UNITED STATES SECURITIES AND EXCHANGE COMMISSION

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

				Three Months Ended September 30,
				2005		2004
				(thousands of dollars except for per
				share amounts)
Operating Revenues:
	Electric utility:
		General business		$	207,237	$	186,687
		Off-system sales			34,105		34,969
		Other revenues			2,890		19,532
			Total electric utility revenues		244,232		241,188
	Other				4,910		5,489
		Total operating revenues			249,142		246,677

Operating Expenses:
	Electric utility:
		Purchased power			81,396		79,607
		Fuel expense			28,018		28,291
		Power cost adjustment			(9,670)		19,620
		Other operations and maintenance			64,292		63,243
		Depreciation			25,726		25,229
		Taxes other than income taxes			5,115		4,593
			Total electric utility expenses		194,877		220,583
	Other				11,053		7,161
			Total operating expenses		205,930		227,744

Operating Income (Loss):
	Electric utility				49,355		20,605
	Other				(6,143)		(1,672)
		Total operating income			43,212		18,933

Other Income					3,763		3,297

Earnings of Unconsolidated Equity-method Investments					872		2,225

Other Expenses					1,759		1,495

Interest Expense and Preferred Dividends:
	Interest on long-term debt				14,317		14,061
	Other interest				609		602
	Preferred dividends of Idaho Power Company				-		3,116
		Total interest expense and preferred dividends			14,926		17,779

Income Before Income Taxes					31,162		5,181

Income Tax Expense (Benefit)					7,545		(20,886)

Net Income				$	23,617	$	26,067

Weighted Average Common Shares Outstanding (000's)					42,287		38,191
Earnings Per Share of Common Stock (basic and diluted)				$	0.56	$	0.68
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)

				Nine Months Ended September 30,
				2005		2004
				(thousands of dollars except for per
				share amounts)
Operating Revenues:
	Electric utility:
		General business		$	504,189	$	491,149
		Off-system sales			105,189		99,899
		Other revenues			25,429		40,653
			Total electric utility revenues		634,807		631,701
	Other				15,988		15,037
		Total operating revenues			650,795		646,738

Operating Expenses:
	Electric utility:
		Purchased power			162,403		162,877
		Fuel expense			77,483		77,364
		Power cost adjustment			(1,673)		30,438
		Other operations and maintenance			185,108		180,515
		Depreciation			75,838		75,459
		Taxes other than income taxes			15,644		15,536
		Impairment of assets			-		9,756
			Total electric utility expenses		514,803		551,945
	Other				34,038		24,259
			Total operating expenses		548,841		576,204

Operating Income (Loss):
	Electric utility				120,004		79,756
	Other				(18,050)		(9,222)
		Total operating income			101,954		70,534

Other Income					11,390		21,007

Earnings of Unconsolidated Equity-method Investments					584		2,919

Other Expenses					4,055		7,231

Interest Expense and Preferred Dividends:
	Interest on long-term debt				42,683		40,628
	Other interest				1,879		2,641
	Preferred dividends of Idaho Power Company				-		4,823
		Total interest expense and preferred dividends			44,562		48,092

Income Before Income Taxes					65,311		39,137

Income Tax Expense (Benefit)					9,176		(19,580)

Net Income				$	56,135	$	58,717

Weighted Average Common Shares Outstanding (000's)					42,245		38,193
Earnings Per Share of Common Stock (basic and diluted)				$	1.33	$	1.54
Dividends Paid Per Share of Common Stock				$	0.90	$	0.90

The accompanying notes are an integral part of these statements.

IDACORP, Inc.
Condensed Consolidated Balance Sheets
(unaudited)

			September 30,		December 31,
			2005		2004
Assets			(thousands of dollars)

Current Assets:
	Cash and cash equivalents		$	13,313	$	23,403
	Receivables:
		Customer		99,200		92,258
		Allowance for uncollectible accounts		(42,940)		(43,108)
		Employee notes		3,090		3,523
		Other		21,696		8,806
	Energy marketing assets			30,822		9,203
	Accrued unbilled revenues			32,336		33,832
	Materials and supplies (at average cost)			32,406		28,008
	Fuel stock (at average cost)			8,200		6,539
	Prepayments			19,865		30,035
	Deferred income taxes			25,132		23,407
	Regulatory assets			3,350		5,510
	Other			2,956		-
		Total current assets		249,426		221,416

Investments				189,393		223,061

Property, Plant and Equipment:
	Utility plant in service			3,463,462		3,324,816
	Accumulated provision for depreciation			(1,373,285)		(1,316,125)
		Utility plant in service - net		2,090,177		2,008,691
	Construction work in progress			144,815		152,427
	Utility plant held for future use			2,652		2,636
	Other property, net of accumulated depreciation			45,358		45,708
		Property, plant and equipment - net		2,283,002		2,209,462

Other Assets:
	American Falls and Milner water rights			31,585		31,585
	Company-owned life insurance			35,616		35,765
	Energy marketing assets - long-term			28,427		16,635
	Regulatory assets			416,209		433,271
	Long-term receivables (net of allowance of $2,578)			3,343		2,895
	Employee notes			3,130		3,746
	Goodwill			13,397		13,659
	Other			47,329		42,677
		Total other assets		579,036		580,233

		Total	$	3,300,857	$	3,234,172

The accompanying notes are an integral part of these statements.

IDACORP, Inc.
Condensed Consolidated Balance Sheets
(unaudited)

				September 30,		December 31,
				2005		2004
Liabilities and Shareholders' Equity				(thousands of dollars)

Current Liabilities:
	Current maturities of long-term debt			$	17,851	$	78,603
	Notes payable				55,600		36,270
	Accounts payable				53,197		79,156
	Energy marketing liabilities				31,110		9,420
	Taxes accrued				66,092		46,318
	Interest accrued				20,754		14,426
	Other				39,658		21,265
		Total current liabilities			284,262		285,458

Other Liabilities:
	Deferred income taxes				540,533		555,774
	Energy marketing liabilities - long-term				28,427		16,635
	Regulatory liabilities				275,959		275,854
	Other				126,670		112,616
		Total other liabilities			971,589		960,879

Long-Term Debt					1,028,882		979,549

Commitments and Contingencies (Notes 5 and 6)

Shareholders' Equity:
	Common stock, no par value (shares authorized 120,000,000; 42,561,278
		and 42,373,758 shares issued, respectively)			596,685		589,440
	Retained earnings				429,688		424,312
	Accumulated other comprehensive loss				(2,928)		(888)
	Treasury stock (239,165 and 156,741 shares at cost, respectively)				(7,321)		(4,578)
		Total shareholders' equity			1,016,124		1,008,286

			Total	$	3,300,857	$	3,234,172

The accompanying notes are an integral part of these statements.

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

				Nine Months Ended
				September 30,
				2005		2004
Operating Activities:				(thousands of dollars)
	Net income			$	56,135	$	58,717
	Adjustments to reconcile net income to net cash provided by
		operating activities:
		Impairment of long-lived assets			-		9,756
		Depreciation and amortization			93,069		93,298
		Deferred taxes and investment tax credits			(8,030)		(25,924)
		Changes in regulatory assets and liabilities			2,974		26,645
		Gain on sale of non-utility assets			(1,490)		(4,557)
		Gain on extinguishment of debt			-		(7,188)
		Undistributed earnings of equity method investments			(12,027)		1,348
		Change in:
			Accounts receivables and prepayments		(9,042)		(1,351)
			Accounts payable and other accrued liabilities		(31,518)		(6,800)
			Taxes accrued		19,774		2,148
			Other current assets		(3,535)		(978)
			Other current liabilities		9,715		7,438
		Other assets			(4,384)		(7,845)
		Other liabilities			9,542		10,705
			Net cash provided by operating activities		121,183		155,412

Investing Activities:
	Additions to property, plant and equipment				(133,217)		(145,061)
	Sale of non-utility assets				243		5,389
	Investments in affordable housing				(3,752)		-
	Purchase of available-for-sale securities				(81,693)		(12,842)
	Sale of available-for-sale securities				116,079		13,664
	Purchase of held-to-maturity securities				(1,369)		(3,723)
	Maturity of held-to-maturity securities				2,789		3,397
	Other assets				395		1,289
	Other liabilities				-		(3,091)
		Net cash used in investing activities			(100,525)		(140,978)

Financing Activities:
	Issuance of long-term debt				64,992		105,000
	Retirement of long-term debt				(76,166)		(73,419)
	Retirement of IPC preferred stock				-		(52,220)
	Issuance of common stock				3,661		206
	Dividends on common stock				(38,001)		(34,224)
	Change in short-term borrowings				19,330		(12,385)
	Acquisition of treasury shares				-		(1,420)
	Other assets				(4,388)		-
	Other liabilities				(176)		(182)
		Net cash used in financing activities			(30,748)		(68,644)

Net decrease in cash and cash equivalents					(10,090)		(54,210)
Cash and cash equivalents beginning of period					23,403		75,159

Cash and cash equivalents end of period				$	13,313	$	20,949

Supplemental Disclosure of Cash Flow Information:
	Cash paid during the period for:
		Income taxes		$	2,718	$	8,948
		Interest (net of amount capitalized)		$	36,361	$	32,868
	Non-cash financing activities:
		Dividends declared and payable		$	12,757	$	-

The accompanying notes are an integral part of these statements.

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

				Three Months Ended
				September 30,
				2005		2004
				(thousands of dollars)

Net Income				$	23,617	$	26,067

Other Comprehensive Income (Loss):
	Unrealized gains (losses) on securities:
		Unrealized holding gains (losses) arising during the period,
			net of tax of $196 and ($302)		214		(526)
		Reclassification adjustment for (gains) losses included
			in net income, net of tax of ($321) and ($228)		(500)		(355)
			Net unrealized gains (losses)		(286)		(881)

Total Comprehensive Income				$	23,331	$	25,186

				Nine Months Ended
				September 30,
				2005		2004
				(thousands of dollars)

Net Income				$	56,135	$	58,717

Other Comprehensive Income (Loss):
	Unrealized gains (losses) on securities:
		Unrealized holding gains (losses) arising during the period,
			net of tax of ($393) and ($18)		(929)		(56)
		Reclassification adjustment for (gains) losses included
			in net income, net of tax of ($714) and ($609)		(1,111)		(949)
			Net unrealized gains (losses)		(2,040)		(1,005)

Total Comprehensive Income				$	54,095	$	57,712

The accompanying notes are an integral part of these statements.

Idaho Power Company
Condensed Consolidated Statements of Income
(unaudited)

			Three Months Ended
			September 30,
			2005		2004
			(thousands of dollars)
Operating Revenues:
	General business		$	207,237	$	186,687
	Off-system sales			34,105		34,969
	Other revenues			2,161		18,563
		Total operating revenues		243,503		240,219

Operating Expenses:
	Operation:
		Purchased power		81,396		79,607
		Fuel expense		28,018		28,291
		Power cost adjustment		(9,670)		19,620
		Other		50,486		48,147
	Maintenance			13,173		14,336
	Depreciation			25,726		25,229
	Taxes other than income taxes			5,115		4,593
		Total operating expenses		194,244		219,823

Income from Operations				49,259		20,396

Other Income (Expense):
	Allowance for equity funds used during construction			1,158		912
	Earnings of unconsolidated equity-method investment			2,937		3,916
	Other income			3,069		2,906
	Other expense			(2,462)		(2,203)
		Total other income		4,702		5,531

Interest Charges:
	Interest on long-term debt			13,427		12,640
	Other interest			704		930
	Allowance for borrowed funds used during construction			(668)		(657)
		Total interest charges		13,463		12,913

Income Before Income Taxes				40,498		13,014

Income Tax Expense (Benefit)				19,529		(13,981)

Net Income				20,969		26,995

	Dividends on Preferred Stock			-		3,116

Earnings on Common Stock			$	20,969	$	23,879

The accompanying notes are an integral part of these statements.

Idaho Power Company
Condensed Consolidated Statements of Income
(unaudited)

			Nine Months Ended
			September 30,
			2005		2004
			(thousands of dollars)
Operating Revenues:
	General business		$	504,189	$	491,149
	Off-system sales			105,189		99,899
	Other revenues			23,473		38,191
		Total operating revenues		632,851		629,239

Operating Expenses:
	Operation:
		Purchased power		162,403		162,877
		Fuel expense		77,483		77,364
		Power cost adjustment		(1,673)		30,438
		Other		137,119		132,687
	Maintenance			46,133		45,459
	Depreciation			75,838		75,459
	Taxes other than income taxes			15,644		15,536
	Impairment of assets			-		9,756
		Total operating expenses		512,947		549,576

Income from Operations				119,904		79,663

Other Income (Expense):
	Allowance for equity funds used during construction			3,702		2,938
	Earnings of unconsolidated equity-method investment			8,127		9,427
	Other income			8,691		7,709
	Other expense			(6,191)		(6,308)
		Total other income		14,329		13,766

Interest Charges:
	Interest on long-term debt			39,982		37,173
	Other interest			2,593		2,866
	Allowance for borrowed funds used during construction			(2,060)		(2,119)
		Total interest charges		40,515		37,920

Income Before Income Taxes				93,718		55,509

Income Tax Expense (Benefit)				38,364		(540)

Net Income				55,354		56,049

Dividends On Preferred Stock				-		4,823

Earnings On Common Stock			$	55,354	$	51,226

The accompanying notes are an integral part of these statements.

Idaho Power Company
Condensed Consolidated Balance Sheets
(unaudited)

				September 30,		December 31,
				2005		2004
Assets				(thousands of dollars)

Electric Plant:
	In service (at original cost)			$	3,463,462	$	3,324,816
	Accumulated provision for depreciation				(1,373,285)		(1,316,125)
		In service - net			2,090,177		2,008,691
	Construction work in progress				142,014		151,652
	Held for future use				2,652		2,636

			Electric plant - net		2,234,843		2,162,979

Investments and Other Property					62,544		86,086

Current Assets:
	Cash and cash equivalents				8,405		17,679
	Receivables:
		Customer			52,779		45,441
		Allowance for uncollectible accounts			(1,195)		(1,363)
		Notes			3,221		3,129
		Employee notes			3,090		3,523
		Related parties			67		1,298
		Other			6,017		5,253
	Accrued unbilled revenues				32,336		33,832
	Materials and supplies (at average cost)				30,119		26,065
	Fuel stock (at average cost)				8,200		6,539
	Prepayments				18,566		28,449
	Regulatory assets				3,350		5,510

			Total current assets		164,955		175,355

Deferred Debits:
	American Falls and Milner water rights				31,585		31,585
	Company-owned life insurance				35,616		35,765
	Regulatory assets				416,209		433,271
	Employee notes				3,130		3,746
	Other				43,351		40,425

			Total deferred debits		529,891		544,792

	Total			$	2,992,233	$	2,969,212

The accompanying notes are an integral part of these statements.

Idaho Power Company
Condensed Consolidated Balance Sheets
(unaudited)

				September 30,		December 31,
				2005		2004
Capitalization and Liabilities				(thousands of dollars)

Capitalization:
	Common stock equity:
		Common stock, $2.50 par value (50,000,000 shares
			authorized; 39,150,812 shares outstanding)	$	97,877	$	97,877
		Premium on capital stock			483,707		483,707
		Capital stock expense			(2,097)		(2,097)
		Retained earnings			344,703		340,107
		Accumulated other comprehensive loss			(2,928)		(888)

			Total common stock equity		921,262		918,706

	Long-term debt				983,663		923,910

			Total capitalization		1,904,925		1,842,616

Current Liabilities:
	Long-term debt due within one year				-		60,000
	Accounts payable				50,053		74,642
	Notes and accounts payable to related parties				13,109		278
	Taxes accrued				67,029		42,228
	Interest accrued				20,075		13,743
	Deferred income taxes				3,350		5,510
	Other				24,029		18,103

			Total current liabilities		177,645		214,504

Deferred Credits:
	Deferred income taxes				527,647		542,829
	Regulatory liabilities				275,959		275,854
	Other				106,057		93,409

			Total deferred credits		909,663		912,092

Commitments and Contingencies (Notes 5 and 6)

			Total	$	2,992,233	$	2,969,212

The accompanying notes are an integral part of these statements.

Idaho Power Company
Condensed Consolidated Statements of Capitalization
(unaudited)

				September 30,				December 31,
				2005		%		2004		%
				(thousands of dollars)
Common Stock Equity:
	Common stock			$	97,877			$	97,877
	Premium on capital stock				483,707				483,707
	Capital stock expense				(2,097)				(2,097)
	Retained earnings				344,703				340,107
	Accumulated other comprehensive loss				(2,928)				(888)
		Total common stock equity			921,262		48		918,706		50

Long-Term Debt:
	First mortgage bonds:
		5.83% Series due 2005			-				60,000
		7.38% Series due 2007			80,000				80,000
		7.20% Series due 2009			80,000				80,000
		6.60% Series due 2011			120,000				120,000
		4.75% Series due 2012			100,000				100,000
		4.25% Series due 2013			70,000				70,000
		6% Series due 2032			100,000				100,000
		5.50% Series due 2033			70,000				70,000
		5.50% Series due 2034			50,000				50,000
		5.875%Series due 2034			55,000				55,000
		5.30% Series due 2035			60,000				-
			Total first mortgage bonds		785,000				785,000
		Amount due within one year			-				(60,000)
			Net first mortgage bonds		785,000				725,000

	Pollution control revenue bonds:
		Variable Auction Rate Series 2003 due 2024			49,800				49,800
		6.05% Series 1996A due 2026			68,100				68,100
		Variable Rate Series 1996B due 2026			24,200				24,200
		Variable Rate Series 1996C due 2026			24,000				24,000
		Variable Rate Series 2000 due 2027			4,360				4,360
			Total pollution control revenue bonds		170,460				170,460

	American Falls bond guarantee				19,885				19,885
	Milner Dam note guarantee				11,700				11,700
	Unamortized premium/discount - net				(3,382)				(3,135)

			Total long-term debt		983,663		52		923,910		50

Total Capitalization				$	1,904,925		100	$	1,842,616		100

The accompanying notes are an integral part of these statements.

