2006 and $3.3 million year-to-date, compared to losses of $2.4 million and $4.5 million for the same time periods in 2005. IDACOMM lost $0.8 million in the second quarter of 2006 and $0.4 million year-to-date, compared to losses of $0.2 million and $0.4 million for the same time periods in 2005. The results from discontinued operations also reflect the allocation of intra-period tax allocations.

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 on continuing operations for the six months ended June 30, 2006, was 23.6 percent, compared to 8.5 percent for the six months ended June 30, 2005. IPC's effective tax rate for the six months ended June 30, 2006, was 39.4 percent, compared to 35.4 percent for the six months ended June 30, 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 simplified service cost method 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 six months ended June 30, 2006, were $147 million and $116 million, respectively.

IDACORP's and IPC's operating cash flows increased $81 million and $47 million, respectively, compared to 2005. At IPC, favorable hydroelectric conditions reduced power supply costs significantly, but such costs were being collected in retail rates and a significant portion will be refunded through the PCA. Partially offsetting this increase was a $41 million increase in income tax payments made by IPC to IDACORP. The increase in IDACORP's operating cash flows was primarily the result of the increased collections from customers at IPC, and the collection of $10 million of accounts receivable and $10 million of margin deposits at IE, offset by a $34 million increase in income tax payments.

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.

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

Credit ratings
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)
Short-Term Tax-Exempt Debt	BBB/A-2	None	Baa 1/	None	None	None
			VMIG-2
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 58 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 excluding the sale of ITI. 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 externally financed capital.

The current expectation of approximately 58 percent of 2006 capital requirements is an increase from the 43 percent projected in IDACORP's and IPC's Quarterly Report on Form 10-Q for the quarter ended March 31, 2006. This increase is primarily due to proceeds received by IE for settling matters related to the California Refund proceedings, general business carryforward tax credits and working capital adjustments. These projections include $28 million in income taxes paid by IPC in the first quarter of 2006 on the $71 million received from the sale of excess SO₂ emission allowances in 2005. These income tax payments 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 70 percent of 2006 capital requirements. Emission allowances are discussed below in "REGULATORY MATTERS - Emission Allowances."

Utility construction program: Utility construction expenditures were $101 million for the six months ended June 30, 2006, compared to $86 million for the six months ended June 30, 2005 due primarily to increases in transmission and distribution construction. 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.

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 June 30, 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 June 30, 2006, the leverage ratios for both IDACORP and IPC were 51 percent. At June 30, 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 second quarter of 2006, IDACORP issued 63,141 shares.

LEGAL AND ENVIRONMENTAL ISSUES:

Legal and Other Proceedings

Shareholder Lawsuit: 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 had until May 1, 2006, to file an amended complaint only as to the loss causation element. On May 1, 2006, the plaintiffs filed an amended complaint. The defendants filed a motion to dismiss the amended complaint on June 16, 2006. The briefing schedule requires plaintiffs' response to defendants' motion to dismiss to be filed on or before August 14, 2006, and the defendants' response on or before August 28, 2006. IDACORP and the other defendants intend to defend themselves vigorously against the allegations. IDACORP cannot, however, predict the outcome of these matters.

Public Utility District No. 1 of Grays Harbor County, Washington: On July 25, 2006, the case was dismissed with prejudice by the Honorable Robert H. Whaley, sitting by designation in the U.S. District Court for the Southern District of California, pursuant to an agreed resolution of the matter between Grays Harbor and IDACORP, IPC and IE. The settlement did not have a material adverse effect on IDACORP's consolidated financial position, results of operation 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 affirming the dismissal of the entire case. The dismissal of the case, with prejudice, became final on June 28, 2006, when the Port of Seattle elected not to file a certiorari petition to the U.S. Supreme Court.

