Edgar Filing: IDACORP INC

UNITED STATES SECURITIES AND EXCHANGE COMMISSION

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

(Mark One)

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

EXCHANGE ACT OF 1934

For the quarterly period ended June 30, 2007

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

For the transition period from

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

None

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

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

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

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

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

Number of shares of Common Stock outstanding as of June 30, 2007:

IDACORP, Inc.:	44,303,372
Idaho Power Company:	39,150,812, all held by IDACORP, Inc.

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

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

COMMONLY USED TERMS

AFDC	-	Allowance for Funds Used During Construction
Cal ISO	-	California Independent System Operator
CalPX	-	California Power Exchange
CAMP	-	Comprehensive Aquifer Management Plan
cfs	-	Cubic feet per second
DSM	-	Demand Side Management
Energy Act	-	Energy Policy Act of 2005
EPS	-	Earnings per share
ESA	-	Endangered Species Act
ESPA	-	Eastern Snake Plain Aquifer
FASB	-	Financial Accounting Standards Board
FERC	-	Federal Energy Regulatory Commission
FIN	-	Financial Accounting Standards Board Interpretation
Fitch	-	Fitch, Inc.
FPA	-	Federal Power Act
GAAP	-	Generally Accepted Accounting Principles in the United States of America
Ida-West	-	Ida-West Energy, a subsidiary of IDACORP, Inc.
IDEQ	-	Idaho Department of Environmental Quality
IDWR	-	Idaho Department of Water Resources
IE	-	IDACORP Energy, a subsidiary of IDACORP, Inc.
IERCO	-	Idaho Energy Resources Co.
IFS	-	IDACORP Financial Services, a subsidiary of IDACORP, Inc.
IPC	-	Idaho Power Company, a subsidiary of IDACORP, Inc.
IPUC	-	Idaho Public Utilities Commission
IRP	-	Integrated Resource Plan
ITI	-	IDACORP Technologies, Inc.
IWRB	-	Idaho Water Resource Board
kW	-	Kilowatt
maf	-	Million acre feet
MD&A	-	Management's Discussion and Analysis of Financial Condition and Results of
			Operations
Moody's	-	Moody's Investors Service
MW	-	Megawatt
MWh	-	Megawatt-hour
NEPA	-	National Environmental Policy Act of 1996
O & M	-	Operations and Maintenance
OPUC	-	Oregon Public Utility Commission
PCA	-	Power Cost Adjustment
PM&E	-	Protection, Mitigation and Enhancement
PURPA	-	Public Utility Regulatory Policies Act of 1978
RFP	-	Request for Proposal
RTO	-	Regional Transmission Organization
S&P	-	Standard & Poor's Ratings Services
SFAS	-	Statement of Financial Accounting Standards
SO₂	-	Sulfur Dioxide
SRBA	-	Snake River Basin Adjudication
Valmy	-	North Valmy Steam Electric Generating Plant
VIEs	-	Variable Interest Entities

Table of Contents

TABLE OF CONTENTS

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		14-26
		Reports of Independent Registered Public Accounting Firm		27-28

	Item 2. Management's Discussion and Analysis of Financial
		Condition and Results of Operations		29-52

	Item 3. Quantitative and Qualitative Disclosures About Market Risk			53

	Item 4. Controls and Procedures			53-54

Part II. Other Information:

	Item 1. Legal Proceedings			54

	Item 1A. Risk Factors			54

	Item 2. Unregistered Sales of Equity Securities and Use of Proceeds			54-55

	Item 4. Submission of Matters to a Vote of Security Holders			55

	Item 6. Exhibits			56-61

Signatures				62

Exhibit Index				63

SAFE HARBOR STATEMENT

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

Table of Contents

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

	Three months ended
	June 30,
	2007		2006
	(thousands of dollars except
Operating Revenues:	for per share amounts)
Electric utility:
General business	$	162,212	$	159,210
Off-system sales	37,177		75,598
Other revenues	13,137		6,040
Total electric utility revenues	212,526		240,848
Other	1,246		1,787
Total operating revenues	213,772		242,635
Operating Expenses:
Electric utility:
Purchased power	80,467		74,808
Fuel expense	27,520		21,954
Power cost adjustment	(42,172)		4,600
Other operations and maintenance	78,888		69,840
Demand-side management	2,548		-
Gain on sale of emission allowances	(882)		(8,126)
Depreciation	25,613		24,633
Taxes other than income taxes	4,636		6,329
Total electric utility expenses	176,618		194,038
Other expense	582		3,046
Total operating expenses	177,200		197,084
Operating Income (Loss):
Electric utility	35,908		46,810
Other	664		(1,259)
Total operating income	36,572		45,551
Other Income	3,862		5,080
Losses of Unconsolidated Equity-Method Investments	(1,551)		(2,208)
Other Expense	1,571		2,655
Interest Expense:
Interest on long-term debt	13,896		14,200
Other interest	1,514		1,175
Total interest expense	15,410		15,375
Income Before Income Taxes	21,902		30,393
Income Tax Expense	3,437		7,720
Income from Continuing Operations	18,465		22,673
Income (Losses) from Discontinued Operations, net of tax	-		(2,817)
Net Income	$	18,465	$	19,856
Weighted Average Common Shares Outstanding - Basic (000's)	43,751		42,557
Weighted Average Common Shares Outstanding - Diluted (000's)	43,884		42,702
Earnings Per Share of Common Stock (basic and diluted):
Earnings per share from Continuing Operations	$	0.42	$	0.53
Earnings (losses) per share from Discontinued Operations	-		(0.06)
Earnings Per Share of Common Stock	$	0.42	$	0.47
Dividends Paid Per Share of Common Stock	$	0.30	$	0.30

The accompanying notes are an integral part of these statements.