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

				Nine Months Ended
				September 30,
				2005		2004
				(thousands of dollars)
Operating Activities:
	Net income			$	55,354	$	56,049
	Adjustments to reconcile net income to net cash provided by
		operating activities:
		Impairment of long-lived assets			-		9,756
		Depreciation and amortization			80,917		83,455
		Deferred taxes and investment tax credits			(8,406)		(28,599)
		Changes in regulatory assets and liabilities			2,974		26,645
		Undistributed earnings of equity method investment			(10,982)		1,696
		Change in:
			Accounts receivables and prepayments		2,918		(3,613)
			Accounts payable		(29,768)		6,371
			Taxes accrued		24,801		(6,596)
			Other current assets		(3,192)		(142)
			Other current liabilities		9,986		6,587
		Other assets			(4,760)		(7,932)
		Other liabilities			6,340		9,851
			Net cash provided by operating activities		126,182		153,528

Investing Activities:
	Additions to utility plant				(127,983)		(136,660)
	Purchase of available-for-sale securities				(81,693)		(11,185)
	Sale of available-for-sale securities				116,078		13,105
	Other assets				532		408
	Other liabilities				-		(1,545)
		Net cash used in investing activities			(93,066)		(135,877)

Financing Activities:
	Issuance of long-term debt				60,000		105,000
	Retirement of long-term debt				(60,000)		(51,105)
	Retirement of preferred stock				-		(52,220)
	Dividends on common stock				(38,001)		(34,668)
	Dividends on preferred stock				-		(4,823)
	Increase in short-term borrowings				-		21,600
	Other non-current assets				(4,389)		-
		Net cash used in financing activities			(42,390)		(16,216)

Net increase (decrease) in cash and cash equivalents					(9,274)		1,435

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

Cash and cash equivalents at end of period				$	8,405	$	5,466

Supplemental Disclosure of Cash Flow Information:
	Cash paid during the period for:
		Income taxes paid to parent		$	27,244	$	39,816
		Interest (net of amount capitalized)		$	32,377	$	27,640
Non-cash financing activities:
	Dividends declared and payable			$	12,757	$	-

The accompanying notes are an integral part of these statements.

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

				Three Months Ended
				September 30,
				2005		2004
				(thousands of dollars)

Net Income				$	20,969	$	26,995

Other Comprehensive Income (Loss):
	Unrealized gains (losses) on securities:
		Unrealized holding gains (losses) arising during the period,
			net of tax of $196 and ($302)		214		(526)
		Reclassification adjustment for (gains) losses included
			in net income, net of tax of ($321) and ($228)		(500)		(355)
			Net unrealized gains (losses)		(286)		(881)

Total Comprehensive Income				$	20,683	$	26,114

				Nine Months Ended
				September 30,
				2005		2004
				(thousands of dollars)

Net Income				$	55,354	$	56,049

Other Comprehensive Income (Loss):
	Unrealized gains (losses) on securities:
		Unrealized holding gains (losses) arising during the period,
			net of tax of ($393) and ($18)		(929)		(56)
		Reclassification adjustment for (gains) losses included
			in net income, net of tax of ($714) and ($609)		(1,111)		(949)
			Net unrealized gains (losses)		(2,040)		(1,005)

Total Comprehensive Income				$	53,314	$	55,044

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). Therefore, the Notes to 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 whose principal operating subsidiary is IPC. IDACORP is exempt from registration as a public utility holding company pursuant to Section 3(a)(1) of the Public Utility Holding Company Act of 1935 (1935 Act). In addition, pursuant to Rule 2 of the General Rules and Regulations under the 1935 Act, IDACORP is exempt from all the provisions of the 1935 Act and rules thereunder, except for Section 9(a)(2) of the 1935 Act, which requires IDACORP to seek prior Securities and Exchange Commission approval to acquire securities of another public utility company. Under the Energy Policy Act of 2005, the 1935 Act has been repealed, effective February 8, 2006, with the FERC receiving increased authority over mergers and affiliate transactions involving public utilities and the FERC and state commissions receiving increased access to the books and records of holding company systems.

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

IDACORP's other operating subsidiaries include:

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

IdaTech, LLC - developer of integrated fuel cell systems;

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

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

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

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

Financial Statements
In the opinion of IDACORP and IPC, the accompanying unaudited condensed consolidated financial statements contain all adjustments necessary to present fairly their consolidated financial positions as of September 30, 2005, and consolidated results of operations for the three and nine months ended September 30, 2005 and 2004 and consolidated cash flows for the nine months ended September 30, 2005 and 2004. These financial statements do not contain the complete detail or footnote disclosure concerning accounting policies and other matters that would be included in full-year financial statements and therefore they should be read in conjunction with the audited consolidated financial statements included in IDACORP's and IPC's Annual Report on Form 10-K for the year ended December 31, 2004. The results of operations for the interim periods are not necessarily indicative of the results to be expected for the full year.

Earnings Per Share
The computation of diluted earnings per share (EPS) differs from basic EPS only due to the inclusion of immaterial amounts of potentially dilutive shares related to stock-based compensation awards. The diluted EPS computation excluded 824,500 and 1,014,437 common stock options for the three and nine months ended September 30, 2005, respectively, because the options' exercise prices were greater than the average market price of the common stock during the period. For the same periods in 2004, there were 823,000 options excluded from the diluted EPS calculation for the same reason. In total, 1,438,314 options were outstanding at September 30, 2005, with expiration dates between 2010 and 2015.

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

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

			Three Months Ended				Nine Months Ended
			September 30,				September 30,
			2005		2004		2005		2004
IDACORP:
Net income, as reported			$	23,617	$	26,067	$	56,135	$	58,717
Add: Stock-based employee compensation
	expense included in reported net income,
	net of related tax effects			275		60		597		291
Deduct: Total stock-based employee
	compensation expense determined under
	fair value based method for all awards, net
	of related tax effects			495		207		1,250		864
		Pro forma net income	$	23,397	$	25,920	$	55,482	$	58,144
EPS of common stock:
	Basic and diluted - as reported		$	0.56	$	0.68	$	1.33	$	1.54
	Basic and diluted - pro forma			0.55		0.68		1.31		1.52

IPC:
Net income, as reported			$	20,969	$	26,995	$	55,354	$	56,049
Add: Stock-based employee compensation
	expense included in reported net income,
	net of related tax effects			167		34		311		217
Deduct: Total stock-based employee
	compensation expense determined under
	fair value based method for all awards, net
	of related tax effects			313		190		660		733
		Pro forma net income	$	20,823	$	26,839	$	55,005	$	55,533

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

Reclassifications
Certain items previously reported for periods prior to September 30, 2005 have been reclassified to conform to the current period's presentation. Net income and shareholders' equity were not affected by these reclassifications.

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

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

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

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

SFAS 154: In May 2005 the FASB issued SFAS 154, "Accounting Changes and Error Corrections - a replacement of APB Opinion No. 20 and FASB Statement No. 3." SFAS 154 changes the requirements for the accounting for and reporting of a change in accounting principle. It applies to all voluntary changes in accounting principle and to changes required by an accounting pronouncement that does not include specific transition provisions. When a pronouncement includes specific transition provisions, those provisions should be followed. SFAS 154 requires retrospective application to prior periods' financial statements of changes in accounting principle, unless it is impracticable to determine either the period-specific effects or the cumulative effect of the change. When it is impracticable to determine the period-specific effects of an accounting change on one or more individual prior periods presented, SFAS 154 requires that the new accounting principle be applied to the balances of assets and liabilities as of the beginning of the earliest period for which retrospective application is practicable and that a corresponding adjustment be made to the opening balance of retained earnings for that period rather than being reported in an income statement. When it is impracticable to determine the cumulative effect of applying a change in accounting principle to all prior periods, SFAS 154 requires that the new accounting principle be applied as if it were adopted prospectively from the earliest date practicable. SFAS 154, which is effective for accounting changes and corrections of errors made in fiscal years beginning after December 15, 2005, is not expected to have a material effect on IDACORP's or IPC's financial statements.

FSP FAS 109-1: On December 21, 2004, the FASB issued FSP FAS 109-1, "Application of FASB Statement No. 109, 'Accounting for Income Taxes', to the Tax Deduction on Qualified Production Activities Provided by the American Jobs Creation Act of 2004." The American Jobs Creation Act of 2004 (the Act) created Section 199 of the Internal Revenue Code entitled "Income Attributable to Domestic Production Activities." Effective for tax years beginning after December 31, 2004, Section 199 provides for a tax deduction related to domestic manufacturing activities of up to nine percent (when fully phased-in) of the lesser of "qualified production activities income" or taxable income. Under the statute, the production of electricity, excluding transmission and distribution, is considered a domestic manufacturing activity. On October 20, 2005, the Treasury Department released proposed regulations for Section 199.

The FASB concluded that the deduction should be accounted for as a special deduction in accordance with SFAS No. 109, "Accounting for Income Taxes." The estimated 2005 Section 199 tax deduction currently recorded does not have a significant impact on the financial statements of IDACORP or IPC.

FIN 47: In March 2005 the FASB issued Interpretation (FIN) 47, "Accounting for Conditional Asset Retirement Obligations." FIN 47 clarifies that the term "conditional asset retirement obligation" as used in SFAS 143, "Accounting for Asset Retirement Obligations," refers to a legal obligation to perform an asset retirement activity in which the timing and/or method of settlement are conditional on a future event that may or may not be within the control of the entity. FIN 47 clarifies that uncertainty about the timing and/or method of settlement of a conditional asset retirement obligation should be factored into the measurement of the liability when sufficient information exists to make a reasonable estimate of the fair value of the obligation. FIN 47 also provides guidance on when an entity would have sufficient information to recognize a liability and indicators that would preclude an entity from recognizing a liability for such obligations. FIN 47 will be effective no later than the end of fiscal years ending after December 15, 2005. IDACORP and IPC are currently reviewing the provisions of FIN 47 to determine its effect on their financial statements.

2. INCOME TAXES:

Income Tax Rate
In accordance with interim reporting requirements, IDACORP and IPC use an estimated annual effective tax rate for computing their provisions for income taxes on an interim basis. IDACORP's effective rate for the nine months ended September 30, 2005 was 14.1 percent, compared to (50.0) percent for the nine months ended September 30, 2004. IPC's effective tax rate for the nine months ended September 30, 2005 was 40.9 percent, compared to (1.0) percent for the nine months ended September 30, 2004.

During the third quarter IPC recorded additional income tax expense of $2 million related to the reversal of its previously accrued 2005 tax deduction for capitalized overhead costs. Recently released treasury regulations have negatively impacted IPC's continued use of that tax method. The reversal of the capitalized overhead deduction coupled with changes in other flow-through tax adjustments at IPC have increased IDACORP and IPC's 2005 effective income tax rates over prior quarters. For the nine months ended September 30, 2004, IDACORP and IPC's income tax expense was positively impacted by the reversal of a regulatory tax liability, the capitalized overhead tax deduction, and settlement of prior tax audits.

Status of Audit Proceedings
In March 2005, the Internal Revenue Service (IRS) began its examination of IDACORP's 2001 through 2003 tax years. On October 24, 2005, the Idaho State Tax Commission 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.

With the exception of the capitalized overhead cost method, discussed below, management cannot predict with certainty which financial accounts or tax adjustments will be chosen by the IRS for examination. IDACORP intends to vigorously defend its tax positions. It is possible that material differences in actual outcomes, costs and exposures relative to current estimates, or material changes in such estimates, could have a material adverse effect on IDACORP's and IPC's consolidated financial position, results of operations, or cash flows.

Capitalized Overhead Costs: On August 2, 2005, the IRS and 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 do the current treasury regulations.

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 adopted 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 2004 and prior open tax years, if IPC cannot satisfy the new guidance as currently drafted, IPC would be required to use another method of uniform capitalization, which could be more or 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 tax year and, as drafted, will preclude IPC from using this method for self-constructed assets for 2005 and thereafter. Accordingly, in the third quarter, IPC reversed its previously accrued 2005 tax deduction for capitalized overhead costs for both financial reporting and estimated tax payment purposes. IPC is evaluating alternatives for a new uniform capitalization method.

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 2005 or prior tax years.

Accounting for Uncertain Tax Positions
On July 14, 2005, the FASB released an Exposure Draft of its proposed Interpretation clarifying accounting for uncertain tax positions in accordance with FASB Statement No. 109, "Accounting for Income Taxes." The proposed guidance addresses the recognition, measurement, classification, and disclosure issues related to the recording of financial statement benefits for income tax positions that have some degree of uncertainty.

In October the FASB announced that it has moved its projected issuance date of the final standard to the first quarter of 2006. Management is unable to predict the final action by FASB, but is continuing to assess the provisions of this proposed Interpretation.

3. COMMON STOCK:

During the nine months ended September 30, 2005, IDACORP entered into the following transactions involving its common stock:

62,983 original issue shares were granted to participants in the 2000 Long-Term Incentive and Compensation Program;

124,537 original issue shares were issued under the Dividend Reinvestment and Stock Purchase Plan and the Employee Savings Plan;

11,925 shares were purchased on the open market and granted to non-employee IDACORP and IPC directors as part of their compensation; and

21,510 shares issued in 2001 as contingent payment to the shareholders of an acquired business were forfeited back to IDACORP.

4. FINANCING:

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

				September 30,		December 31,
				2005		2004
First mortgage bonds:
	5.83% Series due 2005			$	-	$	60,000
	7.38% Series due 2007				80,000		80,000
	7.20% Series due 2009				80,000		80,000
	6.60% Series due 2011				120,000		120,000
	4.75% Series due 2012				100,000		100,000
	4.25% Series due 2013				70,000		70,000
	6% Series due 2032				100,000		100,000
	5.50% Series due 2033				70,000		70,000
	5.50% Series due 2034				50,000		50,000
	5.875% Series due 2034				55,000		55,000
	5.30% Series due 2035				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					(3,381)		(3,135)
Debt related to investments in affordable housing					55,329		66,310
Other subsidiary debt					7,740		7,932
	Total				1,046,733		1,058,152
Current maturities of long-term debt					(17,851)		(78,603)

			Total long-term debt	$	1,028,882	$	979,549

(a)		Humboldt County Pollution Control Revenue bonds are secured by first mortgage bonds, bringing the total first
		mortgage bonds outstanding at September 30, 2005 to $834.8 million.

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

On August 26, 2005, IPC issued $60 million of its 5.30% First Mortgage Bonds due 2035, Secured Medium-Term Notes, Series F. The proceeds of this issuance were used to repay the $60 million, 5.83% First Mortgage Bonds that matured on September 9, 2005.

On August 30, 2005, IPC settled a forward-starting interest rate swap agreement by making a payment of $2.7 million to the counterparty of the agreement. In accordance with regulatory accounting practices under SFAS No. 71, IPC is amortizing this amount over the life of the 5.30% First Mortgage Bonds due 2035.

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 September 30, 2005, IPC could issue under the mortgage approximately $452 million of additional first mortgage bonds based on retired first mortgage bonds and $547 million of additional first mortgage bonds based on unfunded property additions. As of September 30, 2005, unfunded property additions were approximately $912 million. Property additions consist of electric or gas property, or property used in connection therewith. Property additions exclude securities, contracts or choses in action, merchandise and equipment for consumption or resale, materials and supplies, property used principally for production or gathering of natural gas, or any power sites and uncompleted works under Idaho state permits. In determining net property additions, IPC deducts all retired funded property from gross property additions except to the extent of certain credits for released funded property.

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

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

At September 30, 2005, IFS had $55 million of debt related to investments in affordable housing with interest rates ranging from 3.65 percent to 8.59 percent, due between 2005 and 2010. The investments in affordable housing developments that collateralize this debt had a net book value of $103 million at September 30, 2005. IFS's $16 million Series 2003-1 tax credit note is non-recourse to both IFS and IDACORP. The $9 million Series 2003-2 tax credit note and other outstanding debt are recourse only to IFS.

Credit Facilities
On May 3, 2005, IDACORP entered into a $150 million five-year credit agreement with various lenders. The new IDACORP facility replaced IDACORP's three-year $150 million credit agreement that would have expired on March 16, 2007. The IDACORP facility, which will be used for general corporate purposes and commercial paper back-up, will terminate on March 31, 2010. At September 30, 2005, no loans were outstanding on IDACORP's credit facility and $56 million of commercial paper was outstanding.

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

At September 30, 2005, IPC had regulatory authority to incur up to $250 million of short-term indebtedness. On May 3, 2005, IPC entered into a $200 million five-year credit agreement with various lenders. The new IPC facility replaced IPC's three-year $200 million credit agreement that would have expired on March 16, 2007. The new IPC facility, which expires on March 31, 2010, will be used for general corporate purposes and commercial paper back-up. At September 30, 2005, no loans were outstanding on IPC's credit facility and no commercial paper was outstanding.

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

5. COMMITMENTS AND CONTINGENCIES:

Off-Balance Sheet Arrangements
The federal Surface Mining Control and Reclamation Act of 1977 and similar state statutes establish operational, reclamation and closure standards that must be met during and upon completion of mining activities. These obligations mandate that mine property be restored consistent with specific standards and the approved reclamation plan. The mining operations at the Bridger Coal Company are subject to these reclamation and closure requirements. IPC has agreed to guarantee the performance of reclamation activities at Bridger Coal Company, of which Idaho Energy Resources Co., a subsidiary of IPC, owns a one-third interest. This guarantee, which is renewed each December, was $60 million at September 30, 2005. Bridger Coal has a reclamation trust fund set aside specifically for the purpose of paying these reclamation costs and expects that the fund will be sufficient to cover all such costs. Because of the existence of the fund, the estimated fair value of this guarantee is minimal.