Wah Chang: Following the October 18, 2005 consolidation of Wah Chang's appeal of the dismissal order to the U.S. Court of Appeals for the Ninth Circuit with an identical order in Wah Chang v. Duke Energy Trading and Marketing, IDACORP, IPC and IE filed an answering brief on November 30, 2005. Wah Chang filed its reply brief on January 6, 2006. Wah Chang's appeal to the U.S. Court of Appeals for the Ninth Circuit has now been fully briefed; however, no date has yet been set for oral argument. IDACORP, IPC and IE 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. IDACORP, IPC and IE 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 April 2002, several subsidiaries of Reliant Energy, Inc. (Reliant) and Duke Energy Corporation (Duke) filed cross-complaints against IE and IPC and numerous other participants in the California energy market. The cross-complaints sought indemnification for any liability that may arise from original complaints filed against Reliant and Duke with respect to charges of unlawful and unfair business practices in the California energy markets under California law. On November 9, 2005, both Duke and Reliant submitted to the Court stipulations with IE and IPC to conditionally dismiss, with prejudice, the cross-complaints, subject to reinstatement if proposed settlements between Duke and Reliant and the plaintiffs of the underlying actions were not approved by the Court. Neither IE nor IPC paid any amount to Duke or to Reliant to obtain these dismissals.

Western Energy Proceedings at the FERC

1. California Refund
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 at the FERC. Non-settling parties had until March 9, 2005, to elect to become an additional settling party. The majority of non-settling parties chose to opt out of the Settlement. After consideration of comments, on May 22, 2006, the FERC approved the settlement. Under the terms of the settlement, IE and IPC assigned $24.25 million of the rights to accounts receivable from the California Independent System Operator (CalISO) 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 are 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. Any excess funds remaining at the conclusion of the case are to be returned to IDACORP. Approximately $10.25 million of the remaining IE and IPC receivables was paid to IE and IPC under the Settlement.

On May 22, 2006, the FERC issued an order approving, with certain conditions, the Offer of Settlement. On June 21, 2006, the Port of Seattle, Washington filed a request for rehearing of the FERC order approving the Settlement. On July 10, 2006, IDACORP and the California Parties filed a response to Port of Seattle's request for rehearing. On July 21, 2006, the FERC issued a tolling order in response to the Port of Seattle's request for rehearing, giving the FERC additional time to respond to the request. While IDACORP believes that this Settlement resolves all issues it may have related to the California Refund proceedings, it is possible that additional issues that affect IDACORP may arise in the future.

For some time the Ninth Circuit Court of Appeals held in abeyance consolidated petitions for review (in excess of 100) of FERC orders related to the California Refund proceeding. On September 21, 2004, the Ninth Circuit convened case management proceedings on these petitions and on October 22, 2004, severed a subset of issues for briefing related to: (1) which parties are subject to the FERC's refund jurisdiction under section 201(f) of the Federal Power Act; (2) the temporal scope of refunds under section 206 of the Federal Power Act; and (3) which categories of transaction are subject to refunds. Oral argument was held on April 12-13, 2005. On September 6, 2005, the Ninth Circuit issued a decision on the jurisdictional issues concluding that the FERC lacked refund authority over wholesale electric energy sales made by governmental entities and non-public utilities. On August 2, 2006 the Ninth Circuit issued its decision on the appropriate temporal reach and the type of transactions subject to FERC refund orders and concluded, among other things, that all transactions at issue in the case that occurred within or as a result of the Cal PX and the Cal ISO were the proper subject of refund proceedings; refused to expand the refund proceedings into the bilateral markets including transactions with the California Department of Water Resources; approved the refund effective date as October 2, 2000, but also required FERC to consider whether refunds, including possibly market-wide refunds, should be required for an earlier time due to claims that some market participants had violated governing tariff obligations (although the decision did not specify when that time would start, the California Parties generally had sought further refunds starting May 1, 2000); and effectively expanded the scope of the refund proceeding to transactions within the CalPX and CalISO markets outside the 24-hour spot market and energy exchange transactions.

IDACORP believes that these decisions should have no material effect on IDACORP under the terms of the IDACORP Settlement with the California Parties approved by the FERC on May 22, 2006.

2. California Power Exchange Chargeback
Based upon the 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 CalPX totaling $2.27 million. In the May 22, 2006, Order approving the Settlement, the FERC granted the IE and IPC motion for return of chargeback funds held by the CalPX. On June 1, 2006, IE received approximately $2.5 million from the CalPX representing the return of $2.27 million in chargeback funds plus interest.

3. Market Manipulation
Pursuant to 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 requests for rehearing of the California Parties and other settling parties of the FERC's approval of an earlier settlement with the FERC staff regarding allegations of "gaming" are deemed to be withdrawn. On May 22, 2006, the FERC issued an order approving the February 17, 2006, Offer of Settlement. If the FERC denies the few remaining requests for rehearing filed by non-settling parties of the FERC's approval of the "gaming" case settlement, the effect would be to terminate the FERC investigations as to IPC and IE regarding bidding behavior, physical withholding of power and "gaming" without finding of wrongdoing.