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

	Six months ended
	June 30,
	2007		2006
Operating Revenues:	(thousands of dollars except
Electric utility:	for per share amounts)
General business	$	299,463	$	321,393
Off-system sales	95,016		179,839
Other revenues	23,976		6,890
Total electric utility revenues	418,455		508,122
Other	2,029		2,853
Total operating revenues	420,484		510,975
Operating Expenses:
Electric utility:
Purchased power	131,285		130,733
Fuel expense	58,432		48,923
Power cost adjustment	(63,708)		48,067
Other operations and maintenance	146,715		131,513
Demand-side management	4,663		-
Gain on sale of emission allowances	(882)		(8,235)
Depreciation	50,903		49,182
Taxes other than income taxes	9,554		11,900
Total electric utility expenses	336,962		412,083
Other expense	3,170		6,863
Total operating expenses	340,132		418,946
Operating Income (Loss):
Electric utility	81,493		96,039
Other	(1,141)		(4,010)
Total operating income	80,352		92,029
Other Income	9,251		9,749
Losses of Unconsolidated Equity-Method Investments	(2,877)		(2,259)
Other Expense	4,782		4,076
Interest Expense:
Interest on long-term debt	27,444		28,284
Other interest	3,118		2,204
Total interest expense	30,562		30,488
Income Before Income Taxes	51,382		64,955
Income Tax Expense	8,336		15,327
Income from Continuing Operations	43,046		49,628
Income (Losses) from Discontinued Operations, net of tax	67		(4,296)
Net Income	$	43,113	$	45,332
Weighted Average Common Shares Outstanding - Basic (000's)	43,709		42,515
Weighted Average Common Shares Outstanding - Diluted (000's)	43,845		42,642
Earnings Per Share of Common Stock:
Earnings per share from Continuing Operations-Basic	$	0.99	$	1.17
Earnings (losses) per share from Discontinued Operations-Basic	-		(0.10)
Earnings Per Share of Common Stock-Basic	$	0.99	$	1.07
Earnings per share from Continuing Operations-Diluted	$	0.98	$	1.16
Earnings (losses) per share from Discontinued Operations-Diluted	-		(0.10)
Earnings Per Share of Common Stock-Diluted	$	0.98	$	1.06
Dividends Paid Per Share of Common Stock	$	0.60	$	0.60
The accompanying notes are an integral part of these statements.

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IDACORP, Inc.
Condensed Consolidated Balance Sheets
(unaudited)

	June 30,		December 31,
	2007		2006
Assets	(thousands of dollars)

Current Assets:
Cash and cash equivalents	$	12,464	$	9,892
Receivables:
Customer	64,318		62,131
Allowance for uncollectible accounts	(7,087)		(7,168)
Employee notes	2,338		2,569
Other	10,732		11,855
Energy marketing assets	9,533		12,069
Accrued unbilled revenues	42,823		31,365
Materials and supplies (at average cost)	42,370		39,079
Fuel stock (at average cost)	15,902		15,174
Prepayments	8,269		9,308
Taxes receivable	9,181		-
Deferred income taxes	31,357		28,035
Regulatory assets	1,309		1,480
Refundable income tax deposit	44,903		44,903
Other	3,581		2,513
Assets held for sale	-		3,326
Total current assets	291,993		266,531

Investments	200,430		202,825

Property, Plant and Equipment:
Utility plant in service	3,651,623		3,583,694
Accumulated provision for depreciation	(1,446,131)		(1,406,210)
Utility plant in service - net	2,205,492		2,177,484
Construction work in progress	264,585		210,094
Utility plant held for future use	3,137		2,810
Other property, net of accumulated depreciation	28,377		28,692
Property, plant and equipment - net	2,501,591		2,419,080

Other Assets:
American Falls and Milner water rights	30,022		30,543
Company-owned life insurance	32,604		34,055
Regulatory assets	426,398		423,548
Long-term receivables (net of allowance of $1,878)	3,583		3,802
Employee notes	2,310		2,411
Other	43,385		41,259
Assets held for sale	-		21,076
Total other assets	538,302		556,694

Total	$	3,532,316	$	3,445,130

The accompanying notes are an integral part of these statements.

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IDACORP, Inc.
Condensed Consolidated Balance Sheets
(unaudited)

	June 30,		December 31,
	2007		2006
Liabilities and Shareholders' Equity	(thousands of dollars)

Current Liabilities:
Current maturities of long-term debt	$	91,310	$	95,125
Notes payable	86,900		129,000
Accounts payable	85,602		86,440
Energy marketing liabilities	10,842		13,532
Taxes accrued	-		47,402
Interest accrued	18,960		12,657
Other	54,745		23,572
Liabilities held for sale	-		2,606
Total current liabilities	348,359		410,334

Other Liabilities:
Deferred income taxes	475,115		498,512
Regulatory liabilities	278,597		294,844
Other	196,148		179,836
Liabilities held for sale	-		8,773
Total other liabilities	949,860		981,965

Long-Term Debt	1,064,603		928,648

Commitments and Contingencies (Note 5)

Shareholders' Equity:
Common stock, no par value (shares authorized 120,000,000;
44,304,643 and 43,905,458 shares issued, respectively)	650,149		638,799
Retained earnings	525,266		493,363
Accumulated other comprehensive loss	(5,913)		(5,737)
Treasury stock (1,271 and 71,570 shares at cost, respectively)	(8)		(2,242)
Total shareholders' equity	1,169,494		1,124,183

Total	$	3,532,316	$	3,445,130

The accompanying notes are an integral part of these statements.

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

	Six Months Ended
	June 30,
	2007		2006
	(thousands of dollars)
Operating Activities:
Net income	$	43,113	$	45,332
Adjustments to reconcile net income to net cash provided by
operating activities:
Depreciation and amortization	60,397		60,339
Deferred income taxes and investment tax credits	18,760		(35,056)
Changes in regulatory assets and liabilities	(65,257)		61,143
Undistributed earnings of subsidiaries	(2,922)		(4,607)
Gain on sale of assets	(2,687)		(7,547)
Other non-cash adjustments to net income	4,564		(1,957)
Change in:
Accounts receivable and prepayments	(3,001)		26,095
Accounts payable and other accrued liabilities	(3,548)		(10,470)
Taxes accrued	(12,582)		14,317
Other current assets	(15,402)		(8,416)
Other current liabilities	11,160		10,003
Other assets	568		(2,345)
Other liabilities	8,300		(317)
Net cash provided by operating activities	41,463		146,514
Investing Activities:
Additions to property, plant and equipment	(122,179)		(102,465)
Proceeds from the sale of IDACOMM	7,283		-
Investments in affordable housing	300		-
Proceeds from the sale of emission allowances	2,685		10,865
Investments in unconsolidated affiliates	(3,600)		(11,520)
Purchase of available-for-sale securities	(24,349)		(9,428)
Proceeds from the sale of available-for-sale securities	25,296		10,607
Purchase of held-to-maturity securities	(1,325)		(1,245)
Maturity of held-to-maturity securities	1,730		981
Other assets	1,377		857
Net cash used in investing activities	(112,782)		(101,348)
Financing Activities:
Issuance of long-term debt	140,000		-
Retirement of long-term debt	(7,650)		(7,901)
Dividends on common stock	(26,286)		(25,521)
Net change in short-term borrowings	(42,100)		(14,900)
Issuance of common stock	12,451		4,816
Acquisition of treasury stock	(346)		-
Other	(2,178)		(145)
Net cash provided by (used in) financing activities	73,891		(43,651)
Net increase in cash and cash equivalents	2,572		1,515
Cash and cash equivalents at beginning of period	9,892		52,356
Cash and cash equivalents at end of period	$	12,464	$	53,871
Supplemental Disclosure of Cash Flow Information:
Cash paid during the period for:
Income taxes	$	3,314	$	34,623
Interest (net of amount capitalized)	$	29,342	$	29,317
Non-cash investing activities
Additions to property, plant and equipment in accounts payable	$	9,878	$	9,481
The accompanying notes are an integral part of these statements.