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

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

Alves Dairy: On May 18, 2004, Herculano and Frances Alves, dairy operators from Twin Falls, Idaho, brought suit against IPC in Idaho State District Court, Fifth Judicial District, Twin Falls County. The plaintiffs sought unspecified monetary damages for negligence and nuisance (allegedly allowing electrical current to flow in the earth, injuring the plaintiffs' right to use and enjoy their property and adversely affecting their dairy herd). On July 16, 2004, IPC filed an answer to Mr. and Mrs. Alves' complaint, denying all liability to the plaintiffs, and asserting certain affirmative defenses.

On June 30, 2005, the case was dismissed, with prejudice, pursuant to an agreed resolution of the matter by the plaintiffs and IPC. The amounts payable by IPC pursuant to the resolution, less a deductible, were covered by insurance and did not have a material adverse effect on IDACORP's or IPC's consolidated financial position, results of operations, or cash flows.

Public Utility District No. 1 of Grays Harbor County, Washington: On October 15, 2002, Public Utility District No. 1 of Grays Harbor County, Washington (Grays Harbor) filed a lawsuit in the Superior Court of the State of Washington, for the County of Grays Harbor, against IDACORP, IPC and IE. On March 9, 2001, Grays Harbor entered into a 20 megawatt (MW) purchase transaction with IPC for the purchase of electric power from October 1, 2001 through March 31, 2002, at a rate of $249 per megawatt-hour (MWh). In June 2001, with the consent of Grays Harbor, IPC assigned all of its rights and obligations under the contract to IE. In its lawsuit, Grays Harbor alleged that the assignment was void and unenforceable, and sought restitution from IE and IDACORP, or in the alternative, Grays Harbor alleged that the contract should be rescinded or reformed. Grays Harbor sought as damages an amount equal to the difference between $249 per MWh and the "fair value" of electric power delivered by IE during the period October 1, 2001 through March 31, 2002.

IDACORP, IPC and IE removed this action from the state court to the U.S. District Court for the Western District of Washington at Tacoma. On November 12, 2002, the companies filed a motion to dismiss Grays Harbor's complaint, asserting that the U.S. District Court lacked jurisdiction because the FERC has exclusive jurisdiction over wholesale power transactions and thus the matter is preempted under the Federal Power Act and barred by the filed-rate doctrine. The court ruled in favor of the companies' motion to dismiss and dismissed the case with prejudice on January 28, 2003. On February 25, 2003, Grays Harbor filed a Notice of Appeal, appealing the final judgment of dismissal to the U.S. Court of Appeals for the Ninth Circuit. On August 10, 2004, the Ninth Circuit affirmed the dismissal of Grays Harbor's complaint, finding that Grays Harbor's claims were preempted by federal law and were barred by the filed-rate doctrine. The court also remanded the case to allow Grays Harbor leave to amend its complaint to seek declaratory relief only as to contract formation, and held that Grays Harbor could seek monetary relief, if at all, only from the FERC, and not from the courts. IDACORP, IPC and IE sought rehearing from the Ninth Circuit arguing that the court erred in granting leave to amend the complaint as such a declaratory relief claim would be preempted and would be barred by the filed-rate doctrine. The Ninth Circuit denied the rehearing request on October 25, 2004, and the decision became final on November 12, 2004. On that same date, the companies took steps to have the case transferred and consolidated with other similar cases arising out of the California energy crisis currently pending before the Honorable Robert H. Whaley, sitting by designation in the Southern District of California and presiding over Multidistrict Litigation Docket No. 1405, regarding California Wholesale Electricity Antitrust Litigation. On November 18, 2004, Grays Harbor filed an amended complaint alleging that the contract was formed under circumstances of "mistake" as to an "artificial . . . power shortage." Grays Harbor asked that the contract therefore be declared "unenforceable" and found "unconscionable." On December 23, 2004, the Judicial Panel on Multidistrict Litigation conditionally transferred the case to Judge Whaley. Grays Harbor sought to vacate the transfer; however, on April 18, 2005, the Judicial Panel on Multidistrict Litigation ordered the case transferred. On May 18, 2005, IDACORP, IPC and IE filed a motion to dismiss the amended complaint. The motion was heard on September 29, 2005. The court has not yet ruled on the motion. The companies intend to vigorously defend their position and believe this matter will not have a material adverse effect on their consolidated financial positions, results of operations, or cash flows.

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

All defendants, including IPC and IDACORP, moved to dismiss the complaint in lieu of answering it. The motions were based on the ground that the complaint seeks to set alternative electrical rates, which are exclusively within the jurisdiction of the FERC and are barred by the filed-rate doctrine. A hearing on the motion to dismiss was heard on March 26, 2004. On May 28, 2004, the court granted IPC's and IDACORP's motion to dismiss. In June 2004, the Port of Seattle appealed the court's decision to the U.S. Court of Appeals for the Ninth Circuit. The appeal has been fully briefed; however, no date has yet been set for oral argument. Also, on July 19, 2005 the companies filed a motion for summary affirmance of the district court's order dismissing the Port of Seattle's complaint. The Ninth Circuit issued an order denying this motion on October 19, 2005. The companies intend to vigorously defend their position in this proceeding and believe this matter will not have a material adverse effect on their consolidated financial positions, results of operations or cash flows.

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

On September 8, 2004, this case was transferred and consolidated with other similar cases currently pending before the Honorable Robert H. Whaley.

The companies' motion to dismiss the complaint was granted on February 11, 2005. Wah Chang appealed to the Ninth Circuit on March 10, 2005. The Ninth Circuit set a briefing schedule on the appeal, requiring Wah Chang's opening brief to be filed by July 6, 2005. On May 18, 2005, Wah Chang filed a motion to stay the appeal or in the alternative to voluntarily dismiss the appeal without prejudice to reinstatement. The companies opposed the motion and filed a cross-motion asking the Court to summarily affirm the district court's order of dismissal. On July 8, 2005, the Ninth Circuit denied Wah Chang's motion and also denied the companies' motion for summary affirmance without prejudice to renewal following the filing of Wah Chang's opening brief. Wah Chang's opening brief was filed on September 21, 2005. On October 11, 2005 the companies, along with the other defendants, filed a motion to consolidate this appeal with Wah Chang v. Duke Energy Trading and Marketing currently pending before the Ninth Circuit. On October 20, 2005 the Ninth Circuit granted the motion to consolidate and established a revised briefing schedule. The companies' answering brief is due November 30, 2005 and Wah Chang's optional reply brief is due December 16, 2005. The companies intend to vigorously defend their position in this proceeding and believe this matter will not have a material adverse effect on their consolidated financial positions, results of operations or cash flows.

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

On September 8, 2004, this case was transferred and consolidated with other similar cases currently pending before the Honorable Robert H. Whaley. The companies' motion to dismiss the complaint was granted on February 11, 2005. The City of Tacoma appealed to the Ninth Circuit on March 10, 2005. The City of Tacoma filed its opening brief on June 29, 2005. The companies and other defendants filed their opposition brief on August 9, 2005. The City of Tacoma moved for an extension of time within which to file its optional reply brief. The Court has not yet ruled on the City of Tacoma's motion for an extension of time, and the City of Tacoma has not yet filed a reply brief. Also on August 9, 2005, the companies moved for summary affirmance of the district court's order dismissing the City of Tacoma's complaint. The City of Tacoma filed a response to the companies' motion for summary affirmance on August 24, 2005. The Ninth Circuit has not yet ruled on the companies' motion for summary affirmance. The companies intend to vigorously defend their position in this proceeding and believe this matter will not have a material adverse effect on their consolidated financial positions, results of operations or cash flows.

Wholesale Electricity Antitrust Cases I & II: These cross-actions against IE and IPC emerged from multiple California state court proceedings first initiated in late 2000 against various power generators/marketers by various California municipalities and citizens. Suit was filed against entities including Reliant Energy Services, Inc., Reliant Ormond Beach, L.L.C., Reliant Energy Etiwanda, L.L.C., Reliant Energy Ellwood, L.L.C., Reliant Energy Mandalay, L.L.C. and Reliant Energy Coolwater, L.L.C. (collectively, Reliant); and Duke Energy Trading and Marketing, L.L.C., Duke Energy Morro Bay, L.L.C., Duke Energy Moss Landing, L.L.C., Duke Energy South Bay, L.L.C. and Duke Energy Oakland, L.L.C. (collectively, Duke). While varying in some particulars, these cases made a common claim that Reliant, Duke and certain others (not including IE or IPC) colluded to influence the price of electricity in the California wholesale electricity market. The plaintiffs asserted various claims that the defendants violated the California Antitrust Law (the Cartwright Act), Business and Professions Code Section 16720 and California's Unfair Competition Law, Business and Professions Code Section 17200. Among the acts complained of are bid rigging, information exchanges, withholding of power and other wrongful acts. These actions were subsequently consolidated, resulting in the filing of Plaintiffs' Master Complaint in San Diego Superior Court on March 8, 2002.

On April 22, 2002, more than a year after the initial complaints were filed, two of the original defendants, Duke and Reliant, filed separate cross-complaints against IPC and IE, and approximately 30 other cross-defendants. Duke and Reliant's cross-complaints seek indemnity from IPC, IE and the other cross-defendants for an unspecified share of any amounts they must pay in the underlying suits because, they allege, other market participants like IPC and IE engaged in the same conduct at issue in the Plaintiffs' Master Complaint. Duke and Reliant also seek declaratory relief as to the respective liability and conduct of each of the cross-defendants in the actions alleged in the Plaintiffs' Master Complaint. Reliant also asserted a claim against IPC for alleged violations of the California Unfair Competition Law, Business and Professions Code Section 17200. As a buyer of electricity in California, Reliant seeks the same relief from the cross-defendants, including IPC, as that sought by plaintiffs in the Plaintiffs' Master Complaint as to any power Reliant purchased through the California markets.

Some of the newly added defendants (foreign citizens and federal agencies) removed that litigation to federal court. IPC and IE, together with numerous other defendants added by the cross-complaints, have moved to dismiss these claims, and those motions were heard in September 2002, together with motions to remand the case back to state court filed by the original plaintiffs. On December 13, 2002, the U.S. District Court granted Plaintiffs' Motion to Remand to state court, but did not issue a ruling on IPC and IE's motion to dismiss. The U.S. Court of Appeals for the Ninth Circuit granted certain Defendants and Cross-Defendants' Motions to Stay the Remand Order while they appeal the order. The briefing on the appeal was completed in December 2003. On December 8, 2004, the Ninth Circuit issued its opinion in People of California v. NRG Energy, Inc., et al., which affirmed the district court's remand of these cases to state court and dismissed certain federal government defendants due to their sovereign immunity from suit.

On March 10, 2005, the Ninth Circuit's mandate, remanding People of California v. NRG Energy, Inc. to state court was issued. On March 15, 2005, however, cross-defendant, Powerex Corp., filed a motion to recall mandate until a petition for certiorari seeking review of this case by the U.S. Supreme Court is filed and ruled upon by the Supreme Court. On April 6, 2005, the Ninth Circuit denied Powerex Corp.'s motion to recall mandate, and the case has been remanded to state court. On July 15, 2005, Powerex Corp. filed a petition for certiorari with the U.S. Supreme Court, which is currently pending.

On June 3, 2005, the cross-defendants, including IPC and IE, filed a demurrer in state court seeking to dismiss the action. On August 8, 2005, the Clerk of the Court entered Duke's voluntary dismissal, with prejudice, of the cross-complaint against IE. Reliant's cross-complaint against IPC, however, is still pending. Further briefing and hearing on IPC's demurrer was stayed pending the outcome of the demurrer filed by Reliant on the Master Complaint. On September 22, 2005, the Court took Reliant's demurrer off calendar pending approval of a proposed settlement as to the plaintiff's Master Complaint. In light of Reliant's proposed settlement, the court ordered the parties to meet and confer regarding the status of Reliant's cross-complaint. Negotiations are ongoing. On October 3, 2005 the court sustained the defendants' joint demurrer to the Master Complaint and scheduled a status conference to discuss the status of the cross-complaints. On October 13, 2005 the court set the companies' demurrer on the cross-complaint for hearing on December 23, 2005. The companies intend to vigorously defend their position and believe these matters will not have a material adverse effect on their consolidated financial positions, results of operations or cash flows.

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

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

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

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

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

The FERC issued an order on April 6, 2001 requiring the CalPX to rescind all chargeback actions related to Pacific Gas and Electric Company's and Southern California Edison's liabilities. Shortly after the issuance of that order, the CalPX segregated the CalPX chargeback amounts it had collected in a separate account. The CalPX claimed it was awaiting further orders from the FERC and the bankruptcy court before distributing the funds that it collected under its chargeback tariff mechanism. On October 7, 2004, the FERC issued an order determining that it would not require the disbursement of chargeback funds until the completion of the California refund proceedings. On November 8, 2004, IE, along with a number of other parties, sought rehearing of that order. On March 15, 2005, the FERC issued an order on rehearing confirming that the CalPX is to continue to hold the chargeback funds, but solely to offset seller-specific shortfalls in the seller's CalPX account at the conclusion of the California refund proceeding. Balances are to be returned to the respective sellers at the conclusion of a seller's participation in the refund proceeding. Powerex Corp. filed a petition for review of the Commission's order on March 24, 2005 in the D.C. Circuit. Neither a briefing schedule nor a date for oral argument has been set.

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

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

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

The FERC issued its Order on Proposed Findings on Refund Liability on March 26, 2003. In large part, the FERC affirmed the recommendations of its Administrative Law Judge. However, the FERC changed a component of the formula the Administrative Law Judge was to apply when it adopted findings of its staff that published California spot market prices for gas did not reliably reflect the prices a gas market, that had not been manipulated, would have produced, despite the fact that many gas buyers paid those amounts. The findings of the Administrative Law Judge, as adjusted by the FERC's March 26, 2003 order, are expected to increase the offsets to amounts still owed by the Cal ISO and the CalPX to the companies. Calculations remain uncertain because (1) the FERC has required the Cal ISO to correct a number of defects in its calculations, (2) it is unclear what, if any, effect the ruling of the Ninth Circuit in Bonneville Power Administration v. FERC, described below, might have on the ISO's calculations, and (3) the FERC has stated that if refunds will prevent a seller from recovering its California portfolio costs during the Refund Period, it will provide an opportunity for a cost showing by such a respondent. On August 8, 2005, the FERC issued an Order establishing the framework for filings by sellers who elected to make such a cost showing. On September 14, 2005 IE and IPC made a joint cost filing, as did approximately thirty other sellers. On October 11, 2005, the California entities filed comments on the companies' cost filing and those made by other parties. IPC and IE submitted reply comments on October 19, 2005. The California entities filed supplemental comments on October 24, 2005 and IPC and IE filed supplemental reply comments on October 27, 2005. IPC and IE are unsure of the impact the FERC's rulings will have on the refunds due from California. However, as to potential refunds, if any, IPC and IE believe their exposure is likely to be offset by amounts due from California entities.

IE, along with a number of other parties, filed an application with the FERC on April 25, 2003 seeking rehearing of the March 26, 2003 order. On October 16, 2003, the FERC issued two orders denying rehearing of most contentions that had been advanced and directing the Cal ISO to prepare its compliance filing calculating revised Mitigated Market Clearing Prices and refund amounts within five months. The Cal ISO has since, on a number of occasions, requested additional time to complete its compliance filings. This Cal ISO compliance filing has been delayed until at least March 2006. The Cal ISO is required to update the FERC on its progress monthly.

On December 2, 2003, IE petitioned the U.S. Court of Appeals for the Ninth Circuit for review of the FERC's orders, and since that time, dozens of other petitions for review have been filed. The Ninth Circuit consolidated IE's and the other parties' petitions with the petitions for review arising from earlier FERC orders in this proceeding, bringing the total number of consolidated petitions to more than 100. The Ninth Circuit held the appeals in abeyance pending the disposition of the market manipulation claims discussed below and the development of a comprehensive plan to brief this complicated case. Certain parties also sought further rehearing and clarification before the FERC. On September 21, 2004, the Ninth Circuit convened case management proceedings, a procedure reserved to help organize complex cases. On October 22, 2004, the Ninth Circuit severed a subset of the stayed appeals in order that briefing could commence regarding cases 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 transactions are subject to refunds. Oral argument was held on April 12-13, 2005. On September 6, 2005 the Ninth Circuit issued its decision in one of the severed cases, Bonneville Power Administration v. FERC. In that decision, the Ninth Circuit concluded that the FERC lacked refund authority over wholesale electric energy sales made by governmental entities and non-public utilities. The time for requests for rehearing was to expire on October 21, 2005, but has been extended until 45 days after the Ninth Circuit issues its decision in the other severed cases. The companies cannot predict whether rehearing will be sought and, if sought, whether it will be granted or what action the FERC might take if the matter is remanded.

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

In June 2001, IPC transferred its non-utility wholesale electricity marketing operations to IE. Effective with this transfer, the outstanding receivables and payables with the CalPX and the Cal ISO were assigned from IPC to IE. At September 30, 2005, with respect to the CalPX chargeback and the California refund proceedings discussed above, the CalPX and the Cal ISO owed $14 million and $30 million, respectively, for energy sales made to them by IPC in November and December 2000. IE has accrued a reserve of $42 million against these receivables. This reserve was calculated taking into account the uncertainty of collection given the California energy situation. Based on the reserve recorded as of September 30, 2005, IDACORP believes that the future collectibility of these receivables or any potential refunds ordered by the FERC would not have a material adverse effect on its consolidated financial position, results of operations or cash flows.