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. The Settlement approved by the FERC on May 22, 2006 resolves all claims the California Parties have against IE and IPC in the Pacific Northwest Refund proceeding. The settlement with Grays Harbor resolves all claims Grays Harbor has against IE and IPC in this proceeding. IE and IPC are unable to predict the outcome as to all other parties in this proceeding.

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.

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 continues to participate in actions, as necessary, to protect its water rights. One such action relates to the constitutionality of the Conjunctive Management Rules (CMR) that were developed by the IDWR to administer connected ground and surface water rights. In August 2005, the surface water irrigation entities that initiated the delivery call filed an action against the IDWR in the state district court in Gooding County, Idaho for a declaratory judgment regarding the validity and constitutionality of the CMR. IPC intervened in the action as a plaintiff/intervenor. The Idaho Ground Water Appropriators intervened as a defendant. In October 2005, the plaintiffs in the case filed a motion for summary judgment, contending that the CMR were unconstitutional and violated the doctrine of prior appropriation as applied in Idaho. After briefing and argument, on June 2, 2006, the district court issued a memorandum decision granting summary judgment to the plaintiffs and holding that the CMR are unconstitutional because the rules failed to protect senior water rights from injury by junior water right diversions. On July 11, 2006, the IDWR appealed the court's order to the Idaho Supreme Court and subsequently filed a motion with the district court asking the court to stay the effect of its order until the conclusion of the appeal.

IPC, together with other interested water users and state interests, also continues to explore and encourage the development of a long-term management plan that will protect the aquifer and the river 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 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.

At the conclusion of the legislative session, the Senate passed Senate Concurrent Resolution 136 directing the Idaho Water Resource Board (IWRB) to develop a comprehensive aquifer management plan for the Eastern Snake Plain Aquifer (ESPA) and to receive public input regarding the goals, objectives, and methods of management for the ESPA from affected water right holders, cities, counties, the general public and state and federal agencies. The IWRB initiated a public process for the development of an aquifer management plan in June 2006. IPC is participating in that process. The IWRB is expected to report to the Idaho Legislature in 2007 on the progress of the planning effort.

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 IWRB. 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 water rights dismissed.

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 state mercury plans in Idaho, Wyoming, Nevada, and Oregon. 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.

Regional Haze studies are being performed on the IPC jointly-owned thermal plants to determine the effect on Class I wilderness areas. IPC is monitoring the results of these studies and issues surrounding regional haze. It is anticipated that Regional Haze rules 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 May 12, 2006, the IPUC issued an order approving a settlement of IPC's general rate case filed in October 2005. The order approves an average increase of 3.2 percent in base rates, or $18 million in revenues, effective June 1, 2006.

On February 27, 2006, IPC, the IPUC staff and representatives of customer groups had filed a stipulation with the IPUC that became the basis for the final order.

IPC's original filing had asked for an annual increase to its Idaho retail base rates of $44 million, a 7.8 percent average increase. 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.

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.

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

		June 30,		December 31,
		2006		2005
Idaho PCA current year:
	Deferral (accrual) for the 2006-2007 rate year	$	-	$	3,684
	Deferral (accrual) for the 2007-2008 rate year *		(47,064)		-
Idaho PCA true-up awaiting recovery (refund):
	Authorized May 2005		-		28,567
	Authorized May 2006		(19,265)		-
Oregon deferral:
	2001 costs		7,637		8,411
	2005 costs		2,790		2,880
	Total deferral (accrual)	$	(55,902)	$	43,542
* includes a $42.1 million credit for SO₂emission allowance sales allocated to customers

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

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

On 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 2003 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. A settlement conference is scheduled for August 17, 2006.

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. On June 14, 2006, a settlement conference was held; however, settlement is pending further staff review.

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.

Fixed Cost Adjustment Mechanism (FCA)
On January 27, 2006, IPC filed with the IPUC for authority to implement a rate adjustment mechanism that would adjust rates downward or upward to recover fixed costs independent from the volume of IPC's energy sales. This filing is a continuation of a 2004 case that was opened to investigate the financial disincentives to investment in energy efficiency by IPC. This true-up mechanism would be applicable only to residential and small general service customers. The first FCA rate change under this proposal would occur on June 1, 2007, coincident with IPC's PCA rate change. The accounting for the FCA will be separate from the PCA. As part of the filing, IPC proposes a three percent cap on any rate increase to be applied at the discretion of the IPUC.