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

	Three Months Ended
	June 30,
	2007		2006
	(thousands of dollars)

Net Income	$	18,465	$	19,856

Other Comprehensive Income (Loss):
Unrealized gains (losses) on securities:
Unrealized holding gains (losses) arising during the period,
net of tax of $425 and ($523)	662		(922)
Reclassification adjustment for gains included
in net income, net of tax of $0 and ($512)	-		(798)
Net unrealized gains (losses)	662		(1,720)
Unfunded pension liability adjustment, net of tax
of $72 and $0	113		-
Total Comprehensive Income	$	19,240	$	18,136

The accompanying notes are an integral part of these statements.

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

	Six Months Ended
	June 30,
	2007		2006
	(thousands of dollars)

Net Income	$	43,113	$	45,332

Other Comprehensive Income (Loss):
Unrealized gains (losses) on securities:
Unrealized holding gains (losses) arising during the period,
net of tax of $304 and ($65)	473		(248)
Reclassification adjustment for gains included
in net income, net of tax of ($561) and ($730)	(874)		(1,138)
Net unrealized gains (losses)	(401)		(1,386)
Unfunded pension liability adjustment, net of tax
of $145 and $0	225		-
Total Comprehensive Income	$	42,937	$	43,946

The accompanying notes are an integral part of these statements.

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Idaho Power Company
Condensed Consolidated Statements of Income
(unaudited)

	Three Months Ended
	June 30,
	2007		2006
	(thousands of dollars)
Operating Revenues:
General business	$	162,212	$	159,210
Off-system sales	37,177		75,598
Other revenues	13,137		6,040
Total operating revenues	212,526		240,848

Operating Expenses:
Operation:
Purchased power	80,467		74,808
Fuel expense	27,520		21,954
Power cost adjustment	(42,172)		4,600
Other	55,242		48,200
Demand-side management	2,548		-
Gain on sale of emission allowances	(882)		(8,126)
Maintenance	23,646		21,640
Depreciation	25,613		24,633
Taxes other than income taxes	4,636		6,329
Total operating expenses	176,618		194,038

Income from Operations	35,908		46,810

Other Income (Expense):
Allowance for equity funds used during construction	1,374		1,646
Earnings of unconsolidated equity-method investments	544		491
Other income	2,155		3,030
Other expense	(1,558)		(2,580)
Total other income	2,515		2,587

Interest Charges:
Interest on long-term debt	13,387		13,531
Other interest	2,484		1,358
Allowance for borrowed funds used during construction	(1,915)		(941)
Total interest charges	13,956		13,948

Income Before Income Taxes	24,467		35,449

Income Tax Expense	8,303		13,837

Net Income	$	16,164	$	21,612

The accompanying notes are an integral part of these statements.

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Idaho Power Company
Condensed Consolidated Statements of Income
(unaudited)

	Six Months Ended
	June 30,
	2007		2006
	(thousands of dollars)
Operating Revenues:
General business	$	299,463	$	321,393
Off-system sales	95,016		179,839
Other revenues	23,976		6,890
Total operating revenues	418,455		508,122

Operating Expenses:
Operation:
Purchased power	131,285		130,733
Fuel expense	58,432		48,923
Power cost adjustment	(63,708)		48,067
Other	107,447		96,079
Demand-side management	4,663		-
Gain on sale of emission allowances	(882)		(8,235)
Maintenance	39,268		35,434
Depreciation	50,903		49,182
Taxes other than income taxes	9,554		11,900
Total operating expenses	336,962		412,083

Income from Operations	81,493		96,039

Other Income (Expense):
Allowance for equity funds used during construction	2,778		3,110
Earnings of unconsolidated equity-method investments	2,079		3,804
Other income	5,858		5,916
Other expense	(4,432)		(4,257)
Total other income	6,283		8,573

Interest Charges:
Interest on long-term debt	26,471		26,931
Other interest	4,658		2,464
Allowance for borrowed funds used during construction	(3,454)		(1,786)
Total interest charges	27,675		27,609

Income Before Income Taxes	60,101		77,003

Income Tax Expense	20,606		30,370

Net Income	$	39,495	$	46,633

The accompanying notes are an integral part of these statements.

Table of Contents

Idaho Power Company
Condensed Consolidated Balance Sheets
(unaudited)

	June 30,		December 31,
	2007		2006
Assets	(thousands of dollars)

Electric Plant:
In service (at original cost)	$	3,651,623	$	3,583,694
Accumulated provision for depreciation	(1,446,131)		(1,406,210)
In service - net	2,205,492		2,177,484
Construction work in progress	264,585		210,094
Held for future use	3,137		2,810
Electric plant - net	2,473,214		2,390,388

Investments and Other Property	96,117		91,244

Current Assets:
Cash and cash equivalents	3,719		2,404
Receivables:
Customer	57,273		54,218
Allowance for uncollectible accounts	(887)		(968)
Notes	448		514
Employee notes	2,338		2,569
Other	6,776		10,592
Accrued unbilled revenues	42,823		31,365
Materials and supplies (at average cost)	42,370		39,078
Fuel stock (at average cost)	15,902		15,174
Prepayments	7,861		8,952
Taxes receivable	426		-
Deferred income taxes	3,899		-
Regulatory assets	1,309		1,480
Other	342		-
Total current assets	184,599		165,378

Deferred Debits:
American Falls and Milner water rights	30,022		30,543
Company-owned life insurance	32,604		34,055
Regulatory assets	426,398		423,548
Employee notes	2,310		2,411
Other	42,002		40,158
Total deferred debits	533,336		530,715

Total	$	3,287,266	$	3,177,725

The accompanying notes are an integral part of these statements.