On March 20, 2002, the California Attorney General filed a complaint with the FERC against various sellers in the wholesale power market, including IE and IPC, alleging that the FERC's market-based rate requirements violate the Federal Power Act, and, even if the market-based rate requirements are valid, that the quarterly transaction reports filed by sellers do not contain the transaction-specific information mandated by the Federal Power Act and the FERC. The complaint stated that refunds for amounts charged between market-based rates and cost-based rates should be ordered. The FERC denied the challenge to market-based rates and refused to order refunds, but did require sellers, including IE and IPC, to refile their quarterly reports to include transaction-specific data. The Attorney General appealed the FERC's decision to the U.S. Court of Appeals for the Ninth Circuit. The Attorney General contends that the failure of all market-based rate authority sellers of power to have rates on file with the FERC in advance of sales is impermissible. The Ninth Circuit issued its decision on September 9, 2004, concluding that market-based tariffs are permissible under the Federal Power Act, but remanded the matter to the FERC to consider whether the FERC should exercise remedial power (including some form of refunds) when a market participant failed to submit reports that the FERC relies on to confirm the justness and reasonableness of rates charged. Certain parties to the litigation have sought rehearing. The companies cannot predict whether rehearing will be granted or what action the FERC might take if the matter is remanded.

On May 26, 2005 the California Parties filed a motion to lodge additional evidence, primarily audiotapes produced by Enron employees, in the California Refund Proceedings in Docket No. EL00-95. A number of parties, including IDACORP, answered in opposition to that motion.

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

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

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

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

On June 25, 2003, the FERC ordered over 50 entities that participated in the western wholesale power markets between January 1, 2000 and June 20, 2001, including IPC, to show cause why certain trading practices did not constitute gaming or anomalous market behavior in violation of the Cal ISO and the CalPX Tariffs. The Cal ISO was ordered to provide data on each entity's trading practices within 21 days of the order, and each entity was to respond explaining their trading practices within 45 days of receipt of the Cal ISO data. IPC submitted its responses to the show cause orders on September 2 and 4, 2003. On October 16, 2003, IPC reached agreement with the FERC Staff on the two orders commonly referred to as the "gaming" and "partnership" show cause orders. Regarding the gaming order, the FERC Staff determined it had no basis to proceed with allegations of false imports and paper trading and IPC agreed to pay $83,373 to settle allegations of circular scheduling. IPC believed that it had defenses to the circular scheduling allegation but determined that the cost of settlement was less than the cost of litigation. In the settlement, IPC did not admit any wrongdoing or violation of any law. With respect to the "partnership" order, the FERC Staff submitted a motion to the FERC to dismiss the proceeding because materials submitted by IPC demonstrated that IPC did not use its "parking" and "lending" arrangement with Public Service Company of New Mexico to engage in "gaming" or anomalous market behavior ("partnership"). The "gaming" settlement was approved by the FERC on March 3, 2004. Eight parties have requested rehearing of the FERC's March 3, 2004 order, but the FERC has not yet acted on those requests. The motion to dismiss the "partnership" proceeding was approved by the FERC in an order issued on January 23, 2004 and rehearing of that order was not sought within the time allowed by statute. Some of the California Parties and other parties have petitioned the U.S. Court of Appeals for the Ninth Circuit and the District of Columbia Circuit for review of the FERC's orders initiating the show cause proceedings. Some of the parties contend that the scope of the proceedings initiated by the FERC was too narrow. Other parties contend that the orders initiating the show cause proceedings were impermissible. Under the rules for multidistrict litigation, a lottery was held and although these cases were to be considered in the District of Columbia Circuit by order of February 10, 2005, the District of Columbia Circuit transferred the proceedings to the Ninth Circuit. The FERC had moved the District of Columbia Circuit to dismiss these petitions on the grounds of prematurity and lack of ripeness and finality. The transfer order was issued before a ruling from the District of Columbia Circuit and the motions, if renewed, will be considered by the Ninth Circuit. IPC is not able to predict the outcome of the judicial determination of these issues.

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

Pacific Northwest Refund:
On July 25, 2001, the FERC issued an order establishing another proceeding to explore whether there may have been unjust and unreasonable charges for spot market sales in the Pacific Northwest during the period December 25, 2000 through June 20, 2001. The FERC Administrative Law Judge submitted recommendations and findings to the FERC on September 24, 2001. The Administrative Law Judge found that prices should be governed by the Mobile-Sierra standard of the public interest rather than the just and reasonable standard, that the Pacific Northwest spot markets were competitive and that no refunds should be allowed. Procedurally, the Administrative Law Judge's decision is a recommendation to the commissioners of the FERC. Multiple parties submitted comments to the FERC with respect to the Administrative Law Judge's recommendations. The Administrative Law Judge's recommended findings had been pending before the FERC, when at the request of the City of Tacoma and the Port of Seattle on December 19, 2002, the FERC reopened the proceedings to allow the submission of additional evidence related to alleged manipulation of the power market by Enron and others. As was the case in the California refund proceeding, at the conclusion of the discovery period, parties alleging market manipulation were to submit their claims to the FERC and responses were due on March 20, 2003. Grays Harbor, whose civil litigation claims were dismissed, as noted above, intervened in this FERC proceeding, asserting on March 3, 2003 that its six-month forward contract, for which performance had been completed, should be treated as a spot market contract for purposes of the FERC's consideration of refunds and is requesting refunds from IPC of $5 million. Grays Harbor did not suggest that there was any misconduct by IPC or IE. The companies submitted responsive testimony defending vigorously against Grays Harbor's refund claims.

In addition, the Port of Seattle, the City of Tacoma and the City of Seattle made filings with the FERC on March 3, 2003 claiming that because some market participants drove prices up throughout the west through acts of manipulation, prices for contracts throughout the Pacific Northwest market should be re-set starting in May 2000 using the same factors the FERC would use for California markets. Although the majority of these claims are generic, they named a number of power market suppliers, including IPC and IE, as having used parking services provided by other parties under FERC-approved tariffs and thus as being candidates for claims of improperly having received congestion revenues from the Cal ISO. On June 25, 2003, after having considered oral argument held earlier in the month, the FERC issued its Order Granting Rehearing, Denying Request to Withdraw Complaint and Terminating Proceeding, in which it terminated the proceeding and denied claims that refunds should be paid. The FERC denied rehearing on November 10, 2003, triggering the right to file for review. The Port of Seattle, the City of Tacoma, the City of Seattle, the California Attorney General, the CPUC and Puget Sound Energy, Inc. filed petitions for review in the Ninth Circuit. These petitions have been consolidated. Grays Harbor did not file a petition for review, although it has sought to intervene in the proceedings initiated by the petitions of others. On July 21, 2004, the City of Seattle submitted to the Ninth Circuit in the Pacific Northwest refund petition for review a motion requesting leave to offer additional evidence before the FERC in order to try to secure another opportunity for reconsideration by the FERC of its earlier rulings. The evidence that the City of Seattle seeks to introduce before the FERC consisted of audio tapes of what purports to be Enron trader conversations containing inflammatory language that have been the subject of coverage in the press. Under Section 313(b) of the Federal Power Act, a court is empowered to direct the introduction of additional evidence if it is material and could not have been introduced during the underlying proceeding. On September 29, 2004, the Ninth Circuit denied the City of Seattle's motion for leave to adduce evidence, without prejudice to renewing the request for remand in the briefing in the Pacific Northwest refund case. Briefing was completed on May 25, 2005; however, no date has been set for oral argument.

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

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

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

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

On September 14, 2005, Magistrate Judge Mikel H. Williams of the U.S. District Court for the District of Idaho issued a Report and Recommendation that the defendants' motion to dismiss be granted and that the case be dismissed. The Magistrate Judge determined that the plaintiffs did not satisfactorily plead loss causation (i.e., a causal connection between the alleged material misrepresentation and the loss) in conformance with the standards set forth in the recent United States Supreme Court decision of Dura Pharmaceuticals, Inc. v. Broudo, 544 U.S._____, 125 S. Ct. 1627 (2005). The Magistrate Judge also concluded that it would be futile to afford the plaintiffs an opportunity to file an amended complaint because it did not appear that they could cure the deficiencies in their pleadings. The parties have each filed objections to different parts of the Magistrate Judge's Report and Recommendation, and the matter is now before the District Judge.

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

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

6. REGULATORY MATTERS:

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

Rate Case Tax Settlement: In 2003, IPC filed for a general rate increase that took effect June 1, 2004. A portion of that rate case involved IPC's income tax expense. Subsequent to last year's June 1 rate change, IPC asked the IPUC to reconsider that portion of the case and the IPUC granted an ongoing income tax-related adjustment, and a one-year income tax-related adjustment that began on June 1, 2005. Together, these tax related adjustments increased rates by $23 million, or 4.45 percent (2.25 percent for the ongoing portion and 2.2 percent for the one-year portion). The 2.2 percent portion is temporary and will expire on June 1, 2006.

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

Energy Efficiency Tariff Rider: IPC charges an amount to each customer to provide funding for energy efficiency initiatives. In December 2004, IPC filed a request to increase this charge from 0.5 percent of total base revenues to 1.5 percent effective June 1, 2005, and 2.4 percent effective June 1, 2007. The IPUC authorized the June 1, 2005 change while deferring judgment of the 2007 request. In its authorization, the IPUC established caps on the total monthly rider amount for the residential and irrigation classes. The June 1, 2005 change increases the amounts collected from customers by $5 million annually.

Oregon Rate Case
On September 21, 2004, IPC filed an application with the Oregon Public Utility Commission (OPUC) to increase general rates an average of 17.5 percent or approximately $4.4 million annually.

The OPUC issued its order on July 29, 2005 authorizing an increase of $597,000 in annual revenues, an average of 2.37 percent. The significant decrease from IPC's requested amount was primarily related to differences in net power supply costs, which reduced IPC's initial rate request of $4.4 million by $2.4 million.

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.

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

		September 30,		December 31,
		2005		2004
Idaho PCA current year:
	Deferral for the 2005-2006 rate year	$	-	$	22,778
	Deferral for the 2006-2007 rate year		2,163		-
Irrigation Lost Revenues			-		13,290
Idaho PCA true-up awaiting recovery:
	Authorized May 2004		-		11,415
	Authorized May 2005*		34,893		-
Oregon deferral:
	2001 costs		10,536		12,047
	2005 costs		2,068		-
	Total deferral	$	49,660	$	59,530

*$28 million will be recovered with interest during the 2006-2007 PCA rate year.

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

On April 15, 2005, IPC filed the 2005-2006 PCA with the IPUC with a proposed effective date of June 1, 2005. The application proposed to hold the PCA component of customers' rates at the existing level, which is currently recovering $71 million above base rates. By IPUC order, this year's PCA includes $12 million in lost revenues and $2 million in related interest resulting from IPC's Irrigation Load Reduction Program that was in place in 2001. IPC proposed to defer recovery of approximately $28 million of power supply costs, or 4.75 percent, for one year to help mitigate the impacts of the increases for the Bennett Mountain Power Plant and the rate case tax settlement adjustments, since all three were proposed to be effective June 1, 2005. The $28 million will be recovered during the 2006-2007 PCA rate year, and IPC will earn a two percent carrying charge on this balance. The IPUC accepted the company's PCA proposal.

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

Oregon: On March 2, 2005, IPC filed for an accounting order to defer net power supply costs for the period of March 1, 2005 through February 28, 2006 in anticipation of continued low water conditions. The forecasted net power supply costs included in this filing were $169 million, of which $3 million related to the Oregon jurisdiction. IPC is proposing to use the same methodology for this deferral filing that was accepted in 2002 for Oregon's share of IPC's 2001 net power supply expenses. 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.

Emission Allowances
In June 2005, IPC filed applications with the IPUC and OPUC requesting blanket authorization for the sale of excess sulfur dioxide emission allowances and an accounting order. The IPUC issued Order 29852 on August 22, 2005, authorizing the sale and interim accounting treatment. Pursuant to the Order, IPC is required to file a report with the IPUC within 60 days after receipt of any sale proceeds. The Order also stated that the IPUC Staff was to conduct workshops and make a recommendation as to the appropriate ratemaking treatment. The first workshop has been scheduled for November 7, 2005. 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. The OPUC also ordered IPC to file a report within 60 days after receipt of any sales proceeds and stated that ratemaking treatment of the proceeds will be determined in a ratemaking proceeding.

In October 2005, IPC sold 60,000 allowances (out of a total of approximately 107,000 excess allowances) for approximately $57 million (before income taxes and expenses) on the open market. IPC is now seeking approval from the IPUC for the accounting treatment of these transactions, which will determine the allocation of proceeds between retail customers and shareholders. Under the approved interim accounting treatment, IPC is recording the Idaho and Oregon allocated portions of the proceeds (net of income taxes and expenses) as a regulatory liability. At this time, IPC cannot predict the outcome of the IPUC workshops, or any future OPUC ratemaking proceeding relating to this issue, or how the proceeds might ultimately be allocated between retail customers and shareholders.

7. INDUSTRY SEGMENT INFORMATION:

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

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

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

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

		Utility										Consolidated
		Operations		IFS			Other			Eliminations		Total
Three months ended September 30, 2005:
	Revenues	$	244,232		$	343		$	4,567	$	-	$	249,142
	Net income (loss)		20,969			2,687			(39)		-		23,617

Total assets at September 30, 2005		$	2,992,233		$	143,772		$	264,011	$	(99,159)	$	3,300,857

Three months ended September 30, 2004:
	Revenues	$	241,188		$	1,006		$	4,483	$	-	$	246,677
	Net income (loss)		23,879			2,679			(491)		-		26,067

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

Nine months ended September 30, 2005:
	Revenues	$	634,807		$	1,032		$	14,956	$	-	$	650,795
	Net income (loss)		55,354			7,777			(6,996)		-		56,135

Nine months ended September 30, 2004:
	Revenues	$	631,701		$	1,006		$	14,031	$	-	$	646,738
	Net income (loss)		51,226			9,829			(2,338)		-		58,717

8. BENEFIT PLANS

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

						Deferred				Other
		Pension Plan				Compensation Plan				Benefits
		2005		2004		2005		2004		2005		2004
Service cost		$	3,282	$	2,950	$	292	$	340	$	331	$	354
Interest cost			5,282		5,105		538		578		804		1,005
Expected return on plan assets			(7,423)		(6,978)		-		-		(591)		(580)
Amortization of net obligation
	at transition		(32)		(66)		78		153		485		516
Amortization of prior service
	cost		193		193		57		(90)		(127)		(133)
Amortization of net loss			-		-		172		219		179		377
Net periodic benefit cost		$	1,302	$	1,204	$	1,137	$	1,200	$	1,081	$	1,539

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

						Deferred				Other
		Pension Plan				Compensation Plan				Benefits
		2005		2004		2005		2004		2005		2004
Service cost		$	9,846	$	8,858	$	877	$	1,019	$	1,044	$	1,046
Interest cost			15,844		15,331		1,613		1,734		2,536		2,969
Expected return on plan assets			(22,267)		(20,956)		-		-		(1,864)		(1,714)
Amortization of net obligation
	at transition		(94)		(197)		233		460		1,530		1,524
Amortization of prior service
	cost		578		578		171		(271)		(401)		(391)
Amortization of net loss			-		-		517		658		565		1,113
Net periodic benefit cost		$	3,907	$	3,614	$	3,411	$	3,600	$	3,410	$	4,547

IDACORP and IPC have not contributed and do not expect to contribute to their pension plan in 2005.

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

Regulations published on January 28, 2005 provided more flexibility in determining actuarial equivalence to Medicare of the benefits provided by the plan than was initially estimated by IDACORP's and IPC's actuaries. During the second quarter, IDACORP's and IPC's actuaries completed their determination that 2005 periodic postretirement benefit cost would be reduced by $1.5 million, which included a $0.9 million benefit related to the Medicare Act.

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 September 30, 2005, and the related condensed consolidated statements of income and comprehensive income for the three-month and nine-month periods ended September 30, 2005 and 2004, and the condensed consolidated statements of cash flows for the nine-month periods ended September 30, 2005 and 2004. These interim financial statements are the responsibility of the Company's management.

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

Based on our reviews, we are not aware of any material modifications that should be made to such 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, 2004, and the related consolidated statements of income, comprehensive income, shareholders' equity and cash flows for the year then ended (not presented herein); and in our report dated March 8, 2005, we expressed an unqualified opinion on those consolidated financial statements. In our opinion, the information set forth in the accompanying condensed consolidated balance sheet as of December 31, 2004 is fairly stated, in all material respects, in relation to the consolidated balance sheet from which it has been derived.

DELOITTE & TOUCHE LLP

Boise, Idaho
November 2, 2005

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

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

We have reviewed the accompanying condensed consolidated balance sheet and statement of capitalization of Idaho Power Company and subsidiary (the "Company") as of September 30, 2005, and the related condensed consolidated statements of income and comprehensive income for the three-month and nine-month periods ended September 30, 2005 and 2004, and the condensed consolidated statements of cash flows for the nine-month periods ended September 30, 2005 and 2004. These interim financial statements are the responsibility of the Company's management.

We have previously audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheet and statement of capitalization of Idaho Power Company and subsidiary as of December 31, 2004, and the related consolidated statements of income, comprehensive income, retained earnings and cash flows for the year then ended (not presented herein); and in our report dated March 8, 2005, we expressed an unqualified opinion on those consolidated financial statements. In our opinion, the information set forth in the accompanying condensed consolidated balance sheet and statement of capitalization as of December 31, 2004 is fairly stated, in all material respects, in relation to the consolidated balance sheet and statement of capitalization from which it has been derived.