On March 6, 2006, the IPUC reviewed IPC's decoupling proposal and acknowledged the intent of IPC and the IPUC Staff to initiate and engage in settlement discussions. The first workshop was held on May 17, 2006. Additional analysis is currently being completed prior to the next workshop which is not yet scheduled.

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. In the filing IPC proposed 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. On May 31, 2006, the FERC accepted IPC's rates, permitting them to become effective on June 1, 2006, subject to refund based on the outcome of settlement negotiations. The new rates are based on 2005 Form 1 data. IPC has implemented these new rates and established a reserve for possible refund to customers. A settlement conference was held June 28, 2006. The intervenors presented an issues list which addressed small rate making adjustments, a reduction to the requested rate of return on equity, the development of an extensive annual audit plan, and concerns related to the treatment of legacy contracts. A second settlement conference is scheduled for August 16, 2006. IPC is preparing to respond to data requests. A number of parties have intervened in the case. IPC is unable to predict the outcome of this matter.

Integrated Resource Plan
Preparation of the 2006 Integrated Resource Plan (IRP) is in progress. The initial meeting of the IRP Advisory Council was held on October 20, 2005, and subsequent meetings have continued on a regular (typically monthly) basis. In the 2006 IRP, the planning period will change from a ten-year forecast to a 20-year forecast. The 2006 IRP was originally scheduled to be filed in June 2006; however, the IPUC granted IPC's request for a 90-day extension of time to file its 2006 IRP until September 29, 2006.

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 also requests confirmation that IPC can expect to include in rate base the prudent capital costs for the project and recover prudent fuel costs through its PCA mechanism. The application is based on a signed contract with Siemens Power Generation, Inc. to construct the plant valued at $50 million. The contract is contingent upon approval of the application by the IPUC. The parties are involved in the discovery stage of the application process. Technical hearings are scheduled for November 20-21, 2006, and IPC anticipates a conclusion before year end. Related transmission interconnection and line upgrades will be constructed by IPC at an estimated cost of $23 million.

PURPA Wind Projects: As of June 2006, three wind projects, with a total nameplate capacity of 19.9 MW, are selling energy to IPC under approved PURPA agreements. An additional thirteen wind projects, comprising 186.9 MW of wind generation, for a total of 206.8 MW, have approved PURPA agreements and are scheduled to come online during 2006 and 2007.

Wind RFP: IPC has selected Horizon Wind Energy as the successful bidder in IPC's RFP for renewable wind-powered generation issued on January 13, 2005. Horizon's proposal is for a 66-MW project located near La Grande, Oregon, and is expected to be online by the end of 2007. The northeast Oregon location for the Horizon project is different from the existing and proposed PURPA wind projects, which are located along the Snake River in southern Idaho, and should complement the energy from the existing wind projects.

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, 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 Policy 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 (EIS) 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 EIS will describe and evaluate the probable effects, if any, of the proposed action and the other alternatives considered. Section 241 of the Energy Policy 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. Federal agencies with mandatory conditioning authority under sections 4(e) and 18 of the FPA also filed their preliminary terms and conditions under those sections with the FERC on January 26, 2006. The Energy Policy Act of 2005, 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). IPC also filed proposed alternative conditions with the agencies. The hearing requests related to travel and access management, law enforcement and emergency services, and recreation and land management conditions proposed by the BLM, and sediment supply 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. Each of the agencies responded to the hearing requests and referred the requests to the hearings division within the respective agencies for assignment to an administrative law judge (ALJ). Hearings were subsequently set before a Department of Interior ALJ for June 12, 2006, on the requests for hearing on the BLM conditions and a Department of Agriculture ALJ for June 19, 2006, on the USFS requests for hearing. While IPC was preparing for the evidentiary hearings, IPC continued to engage in discussions with the respective agencies regarding possible settlements.

Through these discussions, IPC was able to resolve the disputed issues associated with the pending hearing requests. On May 10, 2006, IPC and the USFS filed a stipulation with the Department of Agriculture ALJ, and revised preliminary terms and conditions with the FERC, resolving all issues associated with the pending USFS hearing requests except for the issues associated with the USFS condition relating to sediment supply and sandbar maintenance. These issues remained subject to hearing on June 19, 2006. On May 15, 2006, IPC and the BLM filed a stipulation with the Department of Interior ALJ and revised preliminary terms and conditions with the FERC resolving all issues associated with the pending BLM hearing requests. Through subsequent settlement discussions with the USFS, IPC resolved all disputed issues associated with the hearing request on the USFS condition relating to sediment supply and sandbar maintenance.