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Idaho Power Company
Condensed Consolidated Balance Sheets
(unaudited)

	June 30,		December 31,
	2007		2006
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	530,758		530,758
Capital stock expense	(2,097)		(2,097)
Retained earnings	432,495		404,076
Accumulated other comprehensive loss	(5,913)		(5,737)
Total common stock equity	1,053,120		1,024,877

Long-term debt	1,041,656		902,884
Total capitalization	2,094,776		1,927,761

Current Liabilities:
Long-term debt due within one year	81,064		81,064
Notes payable	22,000		52,200
Accounts payable	85,054		85,714
Notes and accounts payable to related parties	1,778		1,111
Taxes accrued	-		41,688
Interest accrued	18,608		12,324
Deferred income taxes	-		17
Other	54,663		24,367
Total current liabilities	263,167		298,485

Deferred Credits:
Deferred income taxes	464,522		489,234
Regulatory liabilities	278,597		294,844
Other	186,204		167,401
Total deferred credits	929,323		951,479

Commitments and Contingencies (Note 5)

Total	$	3,287,266	$	3,177,725

The accompanying notes are an integral part of these statements.

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Idaho Power Company
Condensed Consolidated Statements of Capitalization
(unaudited)

	June 30,			December 31,
	2007		%	2006		%
	(thousands of dollars)
Common Stock Equity:
Common stock	$	97,877		$	97,877
Premium on capital stock	530,758			530,758
Capital stock expense	(2,097)			(2,097)
Retained earnings	432,495			404,076
Accumulated other comprehensive loss	(5,913)			(5,737)
Total common stock equity	1,053,120		50	1,024,877		53

Long-Term Debt:
First mortgage bonds:
7.38% Series due 2007	80,000			80,000
7.20% Series due 2009	80,000			80,000
6.60% Series due 2011	120,000			120,000
4.75% Series due 2012	100,000			100,000
4.25% Series due 2013	70,000			70,000
6 % Series due 2032	100,000			100,000
5.50% Series due 2033	70,000			70,000
5.50% Series due 2034	50,000			50,000
5.875% Series due 2034	55,000			55,000
5.30% Series due 2035	60,000			60,000
6.30% Series due 2037	140,000			-
Total first mortgage bonds	925,000			785,000
Amount due within one year	(80,000)			(80,000)
Net first mortgage bonds	845,000			705,000

Pollution control revenue bonds:
Variable Auction Rate Series 2003 due 2024	49,800			49,800
Variable Auction Rate Series 2006 due 2026	116,300			116,300
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	10,636			11,700
Note guarantee due within one year	(1,064)			(1,064)
Unamortized premium/discount - net	(3,261)			(3,097)

Total long-term debt	1,041,656		50	902,884		47

Total Capitalization	$	2,094,776	100	$	1,927,761	100

The accompanying notes are an integral part of these statements.

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

	Six Months Ended
	June 30,
	2007		2006
	(thousands of dollars)
Operating Activities:
Net income	$	39,495	$	46,633
Adjustments to reconcile net income to net cash provided by
operating activities:
Depreciation and amortization	54,487		50,891
Deferred income taxes and investment tax credits	16,671		(34,564)
Changes in regulatory assets and liabilities	(65,257)		61,143
Undistributed earnings of subsidiary	(2,079)		(3,804)
Gain on sale of assets	(2,519)		(7,800)
Other non-cash adjustments to net income	3,008		(3,242)
Change in:
Accounts receivables and prepayments	(4,843)		4,954
Accounts payable	(2,239)		(9,624)
Taxes accrued	(1,094)		9,628
Other current assets	(15,478)		(8,402)
Other current liabilities	11,141		10,837
Other assets	524		(2,082)
Other liabilities	8,943		1,412
Net cash provided by operating activities	40,760		115,980
Investing Activities:
Additions to utility plant	(121,673)		(101,149)
Purchase of available-for-sale securities	(24,349)		(9,428)
Proceeds from the sale of available-for-sale securities	25,296		10,607
Proceeds from the sale of emission allowances	2,685		10,865
Investments in unconsolidated affiliate	(3,600)		(11,520)
Other assets	1,378		873
Net cash used in investing activities	(120,263)		(99,752)
Financing Activities:
Issuance of long-term debt	140,000		-
Retirement of long-term debt	(1,064)		-
Dividends on common stock	(26,212)		(25,487)
Net change in short term borrowings	(30,200)		-
Other	(1,706)		25
Net cash provided by (used in) financing activities	80,818		(25,462)
Net increase (decrease) in cash and cash equivalents	1,315		(9,234)
Cash and cash equivalents at beginning of period	2,404		49,335
Cash and cash equivalents at end of period	$	3,719	$	40,101
Supplemental Disclosure of Cash Flow Information:
Cash paid during the period for:
Income taxes paid to parent	$	6,236	$	56,717
Interest (net of amount capitalized)	$	26,493	$	26,357
Non-cash investing activities:
Additions to utility plant in accounts payable	$	9,878	$	9,481
The accompanying notes are an integral part of these statements.

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

	Three Months Ended
	June 30,
	2007		2006
	(thousands of dollars)

Net Income	$	16,164	$	21,612

Other Comprehensive Income (Loss):
Unrealized gains (losses) on securities:
Unrealized holding gains (losses) arising during the period,
net of tax of $425 and ($523)	662		(922)
Reclassification adjustment for gains included
in net income, net of tax of $0 and ($512)	-		(798)
Net unrealized gains (losses)	662		(1,720)
Unfunded pension liability adjustment, net of tax
of $72 and $0	113		-
Total Comprehensive Income	$	16,939	$	19,892

The accompanying notes are an integral part of these statements.

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

	Six Months Ended
	June 30,
	2007		2006
	(thousands of dollars)

Net Income	$	39,495	$	46,633

Other Comprehensive Income (Loss):
Unrealized gains (losses) on securities:
Unrealized holding gains (losses) arising during the period,
net of tax of $304 and ($65)	473		(248)
Reclassification adjustment for gains included
in net income, net of tax of ($561) and ($730)	(874)		(1,138)
Net unrealized gains (losses)	(401)		(1,386)
Unfunded pension liability adjustment, net of tax
of $145 and $0	225		-
Total Comprehensive Income	$	39,319	$	45,247

The accompanying notes are an integral part of these statements.

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IDACORP, INC. AND IDAHO POWER COMPANY
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(unaudited)

1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES:

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

Nature of Business
IDACORP is a holding company formed in 1998 whose principal operating subsidiary is IPC. IDACORP is subject to the provisions of the Public Utility Holding Company Act of 2005, which provides certain access to books and records to the Federal Energy Regulatory Commission (FERC) and state utility regulatory commissions and imposes certain record retention and reporting requirements on IDACORP.