DELOITTE & TOUCHE LLP

Boise, Idaho
November 2, 2005

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 exempt from registration as a public utility holding company pursuant to Section 3(a)(1) of the Public Utility Holding Company Act of 1935 (1935 Act). In addition, pursuant to Rule 2 of the General Rules and Regulations under the 1935 Act, IDACORP is exempt from all the provisions of the 1935 Act and rules thereunder, except for Section 9(a)(2) of the 1935 Act, which requires IDACORP to seek prior Securities and Exchange Commission approval to acquire securities of another public utility company. Under the Energy Policy Act of 2005 (Energy Act), the 1935 Act has been repealed, effective February 8, 2006, with the Federal Energy Regulatory Commission (FERC) receiving increased authority over mergers and affiliate transactions involving public utilities and the FERC and state commissions receiving increased access to the books and records of holding company systems.

IPC is an electric utility with a service territory covering approximately 24,000 square miles, primarily in southern Idaho and eastern Oregon. IPC is the parent of Idaho Energy Resources Co., a joint venturer in Bridger Coal Company, which supplies coal to the Jim Bridger generating plant owned in part by IPC.

IDACORP's other operating subsidiaries include:

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

IdaTech, LLC - developer of integrated fuel cell systems;

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

Ida-West Energy Company - 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, wound down its operations in 2003.

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

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, 2004 and the Quarterly Reports on Form 10-Q for the quarters ended March 31 and June 30, 2005, 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 recently enacted Energy Policy Act of 2005;

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

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

Weather variations affecting hydroelectric generating conditions and customer energy usage;

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

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

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

Impacts from the potential formation of a regional transmission organization;

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.

RISK FACTORS:

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

Reduced hydroelectric generation can reduce revenues and increase costs. Idaho Power Company has a predominately hydroelectric generating base. Because of Idaho Power Company's heavy reliance on hydroelectric generation, the weather can significantly affect its operations. Idaho Power Company is experiencing its sixth consecutive year of below normal water conditions in 2005. When hydroelectric generation is reduced, Idaho Power Company must increase its use of more expensive thermal generating resources and purchased power. Through its power cost adjustment in Idaho, Idaho Power Company can expect to recover approximately 90 percent of the increase in its Idaho jurisdictional net power supply costs, which are fuel and purchased power less off-system sales, above the level included in its base rates. The power cost adjustment recovery includes both a forecast and deferrals that are subject to the regulatory process. However, recovery of amounts above forecast in one PCA year does not occur until the subsequent PCA year. The non-Idaho net power supply costs are subject to periodic recovery from its Oregon and Federal Energy Regulatory Commission jurisdictional customers.

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

Changes in temperature and precipitation can reduce power sales and revenues. Warmer than normal winters, cooler than normal summers and increased rainfall during the irrigation seasons will reduce retail revenues from power sales.

If the Idaho Public Utilities Commission, the Oregon Public Utility Commission or the Federal Energy Regulatory Commission grant less rate relief than requested in future filings, it will reduce Idaho Power Company's projected earnings and cash flows. If the Idaho Public Utilities Commission, the Oregon Public Utility Commission or the Federal Energy Regulatory Commission were to grant less rate relief than Idaho Power Company requests in future filings, it could have a negative effect on earnings and cash flow and result in future downgrades of IDACORP, Inc.'s and Idaho Power Company's credit ratings.

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

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

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

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

Increased capital expenditures can significantly affect liquidity. Increases in both the number of customers and the demand for energy require expansion and reinforcement of transmission, distribution and generating systems. Because Idaho Power Company did not receive the full amount of rate relief requested in its 2003 general rate case, Idaho Power Company will have to rely more on external financing for its planned utility construction expenditures from 2005 through 2007; these large planned expenditures may weaken the consolidated financial profile of Idaho Power Company and IDACORP, Inc. Additionally, a significant portion of Idaho Power Company's facilities were constructed many years ago. Aging equipment, even if maintained in accordance with good engineering practices, may require significant capital expenditures. Failure of equipment or facilities used in Idaho Power Company's systems could potentially increase repair and maintenance expenses, purchased power expenses and capital expenditures.

If losses at the non-regulated subsidiaries continue and if they are unable to obtain financing, this may, in the short term, reduce IDACORP, Inc.'s earnings and cash flow. IdaTech and IDACOMM have experienced operating losses and it is not certain that they will achieve or sustain profitability in the future. If these non-regulated subsidiaries do not achieve profitability or are unable to obtain financing to fund their operations, this could increase the need for IDACORP, Inc. to provide liquidity in the form of capital contributions or loans. In addition, if the value of these subsidiaries decreases, IDACORP, Inc. may need to take charges for impairment of assets.

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

Regulatory changes could lead to IDACORP, Inc. stock price volatility, lower IDACORP, Inc. stock prices due to short selling and disparate trading activity within the industry. On June 23, 2004, the Securities and Exchange Commission adopted Regulation SHO, which implemented changes to the manner in which short sales are regulated in the U.S. markets. On the same day, the Securities and Exchange Commission established a pilot program under Regulation SHO with respect to a number of issuers, including IDACORP, Inc. The pilot program commenced on May 2, 2005 and will continue until April 28, 2006. During the pilot program, short sales will be effected without regard to the provisions of the tick test in Rule 10a-1(a) and without compliance with any short sale price tests of the New York Stock Exchange or the Pacific Exchange, where IDACORP, Inc. common stock is listed. In the absence of any rule governing the price of short sales during the pilot program, there is a risk of increased volatility in IDACORP, Inc.'s stock, as well as the possibility of short selling at successively lower prices and the acceleration of a declining market for IDACORP, Inc. common stock. There is also the risk of disparate trading activity within the industry, as some issuers are subject to short sale price tests and others, such as IDACORP, Inc., are not.

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

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

Adverse results of income tax audits could reduce earnings and cash flows. In March 2005, the Internal Revenue Service began its examination of IDACORP's 2001 through 2003 tax years. On October 24, 2005, the Idaho State Tax Commission also began its examination of the same tax years. Outcome of the audits could differ materially from the amounts currently recorded, and the difference could reduce IDACORP's and Idaho Power Company's earnings and cash flows.

OVERVIEW OF THIRD QUARTER 2005 AND OUTLOOK:

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

Financial Results
IDACORP's basic and diluted earnings per share (EPS) for the quarter of $0.56 was a $0.12 per share decrease from 2004's $0.68 per share. Net income for the quarter was $24 million, compared to $26 million in the third quarter of 2004. Third quarter 2005 EPS reflects the issuance of over 4 million shares of common stock in December 2004.

IPC's quarterly contribution of $0.50 per share is $0.13 less than last year. Net income decreased from $24 million to $21 million.

IPC's quarterly income from operations increased $29 million compared to 2004, but this improvement was more than offset by increases in income tax expense of $33 million. IPC's 2005 operations benefited from increases to customer rates that took effect in June 2005, continued general business customer growth, and warmer and drier than normal weather. Included in 2004's results was a $19 million credit to Idaho customers stemming from a settlement related to IPC's 2003 general rate case.

The increase in 2005 income tax expense is due primarily to increased taxable income. IPC's income taxes in 2005 also include $2 million of reversals of previously accrued deductions, primarily related to capitalized overhead costs. New temporary regulations issued in August 2005 negatively impacted IPC's tax method for capitalized overhead costs. Also, Income taxes in 2004 included a $16 million credit resulting from a 2003 Idaho general rate case settlement.

IDACORP's non-regulated subsidiaries, including the holding company, combined for a profit of $0.06 per share, an increase of $0.01 per share from last year. IFS earned $0.06 per share in the third quarter of 2005, compared to $0.07 per share in 2004. Other subsidiaries and the holding company combined to break even for the quarter, compared to a loss of $0.02 per share in 2004. Third quarter 2005 results reflect the beneficial effect of intra-period tax allocations recorded at the holding company. In accordance with interim reporting requirements, the estimated annual effective tax rate is used in determining tax expense, which resulted in an intra-period allocation of income tax expense. IDACORP's 2004 results include a $0.05 per share contribution from IE due to the settlement of a legal dispute.

Emission Allowances
In October 2005, IPC sold 60,000 excess sulfur dioxide (SO₂)emission allowances (out of a total of approximately 107,000 excess allowances) on the open market for approximately $57 million. IPC is now seeking approval from the Idaho Public Utilities Commission (IPUC) for the accounting treatment of these transactions, which will determine the allocation of proceeds between retail customers and shareholders. At this time, IPC cannot predict how the proceeds might ultimately be allocated between retail customers and shareholders.

Power Supply Costs
IPC is experiencing its sixth consecutive year of below normal water conditions, and is relying more on wholesale power purchases than it would in a normal year. Hydro generation forecasts for 2005 have improved from earlier in the year, due to heavy precipitation in May, but overall water conditions remain below normal. Generation at IPC's hydroelectric facilities is expected to be 6.3 million MWh in 2005, compared to 2004 generation of 6.0 million MWh and median generation of 8.5 million MWh. IPC expects power supply costs will remain high as long as below normal water conditions persist. IPC's annual PCA filing for the 2005-2006 PCA year included estimated power supply costs of $155 million.

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

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

Relicensing
IPC's most significant ongoing relicensing effort is the Hells Canyon Complex, which provides approximately two-thirds of IPC's hydroelectric generating capacity and 40 percent of its total generating capacity. Over the past year, IPC has participated in negotiations with a number of interested parties in an attempt to develop a comprehensive agreement for relicensing the Hells Canyon Complex. To date, however, the parties have not been successful in reaching an agreement. Because it was unlikely that the parties to the settlement process would reach an agreement on a comprehensive settlement package in the near term and with the issuance of the Notice of Ready for Environmental Analysis (NREA) by the FERC in October 2005, the settlement discussions have been terminated to allow the parties the opportunity to develop comments and preliminary terms and conditions to be filed with the FERC. The parties expect to reassess opportunities for settlement in the spring of 2006 after the filings with the FERC.

Legal Issues
In connection with the shareholder lawsuits filed against IDACORP and four of its officers and directors in 2004, on September 14, 2005, Magistrate Judge Mikel H. Williams of the U.S. District Court for the District of Idaho issued a Report and Recommendation that the defendants' motion to dismiss be granted and that the case be dismissed. The Magistrate Judge determined that the plaintiffs did not satisfactorily plead loss causation (i.e., a causal connection between the alleged material misrepresentation and the loss) in conformance with the standards set forth in the recent United States Supreme Court decision of Dura Pharmaceuticals, Inc. v. Broudo, 544 U.S._____, 125 S. Ct. 1627 (2005). The Magistrate Judge also concluded that it would be futile to afford the plaintiffs an opportunity to file an amended complaint because it did not appear that they could cure the deficiencies in their pleadings. The parties have each filed objections to different parts of the Magistrate Judge's Report and Recommendation, and the matter is now before the District Judge.

Energy Policy Act of 2005
On August 8, 2005, the President signed into law the Energy Act, which is a comprehensive energy bill affecting the regulation of energy companies, including IPC. Key provisions of the Energy Act that may affect IPC include:

Creation of an electric reliability organization that the FERC will appoint and oversee to establish and enforce mandatory reliability rules regarding the interstate electric transmission system;

Requirements for the FERC to establish incentive-based transmission rate policies;

FERC backstop authority for transmission line siting in corridors of national interest;

Changes in authority over regional transmission organizations;

Amendments to PURPA, prospectively terminating mandatory purchase and sale requirements when a qualifying facility has access to competitive markets and eliminating the prohibition against utility ownership of qualifying facilities;

Reform of the hydroelectric licensing process to provide trial-type hearings for disputed facts regarding license conditions, to create a process for licensees to propose alternatives to prescribed conditions and to require prescribing authorities to balance competing interests;

Incentives to develop additional generation at existing hydroelectric dams;

Creation of significant tax incentives to encourage and promote electricity reliability, renewable and clean energy investment and clean coal, and other energy efficiency and conservation; and

Repeal of the 1935 Act, effective February 8, 2006, giving the FERC increased authority over mergers and affiliate transactions involving public utilities, and providing the FERC and state commissions increased access to the books and records of holding company systems.

Implementation of the Energy Act requires the development of regulations by the FERC, the Department of Energy and other federal agencies as well as proceedings at the state level. The FERC issued a Notice of Proposed Rulemaking in September 2005 on 1935 Act transition rules and proposed reporting, accounting and recordkeeping rules for utility holding companies.

IDACORP and IPC are currently monitoring the Energy Act's implementation to determine its effects on the companies.

CRITICAL ACCOUNTING POLICIES:

IDACORP's and IPC's discussion and analysis of their financial condition and results of operations are based upon their condensed consolidated financial statements, which have been prepared in accordance with generally accepted accounting principles. The preparation of these financial statements requires IDACORP and IPC to make estimates and judgments that affect the reported amounts of assets, liabilities, revenues and expenses and related disclosure of contingent assets and liabilities. On an ongoing basis, IDACORP and IPC evaluate these estimates including those estimates related to rate regulation, benefit costs, contingencies, litigation, impairment of assets, income taxes, restructuring costs and bad debt. These estimates are based on historical experience and on other assumptions and factors that are believed to be reasonable under the circumstances, and are the basis for making judgments about the carrying values of assets and liabilities that are not readily apparent from other sources. IDACORP and IPC, based on their ongoing reviews, make adjustments when facts and circumstances dictate.

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

RESULTS OF OPERATIONS:

This section of the MD&A takes a closer look at the significant factors that affected IDACORP's and IPC's earnings during the three and nine months ended September 30, 2005. In this analysis, the results for 2005 are compared to the same periods in 2004. The analysis is organized by IDACORP's reportable segments, which are IPC's utility operations and IFS. The following table presents the contribution to IDACORP's EPS by each of the reportable segments, as well as by the holding company and the other subsidiaries combined, for the three and nine months ended September 30:

EPS of common stock		Three months ended				Nine months ended
		September 30,				September 30,
		2005		2004		2005		2004
Utility operations *		$	0.50	$	0.63	$	1.31	$	1.34
IFS *			0.06		0.07		0.18		0.26
Other *			0.00		(0.02)		(0.16)		(0.06)
	Total EPS	$	0.56	$	0.68	$	1.33	$	1.54

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

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

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

IPC's system is dual peaking, with the larger peak demand generally occurring in the summer. IPC's record system peak of 2,963 MW occurred on July 12, 2002. Peak demand so far in 2005 was 2,961 MW on July 22, 2005. IPC was able to meet system load requirements and off-system sales requirements and had sufficient system reserves in place. IPC's 2004 Integrated Resource Plan (IRP) reports that customers' use of electricity continues to grow during the summer months. IPC projects that summer peaks could grow by an average of 2.5 percent per year over the ten-year IRP planning period.

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

		Three months ended September 30,				Nine months ended September 30,
				% of Total				% of Total
		MWh		Generation		MWh		Generation
		2005	2004	2005	2004	2005	2004	2005	2004
Hydroelectric		1,494	1,407	42%	42%	4,818	4,777	47%	47%
Thermal		2,070	1,950	58%	58%	5,409	5,359	53%	53%
	Total system generation	3,564	3,357	100%	100%	10,227	10,136	100%	100%

Streamflow conditions have remained below average in 2005, but above average precipitation this spring resulted in an improved water supply outlook. The National Weather Service Northwest River Forecast Center reports that the January through September inflow into Brownlee Reservoir was 55 percent of average.

Actual observed Brownlee Reservoir inflow for the April-through-July period was 3.6 million acre-feet (maf). This inflow volume is 56 percent of the 30-year average of 6.3 maf, 60 percent of the median of 6.02 maf and reflects the sixth consecutive year of below average inflow. Generation from IPC's hydroelectric facilities is expected to be 6.3 million MWh in 2005, compared to 6.0 million MWh in 2004 and median hydroelectric generation of 8.5 million MWh.

As noted in IDACORP's and IPC's quarterly reports on Form 10-Q for the quarters ended March 31 and June 30, 2005 the estimated normal annual hydroelectric generation was reduced to 8.7 million MWh, based on the results of updated studies conducted by the Idaho Department of Water Resources (IDWR). The calculation of normal generation is based on average hydrologic conditions for the standardized period of record, 1928 through 2004. Annual hydroelectric generation is now based on median hydrologic conditions for the standardized period of record and the term normal will no longer be used. The median annual hydroelectric generation for the standardized period of record is 8.5 million MWh.

General Business Revenue: The following table presents IPC's general business revenues, MWh sales and average number of customers for the three and nine months ended September 30:

		Three months ended September 30,
			Revenue			MWh		Average Customers
		2005		2004		2005	2004	2005		2004
Residential		$	76,131	$	67,869	1,141	1,067	375,359	361,956
Commercial			48,115		45,293	965	932	57,327	55,738
Industrial			31,780		29,212	880	860	130	127
Irrigation			51,211		44,313	1,012	917	18,013	17,347
	Total	$	207,237	$	186,687	3,998	3,776	450,829	435,168

		Nine months ended September 30,
			Revenue			MWh		Average Customers
		2005		2004		2005	2004	2005		2004
Residential		$	215,506	$	199,878	3,424	3,325	371,585		358,922
Commercial			129,547		124,128	2,719	2,655	56,892		55,326
Industrial			86,893		84,275	2,548	2,475	128		118
Irrigation			72,243		82,868	1,386	1,682	17,930		17,216
	Total	$	504,189	$	491,149	10,077	10,137	446,535		431,582

Rates: Higher rates in effect in 2005 increased general business revenue $9 million over the same quarter last year and $16 million year-to-date. The increased 2005 rates result from several rate proceedings discussed in more detail below in "REGULATORY MATTERS." Approximately $8 million of the general business revenue increase represents collection of previously recorded revenues from the irrigation load reduction program and rate case tax settlement. This revenue is offset by a reduction to other revenues in the same amount.

Usage: Weather variations positively impacted sales by approximately $6 million for the quarter. Conditions were drier and slightly warmer than in the third quarter of 2004. Year-to-date, wet spring weather and milder winter temperatures have lowered sales by approximately $23 million compared to 2004. Rainfall in IPC's service territory in the second quarter was double that of last year, reducing sales to irrigation customers.

Customers: An increase in general business customers improved revenue $6 million for the quarter and $20 million year-to-date, as IPC continues to experience strong customer growth in its service territory.