All of these hearing requests were resolved through stipulations between IPC and the USFS and BLM, respectively, providing for the withdrawal of IPC's requests for hearing and the filing of revised preliminary terms and conditions with the FERC with provisions that were acceptable to IPC.

The FERC will now consider all of the comments, recommendations, terms, conditions and prescriptions submitted by the parties and IPC, as well as the final license application and supporting studies and materials, under the provisions of the FPA and NEPA. On June 7, 2006, the FERC issued an updated schedule for the relicensing process, indicating that it intended to issue a draft EIS on July 31, 2006, hold meetings on the draft EIS in late August and early September 2006 and issue a final EIS by February 26, 2007. The FERC will include those conditions in the final EIS, and in the new 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.

On July 28, 2006, the FERC released the draft EIS. Official notice of its release was published in the Federal Register on August 4, 2006. Comments are to be filed with the FERC by October 2, 2006. The draft EIS is prepared by the FERC staff, pursuant to NEPA and applicable federal regulations, to inform the FERC Commissioners, the public, state and federal agencies and the tribes about the potential adverse and beneficial environmental effects of licensing of the project as proposed by the IPC in its license application and provide a review of other reasonable alternatives or measures that might be included in a license for the project. Based upon the draft EIS, the subsequent comments received, the license application and other material in the FERC record, the FERC Commissioners will decide whether to license the HCC and what conditions to include in the license to address project effects. IPC is in the process of reviewing the draft EIS and will prepare comments for filing with the FERC. Because this is a draft EIS, containing only FERC staff conclusions, it cannot be relied upon to accurately predict the outcome of the relicensing process. IPC's preliminary review of the draft EIS, however, indicates that the FERC staffs' conclusions with regard to the effects of the project and the measures necessary to address those effects are in many respects consistent with the license application filed by IPC.

At June 30, 2006, $82 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 issued a Formal Consultation Package 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 June 30, 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. Oral argument on the appeal was held on June 8, 2006. On July 12, 2006 the Ninth Circuit issued a memorandum decision denying the conservation groups' appeal.

Shoshone Falls Expansion
IPC has developed a License Amendment Application to upgrade the Shoshone Falls hydroelectric project from 12 MW to 62.5 MW. Earlier this year, the draft application was distributed to involved parties for comments. The comment period is now closed and few comments were received. IPC has responded to those comments. IPC will submit the final License Amendment Application to the FERC in August 2006 and the application will move through the FERC's normal evaluation process.

Regional Transmission Organization
In December 1999, the FERC, in Order No. 2000, encouraged all companies with transmission assets to form regional transmission organizations (RTOs). 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.

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. 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 spent funds supporting the development of Grid West. Funding of this effort took two forms. First, funds were loaned to Grid West for the purpose of meeting its developmental expenses. The total accumulated loan through the second quarter of 2006 was approximately $1.1 million. IPC no longer expects this loan to be repaid by Grid West. Second, IPC incurred incremental internal costs from participating in the developmental effort, which are mostly related to incremental travel and legal consultation. Prior to 2005, IPC accumulated these costs in a deferred expense account, which totaledapproximately $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.

On June 29, 2006, the IPUC determined that the case would be processed under modified procedure where a formal hearing is not expected. IPC is currently responding to the IPUC Staff's audit requests. Comments on the case are due to the IPUC by August 14, 2006.

A June 16, 2006 OPUC Staff analysis contended that the OPUC has the authority to grant the IPC application for deferred accounting. On July 10, 2006, IPC concurred with the analysis. IPC filed reply comments on July 28, 2006.

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.

New Accounting Pronouncements
See Note 1 to IDACORP's and IPC's Condensed Consolidated Financial Statements for a discussion of recently issued accounting pronouncements.

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 June 30, 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 June 30, 2006, IDACORP and IPC had $117 million and $84 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 June 30, 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 June 30, 2006, IDACORP and IPC had outstanding fixed rate debt of $913 million and $865 million, respectively. The fair market value of this debt was $876 million and $829 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 $72 million for IDACORP and $71 million for IPC if interest rates were to decline by one percentage point from their June 30, 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 its forward book of electricity trading contracts, IE had 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 was $20 million. During the second quarter this guarantee terminated and IE was refunded all outstanding margin deposits.