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

IDACORP's other subsidiaries include:

IDACORP Financial Services, Inc. (IFS), an investor in affordable housing and other real estate investments;
Ida-West Energy Company (Ida-West), an operator of small hydroelectric generation projects that satisfy the requirements of the Public Utility Regulatory Policies Act of 1978 (PURPA); and
IDACORP Energy (IE), a marketer of energy commodities, which wound down operations in 2003.

On July 20, 2006, IDACORP completed the sale of all of the outstanding common stock of IDACORP Technologies, Inc. (ITI) to IdaTech UK Limited, a wholly-owned subsidiary of Investec Group Investments (UK) Limited. On February 23, 2007, IDACORP completed the sale of all of the outstanding common stock of IDACOMM, Inc. (IDACOMM) to American Fiber Systems, Inc. The results of operations of ITI and IDACOMM are reported as discontinued operations. See Note 9 for further discussion of discontinued operations.

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

Through IFS, IDACORP also holds significant variable interests in VIEs for which it is not the primary beneficiary. These VIEs are historic rehabilitation and affordable housing developments in which IFS holds limited partnership interests ranging up to 99 percent. These investments were acquired between 1996 and 2006. IFS' maximum exposure to loss in these developments was $84 million at June 30, 2007.

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Financial Statements
In the opinion of IDACORP and IPC, the accompanying unaudited condensed consolidated financial statements contain all adjustments necessary to present fairly their consolidated financial positions as of June 30, 2007, and consolidated results of operations for the three and six months ended June 30, 2007 and 2006, and consolidated cash flows for the six months ended June 30, 2007 and 2006. These adjustments are of a normal and recurring nature. These financial statements do not contain the complete detail or footnote disclosure concerning accounting policies and other matters that would be included in full-year financial statements and therefore they should be read in conjunction with the audited consolidated financial statements included in IDACORP's and IPC's Annual Report on Form 10-K for the year ended December 31, 2006. 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 following table presents the computation of IDACORP's basic and diluted earnings per share from continuing operations for the three and six months ended June 30, 2007 and 2006 (in thousands, except for per share amounts):

						Three months ended				Six months ended
						June 30,				June 30,
						2007		2006		2007		2006

Numerator:
	Income from continuing operations					$	18,465	$	22,673	$	43,046	$	49,628

Denominator:
	Weighted-average common shares
		outstanding - basic*					43,751		42,557		43,709		42,515
	Effect of dilutive securities:
		Options					38		90		44		83
		Restricted Stock					95		55		92		44
				Weighted-average common shares
					outstanding - diluted*		43,884		42,702		43,845		42,642

Basic earnings per share from continuing
			operations			$	0.42	$	0.53	$	0.99	$	1.17
Diluted earnings per share from continuing
			operations			$	0.42	$	0.53	$	0.98	$	1.16

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

The diluted EPS computation excluded 486,800 and 487,400 common stock options for the three and six months ended June 30, 2007, respectively, because the options' exercise prices were greater than the average market price of the common stock during those periods. For the same periods in 2006, there were 653,200 options excluded from the diluted EPS computation for the same reason. In total, 833,102 options were outstanding at June 30, 2007, with expiration dates between 2010 and 2015.

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

New Accounting Pronouncements
SFAS 157: In September 2006, the Financial Accounting Standards Board (FASB) issued Statement of Financial Accounting Standards No. 157, "Fair Value Measurements" (SFAS 157), which defines fair value, establishes a framework for measuring fair value in generally accepted accounting principles, and expands disclosures about fair value measurements. SFAS 157 is effective for financial statements issued for fiscal years beginning after November 15, 2007, and interim periods within those fiscal years. IDACORP and IPC are currently evaluating the impact of adopting SFAS 157 on their financial statements.

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SFAS 159: In February 2007, the FASB issued SFAS No. 159, "The Fair Value Option for Financial Assets and Financial Liabilities - Including an Amendment of FASB Statement No. 115" (SFAS 159). This standard permits an entity to choose to measure many financial instruments and certain other items at fair value. Most of the provisions in SFAS 159 are elective; however, the amendment to SFAS No. 115, "Accounting for Certain Investments in Debt and Equity Securities," applies to all entities with available-for-sale and trading securities. The fair value option established by SFAS 159 permits all entities to choose to measure eligible items at fair value at specified election dates. A business entity will report unrealized gains and losses on items for which the fair value option has been elected in earnings at each subsequent reporting date. The fair value option: (a) may be applied instrument by instrument, with a few exceptions, such as investments otherwise accounted for by the equity method; (b) is irrevocable (unless a new election date occurs); and (c) is applied only to entire instruments and not to portions of instruments. SFAS 159 is effective as of the beginning of an entity's first fiscal year that begins after November 15, 2007. Early adoption is permitted as of the beginning of the previous fiscal year provided that the entity makes that choice in the first 120 days of that fiscal year and also elects to apply the provisions of SFAS 157. IDACORP and IPC did not elect to adopt early and are currently evaluating the impact of SFAS 159 on their financial statements.

FSP FIN 39-1: In April 2007 the FASB issued FASB Staff Position No. FIN 39-1 (FSP FIN 39-1), "Amendment of FASB Interpretation No. 39" (FIN 39). FSP FIN 39-1 modifies FIN 39, "Offsetting of Amounts Related to Certain Contracts," and permits reporting entities to offset receivables or payables recognized upon payment or receipt of cash collateral against fair value amounts recognized for derivative instruments that have been offset under a master netting arrangement. FSP FIN 39-1 requires disclosure of a reporting entity's accounting policy (to offset or not offset) as well as amounts recognized for the right to reclaim cash collateral, or the obligation to return cash collateral, that have been offset against net derivative positions. FSP FIN 39-1 is effective for fiscal years beginning after November 15, 2007. IDACORP and IPC are evaluating the application of FSP FIN 39-1 with respect to its assets and liabilities.

2. INCOME TAXES:

Income tax rate
In accordance with interim reporting requirements, IDACORP and IPC use an estimated annual effective tax rate for computing their provisions for income taxes. IDACORP's effective rate on continuing operations for the six months ended June 30, 2007, was 16.2 percent, compared to 23.6 percent for the six months ended June 30, 2006. IPC's effective tax rate for the six months ended June 30, 2007, was 34.3 percent, compared to 39.4 percent for the six months ended June 30, 2006.

The differences in estimated annual effective tax rates are primarily due to the decrease in pre-tax earnings at IDACORP and IPC, timing and amount of IPC's regulatory flow-through tax adjustments, and lower tax credits from IFS.