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

	Three months ended					Nine months ended
	September 30,					September 30,
	2005		2004			2005	2004

Revenue	$	34,105	$	34,969	$	105,189	$	99,899
MWh sold		587		791		2,269		2,439
Revenue per MWh	$	58.12	$	44.23	$	46.36	$	40.95

Third quarter 2005 actual loads and resources were more closely in line with the forecast resulting in 25.8% less surplus system energy available for opportunity sales, as compared to 2004.

Other revenues: Based on the IPUC order approving the settlement agreement related to the calculation of IPC's test year income tax expense in the 2003 Idaho general rate case, IPC recorded monthly, for the period June 1, 2004 through May 31, 2005, other revenues and a corresponding regulatory asset of approximately $12 million. Beginning in June 2005, this regulatory asset is being recovered in rates (and presented in general business revenue), with a corresponding reduction to other revenues. The net effect on other revenue was an $8 million decrease in the third quarter of 2005 and a $5 million decrease year-to-date.

Also, beginning in June 2005, IPC began collecting in general business revenues amounts related to a load reduction program. There was an offsetting reduction to other revenues of approximately $4 million for the quarter and $5 million year-to-date.

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

	Three months ended					Nine months ended
	September 30,					September 30,
	2005			2004		2005	2004

Purchases	$	81,396	$	79,607	$	162,403	$	162,877
MWh purchased		1,420		1,677		3,104		3,625
Cost per MWh purchased	$	57.32	$	47.47	$	52.32	$	44.93

Purchased power expenses were slightly higher compared to the third quarter of last year due to a 20.7 percent increase in average energy prices, partially offset by an 18 percent decrease in purchases.

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

	Three months ended					Nine months ended
	September 30,					September 30,
	2005			2004		2005	2004

Fuel expense	$	28,018	$	28,291	$	77,483	$	77,364
Thermal MWh generated		2,070		1,950		5,398		5,359
Cost per MWh	$	13.54	$	14.51	$	14.35	$	14.44

For the quarter, fuel expense decreased due principally to credits received for the sale-back of natural gas to the supplier at market price, which was greater than the price as purchased for use at IPC's gas-fired plants. This credit is partially offset by a five percent increase in generation at the coal-fired plants. Generation at the Boardman coal-fired plant increased by 60 percent for the quarter due to a longer than usual outage in 2004.

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

So far in 2005, net power supply costs, which are fuel and purchased power less off-system sales, have exceeded the amounts in the annual PCA forecasts, resulting in the deferral of a portion of those costs to subsequent rate years when they are to be recovered in rates. As the deferred revenues are being recovered in rates, the deferred balances are amortized.

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

		Three months ended				Nine months ended
		September 30,				September 30,
		2005			2004	2005		2004
Current year power supply cost accrual (deferral)		$	(12,833)	$	(13,782)	$	(25,378)	$	(27,197)
Amortization of prior year authorized balances			3,163		14,102		23,705		38,335
Settlement agreement			-		19,300		-		19,300
	Total power cost adjustment	$	(9,670)	$	19,620	$	(1,673)	$	30,438

Other operating and maintenance expenses: O&M expenses did not vary materially from the amounts recorded in the corresponding periods of the prior year. IPC projects that its 2005 operating expenses will be approximately $244 to $248 million.

IFS
IFS contributed $0.06 per share in the third quarter of 2005, compared to $0.07 per share in the third quarter of 2004. IFS' income is derived principally from the generation of federal income tax credits and tax depreciation benefits related to its investments in affordable housing and historic rehabilitation developments. IFS generated $5 million of tax credits in the third quarter of both 2005 and 2004, and $15 million year-to-date in both years, and expects to continue generating tax benefits near current levels.

INCOME TAXES:

Status of Audit Proceedings
In March 2005, the Internal Revenue Service began its examination of IDACORP's 2001 through 2003 tax years. On October 24, 2005, the Idaho State Tax Commission 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.

Capitalized Overhead Costs: On August 2, 2005, the Internal Revenue Service and 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 do the current treasury regulations.

IPC is actively involved in pursuing resolution of this matter and is working diligently with the Internal Revenue Service 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 Internal Revenue Service in this matter may have on 2005 or prior tax years.

LIQUIDITY AND CAPITAL RESOURCES:

Operating Cash Flows
IDACORP's and IPC's operating cash flows for the nine months ended September 30, 2005 were $121 million and $126 million, respectively.

IDACORP's and IPC's operating cash flows decreased $34 million and $27 million, respectively, compared to 2004. The decreases were mainly related to the timing of cash disbursements made in 2005 for December 2004 payable balances, including $9 million in employee incentive compensation paid during the first quarter of 2005. There was no similar employee incentive plan payout in 2004. In addition, IPC's distributions from the Bridger Coal joint venture have decreased approximately $13 million, as Bridger is retaining cash to fund increased capital expenditures for conversion to underground mining.

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

Working Capital
IDACORP's other current liabilities and IPC's payable to related parties include $12 million of dividends payable to shareholders. Other changes in working capital are due primarily to timing and normal business activity.

Contractual Obligations
IDACORP's contractual cash obligations have increased from $3.0 billion at December 31, 2004 to $3.4 billion at September 30, 2005. This change is primarily due to an increase in IPC's contractual cash obligations, which increased from $2.9 billion at December 31, 2004 to $3.3 billion at September 30, 2005. The most significant changes from IPC's December 31, 2004 reported amounts are cogeneration and small power production (CSPP), which increased $312 million, and future interest payments, which increased $82 million. The increase in CSPP is primarily due to the addition of new wind and hydro energy contracts. The increase in future interest payments is primarily due to the August 26, 2005, $60 million bond issuance, the proceeds of which were used to repay the $60 million bonds that matured on September 9, 2005. IPC's overall increase in contractual cash obligations from December 31, 2004 to September 30, 2005, is comprised of a $74 million reduction in the amount due in one year or less, a $51 million increase due between one and three years, a $36 million increase due between three and five years and a $394 million increase due in more than five years.

Capital Requirements
IDACORP's internal cash generation after dividends, not including any proceeds from sales of excess emission allowances, is expected to provide less than the full amount of total capital requirements for 2005 through 2007. The contribution from internal cash generation is dependent primarily upon IPC's cash flows from operations, which are subject to risks and uncertainties relating to weather and water conditions, and IPC's ability to obtain rate relief to cover its operating costs. IDACORP's internally generated cash, after dividends, not including any proceeds from sales of excess emission allowances, is expected to provide approximately 62 percent of 2005 capital requirements, where capital requirements are defined as utility construction expenditures, excluding Allowance for Funds Used During Construction (AFDC), plus other regulated and non-regulated investments. This excludes mandatory or optional principal payments on debt obligations. IDACORP and IPC expect to continue financing the utility construction program and other capital requirements with internally generated funds and with increased reliance on externally financed capital.

The current expectation of approximately 62 percent of 2005 capital requirements is a decrease from the 70 percent reported in IDACORP's and IPC's Quarterly Report on Form 10-Q for the quarter ended June 30, 2005. This decrease is due mainly to changes in utility working capital.

Utility Construction Program: Utility construction expenditures were $133 million for the nine months ended September 30, 2005 compared to $137 million for the nine months ended September 30, 2004. As reported in IDACORP's and IPC's Annual Report on Form 10-K for the year ended December 31, 2004, IPC's total construction expenditures are expected to be $672 million, excluding AFDC, from 2005 through 2007. At that time, IPC expected to spend approximately $202 million, excluding AFDC, in 2005. IPC currently expects to spend between $185 million and $195 million, excluding AFDC and other non-cash items. The decrease is due primarily to the deferral of certain construction projects until 2006. The estimate of $672 million over the three-year period has not changed; however, as part of IPC's annual budget cycle, IPC's 2006 through 2007 utility construction program is currently under review.

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

Financing Programs
Credit facilities: On May 3, 2005, IDACORP entered into a $150 million five-year credit agreement with various lenders, Wachovia Bank, National Association, as joint lead arranger and administrative agent and JP Morgan Chase Bank, NA, as joint lead arranger and syndication agent and Wachovia Capital Markets, LLC and J.P. Morgan Securities Inc., as joint lead arrangers and joint book runners (IDACORP Facility). The IDACORP Facility replaced IDACORP's $150 million facility that was to expire on March 16, 2007. The IDACORP Facility, which will be used for general corporate purposes and commercial paper back-up, will terminate on March 31, 2010. The IDACORP Facility provides for the issuance of loans and standby letters of credit not to exceed the aggregate principal amount of $150 million, provided that the aggregate amount of the standby letters of credit may not exceed $75 million.

Under the terms of the IDACORP Facility, IDACORP may borrow floating rate advances and eurodollar rate advances. The floating rate is equal to the higher of (i) the prime rate announced by Wachovia Bank or its parent and (ii) the sum of the federal funds effective rate for such day plus 1/2 percent per annum, plus, in each case, an applicable margin. The eurodollar rate is based upon the British Bankers' Association interest settlement rate for deposits in U.S. dollars published on the Telerate Page 3750 (or any successor page) as adjusted by the applicable reserve requirement for Eurocurrency liabilities imposed under Regulation D of the Board of Governors of the Federal Reserve System, for periods of one, two, three or six months plus the applicable margin. The applicable margin is based on IDACORP's rating for senior unsecured long-term debt securities without third-party credit enhancement as provided by Moody's Investors Services (Moody's) and Standard & Poor's Ratings Service (S&P). The applicable margin for the floating rate advances is zero percent unless IDACORP's rating falls below Baa3 from Moody's or BBB- from S&P, at which time it would equal 0.50 percent. The applicable margin for eurodollar rate advances ranges from 0.27 percent to 0.875 percent depending upon the credit rating. In addition to the applicable margin, if the outstanding aggregate credit exposure exceeds 50 percent of the facility amount, IDACORP would pay a utilization fee ranging from 0.10 percent to 0.125 percent on outstanding loans depending on the credit rating. At September 30, 2005, the applicable margin was zero percent for floating rate advances and 0.425 percent for eurodollar rate advances and 0.125 percent for a utilization fee. A facility fee, payable quarterly by IDACORP, is calculated on the average daily aggregate commitment of the lenders under the IDACORP Facility and is also based on IDACORP's rating from Moody's or S&P as indicated above. At September 30, 2005, the facility fee was 0.15 percent.

In connection with the issuance of letters of credit, IDACORP must pay (i) a fee equal to the applicable margin for eurodollar rate advances on the average daily undrawn stated amount under such letters of credit, payable quarterly in arrears, (ii) a fronting fee at a per annum rate of 0.125 percent on the average daily undrawn stated amount under each letter of credit, payable quarterly in arrears and (iii) documentary and processing charges in accordance with the letter of credit issuer's standard schedule for such charges.

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

The events of default under the IDACORP Facility include (i) nonpayment of principal when due and nonpayment of reimbursement obligations under letters of credit within one business day after becoming due and nonpayment of interest or other fees within five days after becoming due, (ii) materially false representations or warranties made on behalf of IDACORP or any of its subsidiaries on the date as of which made, (iii) breach of covenants, subject in some instances to grace periods, (iv) voluntary and involuntary bankruptcy of IDACORP or any material subsidiary, (v) the non-consensual appointment of a receiver or similar official for IDACORP or any of its material subsidiaries or any substantial portion (as defined in the IDACORP Facility) of its property, (vi) condemnation of all or any substantial portion of the property of IDACORP or its subsidiaries, (vii) default in the payment of indebtedness in excess of $25 million or a default by IDACORP or any of its subsidiaries under any agreement under which such debt was created or governed which will cause or permit the acceleration of such debt or if any of such debt is declared to be due and payable prior to its stated maturity, (viii) IDACORP or any of its subsidiaries not paying, or admitting in writing its inability to pay, its debts as they become due, (ix) the acquisition by any person or two or more persons acting in concert of beneficial ownership (within the meaning of Rule 13d-3 of the Securities Exchange Act of 1934) of 20 percent or more of the outstanding shares of voting stock of IDACORP, (x) the failure of IDACORP to own free and clear of all liens, all of the outstanding shares of voting stock of IPC, (xi) unfunded liabilities of all single employer plans under the Employee Retirement Income Security Act of 1974 exceeding $50 million and (xii) IDACORP or any subsidiary being subject to any proceeding or investigation pertaining to the release of any toxic or hazardous waste or substance into the environment or any violation of any environmental law (as defined in the IDACORP Facility) which could reasonably be expected to have a material adverse effect (as defined in the IDACORP Facility). A default or an acceleration of indebtedness of IPC in excess of $25 million, including indebtedness under the IPC Facility described below, will result in a cross default under the IDACORP Facility.

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

On May 3, 2005, IPC entered into a $200 million five-year credit agreement with various lenders, Wachovia Bank, National Association, as joint lead arranger and administrative agent and JP Morgan Chase Bank, NA, as joint lead arranger and syndication agent and Wachovia Capital Markets, LLC and J.P. Morgan Securities Inc., as joint lead arrangers and joint book runners (IPC Facility). The IPC Facility replaced IPC's $200 million credit agreement that was to expire on March 16, 2007. The IPC Facility, which expires on March 31, 2010, will be used for general corporate purposes and commercial paper back-up. The IPC facility provides for the issuance of loans and standby letters of credit not to exceed the aggregate principal amount of $200 million, provided that the aggregate amount of the standby letters of credit may not exceed $100 million. Under the terms of the IPC Facility, IPC may borrow floating rate advances and eurodollar rate advances. The methods of calculating the floating rate and the eurodollar rate are the same as set forth above for the IDACORP Facility. The applicable margin for the IPC Facility is also dependent upon IPC's rating for senior unsecured long-term debt securities without third-party credit enhancement as provided by Moody's and S&P. At September 30, 2005, the applicable margin for the IPC Facility was zero percent for floating rate advances and 0.35 percent for eurodollar rate advances and 0.125 percent for a utilization fee. A facility fee, payable quarterly by IPC, is calculated on the average daily aggregate commitment of the lenders under the IPC Facility and is also based on IPC's rating from Moody's or S&P as indicated above. At September 30, 2005, the facility fee was 0.125 percent.

In connection with the issuance of letters of credit, IPC must pay (i) a fee equal to the applicable margin for eurodollar rate advances on the average daily undrawn stated amount under such letters of credit, payable quarterly in arrears, (ii) a fronting fee at a per annum rate of 0.125 percent on the average daily undrawn stated amount under each letter of credit, payable quarterly in arrears and (iii) documentary and processing charges in accordance with the letter of credit issuer's standard schedule for such charges.

A ratings downgrade would result in an increase in the cost of borrowing, but would not result in any default or acceleration of the debt under the IPC Facility. If there is a ratings downgrade below investment grade (BBB- or higher by S&P and Baa3 or higher by Moody's), then IPC's authority for continuing borrowings under its regulatory approvals issued by the IPUC and the Oregon Public Utility Commission (OPUC) must be extended or renewed during the occurrence of the ratings downgrade. The Oregon statutes, however, permit the issuance or renewal of indebtedness maturing not more than one year after the date of such issue or renewal without approval of the OPUC. In an order issued May 6, 2005, the IPUC clarified that IPC's authority will not terminate but will continue for a period of 364 days from any downgrade below investment grade.

At September 30, 2005, no loans were outstanding under the IDACORP Facility or IPC Facility.

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

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

Debt Covenants: The IDACORP Facility and the IPC Facility each contain a covenant requiring each company to maintain a leverage ratio of consolidated indebtedness to consolidated total capitalization of no more than 65 percent as of the end of each fiscal quarter. At September 30, 2005, the leverage ratios for both IDACORP and IPC were 52 percent. At September 30, 2005, 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.

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

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

Long-term financings: On August 26, 2005, Idaho Power Company issued $60 million of its 5.30% First Mortgage Bonds due 2035, Secured Medium-Term Notes, Series F. On August 30, 2005, IPC settled a forward-starting interest rate swap agreement by making a payment of $2.7 million to the counterparty of the agreement. In accordance with regulatory accounting practices under SFAS No. 71, IPC is amortizing this amount over the life of the 5.30% First Mortgage Bonds due 2035. The proceeds of the issuance were used to repay the $60 million, 5.83% First Mortgage Bonds that matured on September 9, 2005.

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. Approximately 125,000 shares have been issued through the third quarter.

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

Subsidiary Financing
IdaTech and IDACOMM are each seeking to raise additional funds from private sources in 2005 for the ongoing funding of their respective operations. IdaTech and IDACOMM cannot presently determine what level of private funding may be raised, or what equity interest in the respective companies may be issued in connection with the funding.

LEGAL AND ENVIRONMENTAL ISSUES:

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

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

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

IDACORP, IPC and IE removed this action from the state court to the U.S. District Court for the Western District of Washington at Tacoma. On November 12, 2002, the companies filed a motion to dismiss Grays Harbor's complaint, asserting that the U.S. District Court lacked jurisdiction because the FERC has exclusive jurisdiction over wholesale power transactions and thus the matter is preempted under the Federal Power Act and barred by the filed-rate doctrine. The court ruled in favor of the companies' motion to dismiss and dismissed the case with prejudice on January 28, 2003. On February 25, 2003, Grays Harbor filed a Notice of Appeal, appealing the final judgment of dismissal to the U.S. Court of Appeals for the Ninth Circuit. On August 10, 2004, the Ninth Circuit affirmed the dismissal of Grays Harbor's complaint, finding that Grays Harbor's claims were preempted by federal law and were barred by the filed-rate doctrine. The court also remanded the case to allow Grays Harbor leave to amend its complaint to seek declaratory relief only as to contract formation, and held that Grays Harbor could seek monetary relief, if at all, only from the FERC, and not from the courts. IDACORP, IPC and IE sought rehearing from the Ninth Circuit arguing that the court erred in granting leave to amend the complaint as such a declaratory relief claim would be preempted and would be barred by the filed-rate doctrine. The Ninth Circuit denied the rehearing request on October 25, 2004, and the decision became final on November 12, 2004. On that same date, the companies took steps to have the case transferred and consolidated with other similar cases arising out the California energy crisis currently pending before the Honorable Robert H. Whaley, sitting by designation in the Southern District of California and presiding over Multidistrict Litigation Docket No. 1405, regarding California Wholesale Electricity Antitrust Litigation. On November 18, 2004, Grays Harbor filed an amended complaint alleging that the contract was formed under circumstances of "mistake" as to an "artificial . . . power shortage." Grays Harbor asked that the contract therefore be declared "unenforceable" and found "unconscionable." On December 23, 2004, the Judicial Panel on Multidistrict Litigation conditionally transferred the case to Judge Whaley. Grays Harbor sought to vacate the transfer; however, on April 18, 2005, the Judicial Panel on Multidistrict Litigation ordered the case transferred. On May 18, 2005, IDACORP, IPC and IE filed a motion to dismiss the amended complaint. The motion was heard on September 29, 2005. The court has not yet ruled on the motion. The companies intend to vigorously defend their position and believe this matter will not have a material adverse effect on their consolidated financial positions, results of operation, or cash flows.