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 June 30, 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 June 30, 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 June 30, 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

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 June 30, 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.

Issuer Purchases of Equity Securities:

IDACORP, Inc. Common Stock

						(d) Maximum Number
					(c) Total Number of	(or Approximate
		(a) Total			Shares Purchased	Dollar Value) of
		Number of	(b) Average		as Part of Publicly	Shares that May Yet
		Shares	Price Paid		Announced Plans or	Be Purchased Under
Period		Purchased1	per Share		Programs	the Plans or Programs

April 1 - April 30, 2006		2,655	$	33.63	-	-
May 1 - May 31, 2006		-		-	-	-
June 1 - June 30, 2006		3,404	$	34.29	-	-
	Total	6,059	$	34.00	-	-

1These shares were withheld for taxes upon vesting of restricted stock.

ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS

IDACORP, Inc.:

(a)

Regular annual meeting of IDACORP, Inc.'s shareholders, held May 18, 2006, in Boise, Idaho.

(b)

Directors elected at the meeting for a three-year term:

Gary G. Michael

Jan B. Packwood

Peter S. O'Neill

Continuing Directors:

Rotchford L. Barker

Richard G. Reiten

J. LaMont Keen

Joan H. Smith

Jack K. Lemley

Robert A. Tinstman

Jon H. Miller

Thomas J. Wilford

(c)

To elect three Director Nominees:

Name

For

Withheld

Total Voted

Gary G. Michael

34,816,131

1,457,932

42,790,242

Peter S. O'Neill

35,287,853

986,210

42,790,242

Jan B. Packwood

35,281,339

992,724

42,790,242

To ratify the selection of Deloitte & Touche LLP as the registered public accounting firm for the

fiscal year ending December 31, 2006:

Class of Stock

For

Against

Abstain

Total Voted

Common

35,599,651

424,709

249,701

42,790,242

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. File number 1-14465, 1-3198, Form 10-Q for the quarter ended 3/31/06, filed on 5/9/06, as Exhibit 10(h)(xxix).

*10(h)(xxx)1	First Amendment to the Idaho Power Company Security Plan for Senior Management Employees, effective December 31, 2004. File number 1-14465, 1-3198, Form 10-Q for the quarter ended 3/31/06, filed on 5/9/06, as Exhibit 10(h)(xxx).

*10(h)(xxxi)1	Idaho Power Company Executive Deferred Compensation Plan, effective November 15, 2000. File number 1-14465, 1-3198, Form 10-Q for the quarter ended 3/31/06, filed on 5/9/06, as Exhibit 10(h)(xxxi).

*10(h)(xxxii)1	First Amendment to the Idaho Power Company Executive Deferred Compensation Plan, effective October 1, 2003. File number 1-14465, 1-3198, Form 10-Q for the quarter ended 3/31/06, filed on 5/9/06, as Exhibit 10(h)(xxxii).

*10(h)(xxxiii)1	Second Amendment to the Idaho Power Company Executive Deferred Compensation Plan, effective January 1, 2005. File number 1-14465, 1-3198, Form 10-Q for the quarter ended 3/31/06, filed on 5/9/06, as Exhibit 10(h)(xxxiii).

*10(h)(xxxiv)1	Third Amendment to the Idaho Power Company Executive Deferred Compensation Plan, effective January 1, 2005. File number 1-14465, 1-3198, Form 10-Q for the quarter ended 3/31/06, filed on 5/9/06, as Exhibit 10(h)(xxxiv).

*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 second 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	August 8, 2006	By:	/s/ J. LaMont Keen
			J. LaMont Keen
			President and Chief Executive Officer

Date	August 8, 2006	By:	/s/ Darrel T. Anderson
			Darrel T. Anderson
			Senior Vice President - Administrative Services
			and Chief Financial Officer

IDAHO POWER COMPANY

(Registrant)

Date	August 8, 2006	By:	/s/ J. LaMont Keen
			J. LaMont Keen
			President and Chief Executive Officer

Date	August 8, 2006	By:	/s/ Darrel T. Anderson
			Darrel T. Anderson
			Senior Vice President - Administrative Services
			and Chief Financial Officer

Three Months Ended

Six Months Ended