FIN 48
IDACORP and IPC adopted FASB Interpretation No. 48, "Accounting for Uncertainty in Income Taxes - an interpretation of FASB Statement No. 109" (FIN 48) on January 1, 2007, as required. IPC recorded an increase of $15.1 million to opening retained earnings for the cumulative effect of adopting FIN 48.

IDACORP and IPC recognize interest accrued related to unrecognized tax benefits as interest expense and penalties as other expense. FIN 48 allows companies to change their accounting policy election for interest and penalties upon adoption of the standard. IDACORP and IPC had classified interest as income taxes prior to the adoption of FIN 48. As of January 1, 2007, IPC had accrued interest of $6.5 million. The interest liability did not materially change as of June 30, 2007. No penalties are accrued.

As of January 1, 2007, IPC had total unrecognized tax benefits of $21.2 million. If recognized, the $21.2 million would affect IPC's effective tax rate. The amount of unrecognized tax benefits did not materially change as of June 30, 2007.

IPC is currently disputing the Internal Revenue Service's (IRS) disallowance of IPC's use of the simplified service cost method of uniform capitalization for tax years 2001-2003. The dispute is under review with the IRS Appeals Office, and it is reasonably possible that the matter will be resolved in 2007. Resolution would result in a decrease to IPC's unrecognized tax benefits of $17.4 million. As of June 30, 2007, the appeals conference had not been scheduled.

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IDACORP and IPC are subject to examination by their major tax jurisdictions - U.S. federal and state of Idaho - for tax years 2004 through 2006. There are no income tax examinations currently in process.

3. COMMON STOCK AND STOCK-BASED COMPENSATION:

During the six months ended June 30, 2007, IDACORP entered into the following transactions involving its common stock:

16,222 original issue shares and 75,256 treasury shares were used for awards pursuant to the 2000 Long-Term Incentive and Compensation Plan.
10,820 treasury shares were used for the annual stock grant to directors under the Non-Employee Directors Stock Compensation Plan.
A total of 128,463 original issue shares were issued under the Dividend Reinvestment and Stock Purchase Plan and the Employee Savings Plan.
254,500 original issue shares were issued in at the market offerings at an average price of $31.91 per share under the Continuous Equity Program. An additional 245,500 shares were issued in July 2007 at an average price of $32.23.

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

The LTICP for officers, key employees and directors permits the grant of nonqualified stock options, incentive stock options, stock appreciation rights, restricted stock, restricted stock units, performance units, performance shares and other awards. The RSP permits only the grant of restricted stock or performance-based restricted stock. At June 30, 2007, the maximum number of shares available under the LTICP and RSP were 1,606,555 and 108,595, respectively. The following table shows the compensation cost recognized in income and the tax benefits resulting from these plans, as well as the amounts allocated to IPC for those costs associated with IPC's employees (in thousands of dollars):

	IDACORP						IPC
	Six months ended						Six months ended
	June 30,						June 30,
	2007			2006			2007		2006
Compensation cost	$	1,556	$		1,220	$		996	$	477
Income tax benefit	$	608	$		477	$		390	$	186

No equity compensation costs have been capitalized.

Stock awards: Restricted stock awards have vesting periods of up to four years. Restricted stock awards entitle the recipients to dividends and voting rights, and unvested shares are restricted as to disposition and subject to forfeiture under certain circumstances. The fair value of restricted stock awards is measured based on the market price of the underlying common stock on the date of grant and charged to compensation expense over the vesting period based on the number of shares expected to vest. The weighted average fair value at date of grant for restricted stock awards granted during the first six months of 2007 was $35.18.

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

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The performance goals for the 2006 and 2007 awards are independent of each other and equally weighted, and are based on two metrics, cumulative earnings per share (CEPS) and total shareholder return (TSR) relative to a peer group. The fair value of the CEPS portion is based on the market value at the date of grant, reduced by the loss in time-value of the estimated future dividend payments, using an expected quarterly dividend of $0.30. The fair value of the TSR portion is estimated using a statistical model that incorporates the probability of meeting performance targets based on historical returns relative to the peer group. Both performance goals are measured over the three-year vesting period and are charged to compensation expense over the vesting period based on the number of shares expected to vest. The weighted average fair value at date of grant for CEPS and TSR awards granted during the first six months of 2007 was $25.82.

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

4. FINANCING:

Long-term Financing
On June 22, 2007, IPC issued $140 million of its 6.30% First Mortgage Bonds, Secured Medium-Term Notes, Series F, due June 15, 2037. IPC used the net proceeds to pay down outstanding commercial paper. IPC currently has in place a registration statement that can be used for the issuance of an aggregate principal amount of $100 million of first mortgage bonds (including medium-term notes).

Credit Facilities
On April 25, 2007, IDACORP entered into an Amended and Restated Credit Agreement (IDACORP Facility) with Wachovia Bank, National Association, as administrative agent, swingline lender and LC issuer, JPMorgan Chase Bank, N.A., as syndication agent, Keybank National Association, Wells Fargo Bank, N.A. and Bank of America, N.A., as documentation agents, Wachovia Capital Markets, LLC and J.P. Morgan Securities Inc., as joint lead arrangers and joint book runners, and the other financial institutions party thereto, as lenders. The IDACORP Facility amended and restated a $150 million five-year facility that would have expired on March 31, 2010.

The IDACORP Facility is a $100 million five-year credit agreement that terminates on April 25, 2012. The IDACORP Facility, which will be used for general corporate purposes and commercial paper backup, provides for the issuance of loans and standby letters of credit not to exceed the aggregate principal amount of $100 million, including swingline loans in an aggregate principal amount at any time outstanding not to exceed $10 million. IDACORP has the right to request an increase in the aggregate principal amount of the IDACORP Facility to $150 million and to request one-year extensions of the then existing termination date. At June 30, 2007, no loans were outstanding on IDACORP's Facility and $65 million of commercial paper was outstanding.

On April 25, 2007, IPC entered into an Amended and Restated Credit Agreement (IPC Facility) with Wachovia Bank, National Association, as administrative agent, swingline lender and LC issuer, JPMorgan Chase Bank, N.A., as syndication agent, Keybank National Association, US Bank National Association and Bank of America, N.A., as documentation agents, Wachovia Capital Markets, LLC and J.P. Morgan Securities Inc., as joint lead arrangers and joint book runners, and the other financial institutions party thereto, as lenders. The IPC Facility amended and restated a $200 million five-year credit facility that would have expired on March 31, 2010.