All defendants, including IPC and IDACORP, moved to dismiss the complaint in lieu of answering it. The motions were based on the grounds that the complaint seeks to set alternative electrical rates, which are exclusively within the jurisdiction of the FERC and are barred by the filed-rate doctrine. A hearing on the motion to dismiss was heard on March 26, 2004. On May 28, 2004, the court granted IPC's and IDACORP's motion to dismiss. In June 2004, the Port of Seattle appealed the court's decision to the U.S. Court of Appeals for the Ninth Circuit. The appeal has been fully briefed, however, no date has yet been set for oral argument. Also, on July 19, 2005 the companies filed a motion for summary affirmance of the district court's order dismissing the Port of Seattle's complaint. The Ninth Circuit issued an order denying this motion on October 19, 2005. The companies intend to vigorously defend their position in this proceeding and believe this matter will not have a material adverse effect on their consolidated financial positions, results of operations or cash flows.

On September 8, 2004, this case was transferred and consolidated with other similar cases currently pending before the Honorable Robert H. Whaley.

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

Western Energy Proceedings at the FERC: IE and IPC are involved in a number of FERC proceedings arising out of the western energy situation in California and claims that dysfunctions in the organized California markets contributed to or caused unjust and unreasonable prices in Pacific Northwest spot markets, and may have been the result of manipulations of gas or electric power markets. They include proceedings involving: (1) the chargeback provisions of the California Power Exchange (CalPX) participation agreement, which was triggered when a participant defaulted on a payment to the CalPX. Upon such a default, other participants were required to pay their allocated share of the default amount to the CalPX. This provision was first triggered by the Southern California Edison default and later by the Pacific Gas and Electric Company default. The FERC has ordered the CalPX to hold the chargeback funds and that such funds may be used to make-up individual seller shortfalls in their CalPX account at the conclusion of the California Refund proceeding. One party has appealed this order to the D.C. Circuit Court of Appeals; (2) efforts by the State of California to obtain refunds for a portion of the spot market sales from sellers of electricity into California from October 2, 2000 through June 20, 2001. California is claiming that the sales prices were not just and reasonable and were not in compliance with the Federal Power Act. The FERC issued an order on refund liability on March 26, 2003 on which multiple parties, including IE, sought rehearing. On October 16, 2003, the FERC denied the requests for rehearing and required the California Independent System Operator (Cal ISO) to make a compliance filing regarding refund amounts within five months, which has since been delayed until March 2006. On May 12, 2004, the FERC issued an order clarifying its earlier refund orders and denying a request by certain parties to present as evidence an earlier settlement between the California Public Utilities Commission and El Paso related to manipulation of gas pipeline capacity claiming that the settlement dollars California is receiving from El Paso ($1.69 billion) are duplicative of the FERC order changing the gas component of its refund methodology. The FERC denied requests for rehearing on November 23, 2004. On December 2, 2003, IE and others petitioned the United States Court of Appeals for the Ninth Circuit for review of the FERC's orders on California refunds. As additional FERC orders have been issued, further petitions for review have been filed, including by IE, and have been consolidated with the appeals already pending before the Ninth Circuit. On September 21, 2004, the Ninth Circuit convened the first of its case management proceedings, a procedure reserved to help organize complex cases. On October 22, 2004, the Ninth Circuit severed several issues related to the FERC's refund jurisdiction, established a schedule for briefing and held oral argument on April 12 and 13, 2005. On May 26, 2005, the California Parties filed a motion with the FERC to submit additional evidence. A number of parties are opposing this motion. On September 6, 2005, the Ninth Circuit issued a decision in one of the severed cases concluding that the FERC lacked refund authority over wholesale electrical energy sales made by governmental entities and non-public utilities. On August 8, 2005 the FERC issued an order establishing a framework for those sellers wanting to make a cost filing. The companies along with others made a cost filing on September 14, 2005, the California entities commented on October 11, 2005, and IPC and IE replied to those comments on October 17, 2005. The California entities filed supplemental comments on October 24, 2005 and IPC filed supplemental reply comments on October 27, 2005. At September 30, 2005, with respect to the CalPX chargeback and the California Refund proceedings discussed above, the CalPX and the Cal ISO owed $14 million and $30 million, respectively, for energy sales made to them by IPC in November and December 2000. IE has accrued a reserve of $42 million against these receivables. This reserve was calculated taking into account the uncertainty of collection, given the California energy situation. Based on the reserve recorded as of September 30, 2005, IDACORP believes that the future collectibility of these receivables or any potential refunds ordered by the FERC would not have a material adverse effect on its consolidated financial position, results of operations or cash flows; (3) the Pacific Northwest refund proceedings wherein it was argued that the spot market in the Pacific Northwest was affected by the dysfunction in the California market, warranting refunds. The FERC rejected this claim on June 25, 2003, and denied rehearing on November 11, 2003 and February 9, 2004. The FERC orders were appealed to the Ninth Circuit, which established a briefing schedule under which final briefs were submitted in May 2005. There presently is no date set for oral argument. IE and IPC are unable to predict the outcome of these matters; and (4) two FERC show cause orders which resulted from a ruling of the Ninth Circuit that the FERC permit the California parties in the California refund proceeding to submit materials to the FERC demonstrating market manipulation by various sellers of electricity into California. On June 25, 2003, the FERC ordered a large number of parties including IPC to show cause why certain trading practices did not constitute gaming ("gaming") or anomalous market behavior ("partnership") in violation of the Cal ISO and CalPX Tariffs. On October 16, 2003, IPC reached agreement with the FERC Staff on the show cause orders. The "gaming" settlement was approved by the FERC on March 3, 2004. The FERC approved the motion to dismiss the "partnership" proceeding on January 23, 2004. Although the orders establishing the scope of the show cause proceedings are presently the subject of review petitions in the Ninth Circuit, the order dismissing IPC from the "partnership" proceedings was not the subject of rehearing requests. Eight parties have requested rehearing of the FERC's March 3, 2004 order approving the "gaming" settlement but the FERC has not yet acted on those requests.

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

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

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

Environmental Issues
Idaho Water Management Issues: IPC holds water rights for generation purposes at each of its hydroelectric projects. The State of Idaho is experiencing its sixth consecutive year of below normal precipitation and stream flows. These conditions have exacerbated a developing water shortage in the state, which is manifested by a number of water issues that are of interest to IPC because of their potential impacts on generation at IPC's hydroelectric projects, including declining Snake River base flows and recharge to the Eastern Snake Plain Aquifer, a large underground aquifer that has been estimated to hold between 200-300 maf of water. With respect to base flows, observed records suggest that the base flows in the Snake River, particularly between IPC's Twin Falls and Swan Falls projects, have been in decline for several decades. The yearly average flow measured below Swan Falls declined at an average rate of 43 cubic feet per second (cfs) per year during the period 1961-2003, and observed stream flow gains between Twin Falls and Lower Salmon Falls, which are largely attributed to base flow contribution, declined at a rate of 27 cfs per year over the same period. Low flow in the Snake River near Hagerman, Idaho continues to be observed during 2005 - several river gauges in that area recorded the lowest January - March Snake River flows since the early 1960s. The Snake River, at various places throughout its reach from Rexburg, Idaho to King Hill, Idaho, is connected to the Eastern Snake Plain Aquifer. In certain times of the year, the flows into the Snake River below Milner Dam are heavily dependent on the outflow from springs that are connected to and fed by the Eastern Snake Plain Aquifer in the Thousand Springs reach of the Snake River. The majority of IPC's hydroelectric projects are below Milner Dam.

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

In March 2004, the State of Idaho negotiated an interim agreement between several of the ground and surface water users engaged in the controversy in an effort to allow the state to develop short and long-term goals and objectives for effectively managing the Eastern Snake Plain Aquifer and ensuring that senior water rights are protected consistent with the prior appropriation doctrine and state law. As part of the interim agreement, the pending administrative and judicial processes were stayed until March 15, 2005, and the Idaho Legislature directed the Natural Resources Interim Committee, a standing committee, to meet and evaluate ways to stabilize and properly manage the aquifer. This Interim Committee met with interested parties from March through the fall of 2004 in an effort to resolve the pending controversies. One solution explored was aquifer recharge, or using surface water supplies to increase ground water supplies by allowing the water to sink into the earth in porous locations. Under certain circumstances aquifer recharge may impact senior water rights and therefore conflict with state law. In April 2005, the Idaho Legislature passed House Concurrent Resolution No. 28 directing the Natural Resources Interim Committee, along with the Idaho Water Resources Board, to continue to work with interested parties to develop a plan to implement an effective recharge program for the Eastern Snake Plain Aquifer along with recommendations for necessary legislative changes to implement and fund such a program. The Interim Committee held its first meeting to explore opportunities for implementing such a program in June 2005. Additional meetings are expected through 2005. IPC is participating in this process, as necessary, to protect its existing hydroelectric generation water rights.

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

Similar to the surface water irrigation entities, IPC holds storage rights in American Falls Reservoir. To the extent that groundwater pumping and the reduced surface water flows have impacted American Falls storage water rights, IPC's storage rights may have also been impacted. As such, IPC submitted a letter to the Idaho Department of Water Resources in support of the delivery call and asked the department to grant IPC intervenor status in the pending contested case. The Idaho Ground Water Appropriators, Inc. filed a motion opposing IPC's intervention. The department subsequently denied IPC's request for intervenor status. IPC has appealed the department's order denying intervention to the state district court. Although that appeal is pending, the administrative action before the department continues. A hearing is set for early January 2006. IPC continues to monitor the administrative action.

Due to the drought and low water conditions in Idaho over the past several years, several other actions have been initiated before the Idaho Department of Water Resources and the Snake Rive Adjudication District Court relating to the administration of water rights in Idaho. IPC is monitoring each of these actions and is taking such action as it believes is necessary to protect its water rights.

Clean Air: The Environmental Protection Agency 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 SO₂ allowances to provide compliance for emissions attributable to Idaho Power at all three of its jointly owned coal-fired facilities and both of its natural gas-fired facilities. Through 2005, and prior to the sale of 60,000 emission allowances in October 2005 discussed below in "Emission Allowances," IPC believed that it had approximately 107,000 allowances in excess of the amount needed for Clean Air Act compliance. In addition, IPC has been granted annual allotments of allowances ranging from 15,524 to 28,622 through the year 2035. Allowances necessary for IPC's compliance requirements are up to 14,500 annually. Excess allowances owned by IPC may be held for future use, as they do not contain expiration terms. There is an active marketplace for buying and selling allowances, so that SO₂allowances determined to be excess can be sold to others. For all the foregoing reasons, IPC does not foresee any adverse effects upon its operations with regard to SO₂ emissions at this time. Approval to sell excess allowances has been received from the IPUC and OPUC and sale activities have been initiated. See further discussion in "REGULATORY MATTERS - Emission Allowances."

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

The Clean Air Mercury Rule (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. The first phase cap is 38 tons beginning in 2010, with a second phase cap set at 15 tons beginning in 2018. Mercury emission allocations have been set at the state level, but the states have not allocated the allowances to individual utilities. IPC is actively observing developments on this issue and control equipment technology advances. It is anticipated that this rule may require additional emission controls and expenses at 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 CAMR is being challenged in court by a number of environmental groups and some states.

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

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

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

REGULATORY MATTERS:

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

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

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

Additionally, IPUC Order No. 29600 resolved outstanding issues related to: (1) an unplanned outage at one of the two units of Valmy in the summer of 2003, (2) a matter relating to the expense adjustment rate for growth component of the PCA and (3) regulatory accounting issues related to a tax accounting method change in 2002. As a result, in September 2004, IPC established a regulatory liability of $19 million with a charge to PCA expense. A monthly credit of approximately $0.8 million is included in the PCA through May 2006, which will reduce this regulatory liability. Also in September 2004, IPC reversed a $16 million regulatory tax liability by reducing income tax expense. This regulatory tax liability was established in 2002 when IPC adopted a tax accounting method change for capitalized overhead costs.

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

On October 28, 2005, IPC filed a new general rate case with the IPUC based upon a 2005 test year. IPC is asking for an annual increase to its Idaho retail base rates of $44 million, a 7.8 percent average increase. IPC cannot predict what level of rate adjustment, if any, the IPUC will grant.

Oregon: On September 21, 2004, IPC filed an application with the OPUC to increase general rates an average of 17.5 percent or approximately $4.4 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 on July 29, 2005 authorizing an increase of $597,000 in annual revenues for an average of 2.37 percent. The OPUC adopted the Staff 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.

IPUC Rate Proceedings
IPC has completed four rate proceedings before the IPUC during the first half of 2005: the rate case tax settlement adjustments, the Bennett Mountain Power Plant, the Energy Efficiency Tariff Rider and the 2005-2006 PCA. Increases related to these filings were effective June 1, 2005. The 2005-2006 PCA filing is discussed below in "Deferred Net Power Supply Costs - Idaho."

Energy Efficiency Tariff Rider: IPC charges an amount to each customer to provide funding for energy efficiency initiatives. In December 2004, IPC filed a request to increase this charge from 0.5 percent of total base revenues to 1.5 percent effective June 1, 2005, and 2.4 percent effective June 1, 2007. The June 1, 2005 change increases the annual amounts collected from customers by $5 million. The IPUC authorized the June 1, 2005 change while deferring judgment on the 2007 request.

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

		September 30,		December 31,
		2005		2004
Idaho PCA current year:
	Deferral for the 2005-2006 rate year	$	-	$	22,778
	Deferral for the 2006-2007 rate year		2,163		-
Irrigation Lost Revenues			-		13,290
Idaho PCA true-up awaiting recovery:
	Authorized May 2004		-		11,415
	Authorized May 2005*		34,893		-
Oregon deferral:
	2001 costs		10,536		12,047
	2005 costs		2,068		-
	Total deferral	$	49,660	$	59,530

*$28 million will be recovered with interest during the 2006-2007 PCA rate year.

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

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

On April 15, 2005, IPC filed the 2005-2006 PCA with the IPUC with a proposed effective date of June 1, 2005. The application proposed to hold the PCA component of customers' rates at the existing level, which is currently recovering $71 million above base rates. By IPUC order, this year's PCA includes $12 million in lost revenues and $2 million in related interest resulting from IPC's Irrigation Load Reduction Program that was in place in 2001. IPC proposed to defer approximately $28 million of power supply costs, or 4.75 percent, for one year to help mitigate the impacts of the $9 million, or 1.84 percent, increase for the Bennett Mountain Power Plant and the $23 million, or 4.45 percent, increase due to the rate case tax settlement adjustments. The $28 million will be recovered during the 2006-2007 PCA rate year, and IPC will earn a two percent carrying charge on this balance. The IPUC accepted the company's PCA proposal.

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

The IRP is filed every two years with both the IPUC and the OPUC. Prior to filing, the IRP requires extensive involvement by IPC, the IPUC Staff and the OPUC Staff, as well as customer, technological and environmental representatives and is the starting point for demonstrating prudence in IPC's resource decisions. The IPUC accepted the 2004 IRP on April 22, 2005. The OPUC acknowledged the 2004 IRP on June 17, 2005. Preparation has begun on the 2006 IRP with the initial meeting of the IRP Advisory Council held on October 20, 2005. The 2006 IRP is scheduled to be filed in June 2006.

Peaking Resource RFP: On March 30, 2005, IPC issued a formal Request for Proposal (RFP) seeking bids for the construction of an 88 MW natural gas-fired power plant. IPC sought bids for the construction of a turnkey generating facility to expand its generation capabilities during peak times when electricity supplies are low and wholesale costs are high. The plant was anticipated be on line in 2007. Bid proposals were received in June and the evaluation process is under way. Selection of the successful bid was originally scheduled for October 2005. However, a developer is proposing a large PURPA project that, if developed, will impact the need and timing of any resource acquired under the peaking resource RFP. Negotiations with the PURPA developer are ongoing. A decision regarding the acquisition of any peaking resources acquired under the peaking resource RFP is anticipated by early 2006.

Wind RFP: An RFP for 200 MW of wind-powered generation was issued on January 13, 2005. The RFP requested deliveries of energy from approximately 100 MW of wind-powered generation commencing no later than the end of 2006, and deliveries of energy from all 200 MW commencing no later than the end of 2007. The wind-powered generation RFP pre-bid meeting was held on January 27, 2005. Final bids were due on March 10, 2005. The selection committee has compiled a short list of bidders and suspended further action until the IPUC could process IPC's request for a moratorium on PURPA wind projects discussed below. In late September IPC announced that it would reactivate the RFP, although IPC now anticipates acquiring 100 MW through the process instead of the original 200 MW.