The IPC Facility is a $300 million five-year credit agreement that terminates on April 25, 2012. The IPC Facility, which will be used for general corporate purposes and commercial paper backup, provides for the issuance of loans and standby letters of credit not to exceed the aggregate principal amount of $300 million, including swingline loans in an aggregate principal amount at any time outstanding not to exceed $30 million. IPC has the right to request an increase in the aggregate principal amount of the IPC Facility to $450 million and to request one-year extensions of the then existing termination date. At June 30, 2007, no loans were outstanding on IPC's Facility and $22 million of commercial paper was outstanding.

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At June 30, 2007, IPC had regulatory authority to incur up to $450 million of short-term indebtedness.

5. COMMITMENTS AND CONTINGENCIES:

Guarantees
IPC has agreed to guarantee one-third of the cost of the performance of reclamation activities at Bridger Coal Company, of which Idaho Energy Resources Co., a subsidiary of IPC, owns a one-third interest. This guarantee, which is renewed each December, was $60 million at June 30, 2007. 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.

Legal Proceedings
Reference is made to IDACORP's and IPC's Annual Report on Form 10-K for the year ended December 31, 2006, and Quarterly Report on Form 10-Q for the quarter ended March 31, 2007, for a discussion of all material pending legal proceedings to which IDACORP and IPC and their subsidiaries are parties. The following discussion provides a summary of material developments that occurred in those proceedings during the period covered by this report and of any new material proceedings instituted during the period covered by this report.

Wah Chang: Wah Chang's appeal to the U.S. Court of Appeals for the Ninth Circuit of the February 11, 2005 dismissal of the case by the Honorable Robert H. Whaley, sitting by designation in the U.S. District Court for the Southern District of California, was orally argued on April 10, 2007. The matter now awaits decision by the Ninth Circuit. IDACORP, IPC and IE intend to vigorously defend their position in this proceeding and believe this matter will not have a material adverse effect on their consolidated financial positions, results of operations or cash flows.

Western Energy Proceedings at the FERC:
California Refund: In April 2001, the FERC issued an order stating that it was establishing a price mitigation plan for sales in the California wholesale electricity market. That plan included the potential for orders directing electricity sellers into California from October 2, 2000, through June 20, 2001, 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. On July 25, 2001, the FERC issued an order initiating the California Refund proceeding including evidentiary hearings to determine the scope and methodology for determining refunds. On February 17, 2006, IE and IPC jointly filed with the California Parties (Pacific Gas & Electric Company, San Diego Gas & Electric Company, Southern California Edison, the California Public Utilities Commission, the California Electricity Oversight Board, the California Department of Water Resources and the California Attorney General) an Offer of Settlement at the FERC. A number of other parties, representing substantially less than the majority of potential refund claims, chose to opt out of the Settlement. After consideration of comments, the FERC approved the Offer of Settlement on May 22, 2006.

On June 21, 2006, the Port of Seattle, Washington filed a request for rehearing of the FERC order approving the Settlement. The FERC issued an order on October 5, 2006, denying the Port of Seattle's request for rehearing. On October 24, 2006, the Port of Seattle petitioned the U.S. Court of Appeals for the Ninth Circuit for review of the FERC orders approving the Settlement. The Ninth Circuit consolidated that review petition with the large number of review petitions already consolidated before it and has stayed further action on the consolidated cases while the court's mediator and FERC representatives work on achieving settlements with other parties. On January 23, 2007, IPC and IE filed a motion to sever the Port of Seattle's petition for review from the bulk of cases pending in the Ninth Circuit with which it had been consolidated. IPC and IE also filed a motion to dismiss the Port of Seattle's petition for review. On April 11, 2007, the Ninth Circuit filed an order denying IPC's and IE's motion to sever. The motion to dismiss was denied without prejudice to renew when briefs are filed. IPC and IE are unable to predict when or how the Ninth Circuit might rule on Port of Seattle's petition for review.

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Market Manipulation: As part of the California and Pacific Northwest Refund proceedings, on November 20, 2002, the FERC issued an order permitting discovery and the submission of evidence regarding market manipulation by sellers during the western energy crisis of 2000 and 2001. 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" or anomalous market behavior ("partnership") in violation of the California Independent System Operator and California Power Exchange 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. Originally, eight parties sought rehearing of the "gaming" settlement. The FERC approved the motion to dismiss the "partnership" proceeding on January 23, 2004.

On October 11, 2006, the FERC issued an order denying rehearing of its earlier approval of the "gaming" settlement. On October 24, 2006, the Port of Seattle, Washington appealed to the U.S. Court of Appeals for the Ninth Circuit FERC's denial of its request for rehearing of its order granting approval of the settlement of the gaming allegations against IE and IPC. On November 17, 2006, the Ninth Circuit consolidated the Port of Seattle's review petition with a large number of review petitions previously consolidated and has stayed further action on the consolidated cases while the court's mediator and FERC representatives work on achieving settlements with other parties.

In addition, a number of parties have petitioned the Ninth Circuit Court of Appeals contending that the scope of the show cause proceedings was too narrow, but those petitions have been stayed. IE and IPC are unable to predict the outcome of these matters.

Pacific Northwest Refund: On June 19, 2001, the FERC expanded its price mitigation plan for the California Wholesale electricity market discussed above under "California Refund" to the entire western electrically interconnected system. This expansion led to the Pacific Northwest Refund proceeding. On September 24, 2001, the FERC Administrative Law Judge submitted recommendations and findings to the FERC, finding that prices in the Pacific Northwest during the December 25, 2000, through June 20, 2001, time period should be governed by the Mobile-Sierra standard of public interest rather than the just and reasonable standard, that the Pacific Northwest spot markets were competitive, and that no refunds should be allowed. The FERC declined to order refunds on June 25, 2003, and multiple parties then appealed to the Ninth Circuit Court of Appeals. IE and IPC were parties in the FERC proceeding and are participating in the appeal. Briefing on the appeal was completed on May 25, 2005, and oral argument was held on January 8, 2007. The Settlement in the California Refund proceeding resolves all claims the California Parties have against IE and IPC in the Pacific Northwest proceeding. IE and IPC are unable to predict the outcome of these matters.

There are pending in the U.S. Court of Appeals for the Ninth Circuit approximately 200 petitions for review of numerous FERC orders regarding the Western energy matters of 2000 and 2001, including the California refund proceeding, the structure and content of the FERC's market-based rate regime, show cause orders respecting contentions of market manipulation, and the Pacific Northwest proceedings. Decisions in any one of these appeals may have implications with respect to other pending cases, including those to which IDACORP, IPC or IE are parties. IDACORP, IPC and IE are unable to predict the outcome of any of these petitions for review.