PURPA Wind Projects
As of October 2005, one 10.5 MW wind project (Fossil Gulch) is selling energy to IPC under an approved PURPA agreement and an additional eight wind projects, comprising 92 MW of wind generation, have approved PURPA agreements and are scheduled to come online by early 2006. Signed PURPA agreements for four additional wind projects, adding an additional 75 MW of wind generation, were submitted during October 2005 to the IPUC for approval.

On June 17, 2005, IPC filed an application requesting the IPUC to issue an order temporarily suspending IPC's obligation under PURPA and various IPUC orders, to enter into new contracts to purchase energy generated by wind powered qualifying facilities. IPC has requested the temporary suspension remain in effect until the IPUC investigates the impact on IPC's customers arising out of the addition of substantial amounts of wind-powered generation projects. IPC is concerned that the continuous absorption of additional wind resources will adversely affect IPC's overall power supply costs and system reliability. IPC is also concerned that the apparent high price for wind PURPA resources is impacting bid prices for the wind RFP. On July 8, 2005, IPC submitted testimony in support of the request. On July 22, 2005 the IPUC conducted a hearing on the matter and issued an order on August 4, 2005, reducing the published rate cap eligibility to 100 kW from 10 MW and setting grandfathering criteria for PURPA wind projects in progress at the time of the order. Currently, approximately 120 MW of proposed PURPA wind projects are actively seeking contracts from IPC through the grandfathering criteria, or via negotiated PURPA agreements. The outcome of these agreement requests is unknown at this time.

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

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

On September 2, 2004, two conservation groups, American Rivers and Idaho Rivers United, filed petitions for rehearing of the orders issuing the licenses for the middle Snake River projects. These petitions ask the FERC to vacate the licensing orders and request a determination from the U.S. Fish and Wildlife Service that the middle Snake River projects jeopardize the listed snail species. On October 4, 2004, the FERC issued an Order Granting Rehearing for Further Consideration to provide additional time to consider the matters raised by the rehearing requests. On March 4, 2005, the FERC issued an order denying the conservation groups' rehearing request. On April 28, 2005, American Rivers and Idaho Rivers United appealed this order to the U.S. Court of Appeals for the Ninth Circuit. 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. FERC's brief is due to be filed by December 16, 2005 and IPC's and Fish and Wildlife's briefs by January 27, 2006. American Rivers and Idaho Rivers United filed their briefs with the court on October 14, 2005, and pursuant to the court's recent order, may file an optional reply brief by February 27, 2006.

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

Many of the new license articles require IPC to develop comprehensive plans for Protection, Mitigation and Enhancement (PM&E) measures and submit them to the FERC for approval. The plans are due within six months to one year following license issuance and are required to have detailed costs, schedules and methods for implementing the PM&E measures. As of August 3, 2005, IPC had submitted these plans to the FERC, with the exception of two provisions for which the FERC has granted extensions until December 2005. IPC is also required to consult with certain parties that participated in the relicensing process including state and federal resource agencies, Native American Indian Tribes and non-governmental organizations (environmental and other organizations) prior to the completion of development and the filing of some of the plans. The FERC will then review and approve the plans, after which IPC will proceed with implementation of the planned PM&E measures.

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

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

At September 30, 2005, $9 million of middle Snake River project relicensing and compliance costs were in electric plant in service. The majority of these costs, which were incurred prior to the completion of IPC's 2003 Idaho general rate case, were approved for recovery in rates. Costs incurred since the 2003 general rate case are included in the 2005 general rate case filing. Future costs related to the new license will be submitted to regulators for recovery through the rate-making process.

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

At September 30, 2005, $3 million of Malad project relicensing costs were included in electric plant in service and are included in the 2005 general rate case filing. Future costs related to the new license will be submitted to regulators for recovery through the rate-making process.

Hells Canyon Complex: The most significant ongoing relicensing effort is the Hells Canyon Complex, which provides approximately two-thirds of IPC's hydroelectric generating capacity and 40 percent of its total generating capacity. The current license for the Hells Canyon Complex expired at the end of July 2005. IPC now operates the project under an annual license issued by the FERC until the new multi-year license is issued. 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.

The license application includes the continuation of existing, as well as proposed new measures intended to protect, mitigate and enhance fish and wildlife, protect recreational opportunities and preserve other aspects of environmental quality. The estimated costs of these PM&E measures, are approximately $106 million in the first five years of a license and $218 million over the following 25 years, for a total estimated cost of $324 million over a 30-year license. These cost estimates do not include estimated costs of proposed water quality measures included in the license application. These measures are the subject of ongoing state processes under Section 401 of the Clean Water Act. IPC estimates that costs associated with these water quality measures may result in an additional cost of $62 million, for a total estimated cost of $386 million. These estimated costs could increase as a result of the Hells Canyon ESA Consultation/Settlement Process (see discussion below).

In response to the filing of the license application in July 2003, federal and state agencies, Native American Indian Tribes and other participants in the Hells Canyon Complex relicensing process filed initial comments to the license application, some of which contained additional proposed PM&E measures. IPC's preliminary estimate of the potential cost of these additional proposed measures, assuming all of the proposed measures are included as conditions in a final license, which IPC believes is unlikely, totals more than $2 billion over a period up to 50 years. This would result in an approximate 25 to 30 percent increase to existing base rates. These cost estimates are preliminary as federal, state, tribal and private parties participating in the relicensing proceeding are not required to file their final comments, recommendations, terms, conditions and prescriptions with the FERC until later in the relicensing process. The FERC will then consider these final comments, recommendations, terms, conditions and prescriptions under the Federal Power Act, the National Environmental Policy Act of 1969, as amended (NEPA), the Energy Policy Act of 2005 and other applicable federal laws, and include those conditions in the final license that the FERC determines are necessary and required to protect, mitigate and enhance those resources affected by the operation and management of the project. Under the Federal Power Act, some federal agencies have mandatory conditioning authority. Section 18 of the FPA provides the Departments of Commerce and Interior with authority to require fishways, or passage facilities, to allow fish to migrate below and above a project. Section 4(e) allows federal agencies with jurisdiction over a federal reservation, such as a national forest or park that is occupied by a licensed project to require FERC to include in the license such conditions and prescriptions that the federal agency considers necessary for the adequate protection and utilization of that reservation. The FERC must include in the license those conditions and prescriptions proposed by these agencies, which fall within that agency's conditioning authority, under the FPA. These conditions and prescriptions, however, must be supported by substantial evidence and otherwise be in compliance with the provisions of the Energy Policy Act of 2005. If they are not, a federal appeals court may set the conditions and prescriptions aside. In other words, the agencies have the authority to require actions to be included in a license to protect resources or address issues under their jurisdiction. As such, the actual costs of the PM&E measures associated with the relicensing of the Hells Canyon Complex will not be known until after the new license is issued by the FERC.

At September 30, 2005, $73 million of Hells Canyon Complex relicensing costs were included in construction work in progress. The relicensing costs are recorded and held in construction work in progress until a new multi-year license is issued by the FERC, at which time the charges are transferred to electric plant in service. Relicensing costs and costs related to a new license, as discussed above, will be submitted to regulators for recovery through the rate-making process.

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

On October 20, 2003, the FERC issued Scoping Document 1 to provide interested parties with information on the relicensing of the project and solicit comments and suggestions for a preliminary list of issues and alternatives that might be addressed in the environmental impact statement. The FERC also held four scoping meetings in the fall and winter of 2003 to offer parties the opportunity for input on the scope of the environmental impact statement. Based upon comments and information received in response to Scoping Document 1, on November 24, 2004, the FERC Staff issued Scoping Document 2, which provides for a tentative schedule for the environmental impact statement preparation including the filing of additional information. Subsequent to the issuance of Scoping Document 2, IPC and a number of other parties participating in the Hells Canyon ESA Consultation/Settlement Process (see "Consultation/Settlement Process" discussion below) requested that the FERC revise the tentative schedule to enable the parties to pursue a comprehensive settlement agreement for the relicensing of the Hells Canyon Complex. Since September of 2004, IPC has been working with interested parties to reach an agreement in principle on the relicensing issues, which will inform and focus the FERC in its preparation of the draft environmental impact statement for the NEPA and relicensing process. To facilitate the settlement efforts, the FERC extended the schedule, most recently by letter dated August 10, 2005. The FERC issued the NREA on October 28, 2005 and established a 90-day period for comments and preliminary recommendations and conditions to be filed. The draft environmental impact statement is scheduled to be issued in May 2006.

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

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

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

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

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

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

After the filing of the Interim Agreement with the FERC, the Settlement Working Group, with the continuing assistance of the facilitator and separated FERC Staff, commenced negotiations on the long-term settlement agreement. These negotiations have continued and, due to the number and complexity of the issues, the parties to the settlement process have devoted substantial resources and time to the settlement effort. To date, however, the parties have not been successful in reaching an agreement in principle for the licensing of the Hells Canyon Complex. Because it was unlikely that the parties to the settlement process would reach agreement on a comprehensive settlement package in the near term and because of the issuance of the NREA by the FERC in October 2005, the settlement discussions have been terminated to allow the parties the opportunity to develop comments and preliminary terms and conditions to be filed with the FERC. The parties expect to reassess opportunities for settlement in the spring of 2006 after the filings with the FERC.

Swan Falls Project: The license for the Swan Falls hydroelectric project expires in 2010. On March 10, 2005 IPC initiated formal consultation with agencies, Indian tribes and the public regarding the relicensing of the Swan Falls project. This was done by providing interested stakeholders with detailed information on the Swan Falls project. In addition, a site tour and meeting for interested stakeholders was held on May 2, 2005. 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 September 30, 2005, $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 rate-making process.

Regional Transmission Organization
In December 1999, the FERC, in Order No. 2000, said that all companies with transmission assets must file with the FERC to form regional transmission organizations (RTOs) or explain why they cannot do so. By encouraging the formation of RTOs, the FERC sought to further facilitate the formation of efficient, competitive wholesale electricity markets. In response, several northwest utilities, including IPC, attempted formation of an RTO called RTO West. After the failure of RTO West, the utilities turned toward formation of Grid West, a transmission management entity that would not necessarily become an RTO. In a recent developmental action, the Bonneville Power Administration, PacifiCorp and IPC filed a request to the FERC for a declaratory order stipulating that Grid West need not be an RTO under FERC Order No. 2000. In an order issued July 1, 2005, the FERC acknowledged that Grid West would not need to satisfy their RTO requirements. The order also declared the Grid West governance to be sufficiently independent to satisfy the independence requirements of an RTO should Grid West decide to change its status in the future.

Grid West was to make a major decision in September 2005 on whether to transfer corporate control to a new independent governing board and provide continued developmental funding. This "Decision Point 2" was to be the second of four Decision Points needed to bring Grid West into operation. The Bonneville Power Administration sought and received a 30-day extension to explore the viability of an alternate to Grid West that they characterized as the "Convergence Proposal." At Decision Point 2, on November 1, 2005, the Bonneville Power Administration decided to commit additional funding only to a "Convergence Proposal" and not to the original Grid West proposed plan. A majority of the Grid West board did not accept the "Convergence Proposal" as being viable. This prevented seating of the independent governing board and the decision was made to restructure Grid West to allow those supporting Grid West to continue in its development.

IPC has spent funds supporting the development of Grid West, and expects to continue funding this development as long as it remains a participating utility. Funding of this effort has taken two forms. First, funds have been loaned to Grid West, for the purpose of meeting its developmental expenses. The total accumulated loan through the third quarter of 2005 was approximately $1.0 million. IPC expects this loan to be repaid by Grid West when it commences operation. Second, IPC has incurred incremental internal costs from participating in the developmental effort, which are mostly related to incremental travel and legal consultation. Prior to 2005, IPC had accumulated these costs in deferred expense accounts. The total accumulated internal expense through the fourth quarter of 2004 was approximately $2.3 million. In recognition of the affirmative vote at the end of 2004 at "Decision Point 1" which was the first step to move Grid West into operation, IPC decided that beginning in 2005, all additional incremental costs related to Grid West development activities would be expensed rather than deferred. At this time, IPC expects to pursue recovery of the accumulated internal costs through rates.

OTHER MATTERS:

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

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

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

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

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

IDACORP and IPC are exposed to 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 September 30, 2005.

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 September 30, 2005, IDACORP and IPC had $169 million and $115 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 September 30, 2005, interest expense for the year ending December 31, 2005 would increase and pre-tax earnings would decrease by approximately $2 million for IDACORP and $1 million for IPC.

Fixed Rate Debt: As of September 30, 2005, IDACORP and IPC had outstanding fixed rate debt of $926 million and $865 million, respectively. The fair market value of this debt was $947 million and $885 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 $86 million for IDACORP and $84 million for IPC if interest rates were to decline by one percentage point from their September 30, 2005 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, 2004.

Credit Risk
Utility: IPC's credit risk has not changed materially from that reported in the Annual Report on Form 10-K for the year ended December 31, 2004.

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

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

ITEM 4. CONTROLS AND PROCEDURES

Evaluation of disclosure controls and procedures:

IDACORP:
The Chief Executive Officer and the Acting Chief Financial Officer of IDACORP, based on their evaluation of IDACORP's disclosure controls and procedures (as defined in Exchange Act Rule 13a-15(e)) as of September 30, 2005, have concluded that IDACORP's disclosure controls and procedures are effective.

IPC:
The Chief Executive Officer and the Acting Chief Financial Officer of IPC, based on their evaluation of IPC's disclosure controls and procedures (as defined in Exchange Act Rule 13a-15(e)) as of September 30, 2005, have concluded that IPC's disclosure controls and procedures are effective.

Changes in internal control over financial reporting:

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

PART II - OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS

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

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 September 30, 2005, the leverage ratios for both IDACORP and IPC were 52 percent.

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

ITEM 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	Employment Agreement, dated November 24, 2004, by and between IDACORP, Inc. and Luci K. McDonald. File number 1-14465, 1-3198, Form 8-K, filed on 11/30/04, as Exhibit 10.

*10(h)(xvi)1	Consulting agreement, dated as of January 3, 2005, by and between Robert W. Stahman and IPC, including its parent IDACORP, Inc. and all subsidiaries and affiliates. File number 1-14465, 1-3198, Form 8-K, filed on 1/4/05, as Exhibit 10.

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

*10(h)(xxii) 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)(xxiii)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)(xxiv) 1	IDACORP, Inc. 2004 Executive Incentive Plan. File number 1-14465, 1-3198, Form 8-K, filed on 2/18/05, as Exhibit 10.1.

*10(h)(xxv)1	IDACORP, Inc. 2004 Executive Incentive Plan NEO Incentive Chart. File number 1-14465, 1-3198, Form 8-K, filed on 2/18/05, as Exhibit 10.2.

*10(i)	Framework Agreement, dated October 1, 1984, between the State of Idaho and IPC relating to IPC's Swan Falls and Snake River water rights. File number 33-65720, 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 third quarter 2005.

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	November 3, 2005	By:	/s/	Jan B. Packwood
				Jan B. Packwood
				President and Chief Executive Officer

Date	November 3, 2005	By:	/s/	Lori D. Smith
				Lori D. Smith
				Acting Chief Financial Officer

IDAHO POWER COMPANY

(Registrant)

Date	November 3, 2005	By:	/s/	J. LaMont Keen
				J. LaMont Keen
				President and Chief Operating Officer

Date	November 3, 2005	By:	/s/	Lori D. Smith
				Lori D. Smith
				Acting Chief Financial Officer

EXHIBIT INDEX


Exhibit Number

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

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

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

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

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

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

15		Letter Re: Unaudited Interim Financial Information.

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

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

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

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

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

32(b)		Section 1350 certification. (IPC)

99		Earnings press release for third quarter 2005.

	Exact name of registrants as specified	I.R.S. Employer
Commission File	in their charters, address of principal	Identification
Number	executive offices, zip code and telephone number	Number
1-14465	IDACORP, Inc.	82-0505802
1-3198	Idaho Power Company	82-0130980
	1221 W. Idaho Street
	Boise, ID 83702-5627
	(208) 388-2200
	State of Incorporation: Idaho
	Websites: www.idacorpinc.com
www.idahopower.com

None

IDACORP, Inc.:	42,322,113
Idaho Power Company:	39,150,812, all held by IDACORP, Inc.

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

COMMONLY USED TERMS

Cal ISO	-	California Independent System Operator
CalPX	-	California Power Exchange
EPS	-	Earnings per share
FASB	-	Financial Accounting Standards Board
FERC	-	Federal Energy Regulatory Commission
FIN	-	Financial Accounting Standards Board Interpretation
FSP	-	Financial Accounting Standards Board Staff Position
IE	-	IDACORP Energy, a non-operating subsidiary of IDACORP, Inc.
IFS	-	IDACORP Financial Services, a subsidiary of IDACORP, Inc.
IPC	-	Idaho Power Company, a subsidiary of IDACORP, Inc.
IPUC	-	Idaho Public Utilities Commission
IRP	-	Integrated Resource Plan
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
NREA	-	Notice of Ready for Environmental Analysis
OPUC	-	Oregon Public Utility Commission
PCA	-	Power Cost Adjustment
PURPA	-	Public Utility Regulatory Policies Act of 1978
RTO	-	Regional Transmission Organization
S&P	-	Standard & Poor's Ratings Services
SFAS	-	Statement of Financial Accounting Standards
SO₂	-	Sulfur Dioxide

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		14-33
		Reports of Independent Registered Public Accounting Firm		34-35

	Item 2. Management's Discussion and Analysis of Financial
		Condition and Results of Operations		36-66

	Item 3. Quantitative and Qualitative Disclosures About Market Risk			66-67

	Item 4. Controls and Procedures			67

Part II. Other Information:

	Item 1. Legal Proceedings			68

	Item 2. Unregistered Sales of Equity Securities and Use of Proceeds			68

	Item 6. Exhibits			68-74

Signatures				75

Three Months Ended

Nine Months Ended