Shareholder Lawsuit: On May 26, 2004 and June 22, 2004, two shareholder lawsuits were filed in the U.S. District Court for the District of Idaho 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., raised largely similar allegations. The lawsuits were putative class actions brought on behalf of purchasers of IDACORP stock between February 1, 2002, and June 4, 2002.

On May 21, 2007, the U.S. District Court for the District of Idaho granted the defendants' motion to dismiss the amended complaint because it failed to satisfy the pleading requirements for loss causation. The court also denied the plaintiffs' request to further amend the complaint.

On June 19, 2007, the plaintiffs filed a notice of appeal from the District Court's judgment to the United States Court of Appeals for the Ninth Circuit. IDACORP and the other defendants intend to defend themselves vigorously, but IDACORP is unable to predict the outcome of this matter.

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

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On May 1, 2006, the defendants filed an Answer to plaintiffs' First Amended Complaint denying all liability to the plaintiffs and asserting certain affirmative defenses including collateral estoppel and res judicata, preemption, impossibility and impracticability, failure to join all real and necessary parties, and various defenses based on untimeliness. On June 19, 2006, the defendants filed a motion to dismiss plaintiffs' First Amended Complaint, asserting, among other things, that the Court lacks subject matter jurisdiction and that plaintiffs failed to join an indispensable party (namely, the United States government). On May 31, 2007, the U.S. District Court granted the defendants' motion to dismiss stating that the plaintiffs' claims are barred by the finality provision of the Indian Claims Commission Act. On June 8, 2007, plaintiffs filed a motion for reconsideration. On June 25, 2007, the defendants filed an opposition to plaintiffs' motion for reconsideration and plaintiffs filed their reply to opposition to motion for reconsideration on July 9, 2007. The matter is now fully briefed and submitted to the District Court for decision. IPC intends to vigorously defend its position in this proceeding, but is unable to predict the outcome of this matter.

Sierra Club Lawsuit-Bridger: In February 2007, the Sierra Club and the Wyoming Outdoor Council filed a complaint against PacifiCorp in federal district court in Cheyenne, Wyoming alleging violations of air quality opacity standards at the Jim Bridger coal-fired plant (Plant) in Sweetwater County, Wyoming. Opacity is an indication of the amount of light obscured in the flue gas of a power plant. A formal answer to the complaint was filed by PacifiCorp on April 2, 2007, in which PacifiCorp denied almost all of the allegations and asserted a number of affirmative defenses. IPC is not a party to this proceeding but has a one-third ownership interest in the Plant. PacifiCorp owns a two-thirds interest and is the operator of the Plant. The complaint alleges thousands of opacity permit limit violations by PacifiCorp and seeks a declaration that PacifiCorp has violated opacity limits, a permanent injunction ordering PacifiCorp to comply with such limits, civil penalties of up to $32,500 per day per violation and reimbursement of the plaintiff's costs of litigation, including reasonable attorney fees.

The U.S. District Court has set this matter for trial commencing in April 2008. Discovery in the matter is ongoing. IPC continues to monitor the status of this matter but is unable to predict its outcome and what effect this matter may have on its consolidated financial position, results of operations or cash flows.

Snake River Basin Adjudication: IPC is engaged in the Snake River Basin Adjudication (SRBA), a general stream adjudication, commenced in 1987, to define the nature and extent of water rights in the Snake River basin in Idaho, including the water rights of IPC. The initiation of the SRBA resulted from the Swan Falls Agreement, an agreement entered into by IPC and the Governor and Attorney General of Idaho in October 1984 to resolve litigation relating to IPC's water rights at its Swan Falls project. IPC has filed claims to its water rights for hydropower and other uses in the SRBA. Other water users in the basin have also filed claims to water rights. Parties to the SRBA may file objections to water right claims that adversely affect or injure their claimed water rights and the Idaho District Court for the Fifth Judicial District, which has jurisdiction over SRBA matters (SRBA Court) then adjudicates the claims and objections and enters a decree defining a party's water right. IPC has filed claims for all of its hydropower water rights in the SRBA, is actively protecting those water rights, and is objecting to claims that may potentially injure or affect those water rights. One such claim involves a notice of claim of ownership filed on December 22, 2006, by the State of Idaho, for a portion of the water rights held by IPC that are subject to the Swan Falls Agreement.

In conjunction with the filing of the complaint and petition, IPC filed motions with the court to stay all pending proceedings involving the water rights of IPC and to consolidate those proceedings into a single action where all issues relating to the Swan Falls Agreement can be determined.

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IPC alleged in the complaint, among other things, that contrary to the parties' belief at the time the Swan Falls Agreement was entered into in 1984, the Snake River basin above Swan Falls was over-appropriated and as a consequence there was not in 1984, and there currently is not, water available for new upstream uses over and above the minimum flows established by the Swan Falls Agreement; that because of this mutual mistake of fact relating to the over-appropriation of the basin, the Swan Falls Agreement should be reformed; that the State's December 22, 2006, claim of ownership to IPC's water rights should be denied; and that the Swan Falls Agreement did not subordinate IPC's water rights to aquifer recharge.

On May 30, 2007, the State filed motions to dismiss IPC's complaint and petition. These motions were briefed and, together with IPC's motions to stay and consolidate the proceedings, were argued before the Court on June 25, 2007.

On July 23, 2007, the court issued an Order granting in part and denying in part the State's motion to dismiss, consolidating the issues into a consolidated sub case before the court, providing for discovery during the objection period and setting a scheduling conference for December 17, 2007. In its Order, the court denied the majority of the State's motion to dismiss, refusing to dismiss the complaint and finding that the court has jurisdiction to hear and determine virtually all the issues raised by IPC's complaint that relate to IPC's water rights and the effect of the Swan Falls Agreement upon those water rights. This includes the issues of ownership, whether IPC's water rights are subordinated to recharge and how those water rights are to be administered relative to other water rights on the same or connected resources. The court did find that by virtue of a state statute the IDWR, and its director, could not be parties to the SRBA and therefore stayed IPC's claims against the IDWR and its director pending resolution of the issues to be litigated in the SRBA, or until further order of the court.

Consistent with IPC's motion to consolidate and stay proceedings, the court consolidated all of the issues associated with IPC's water rights before the court and stayed that proceeding to allow other parties that may be affected by the litigation to file responses or intervene in the consolidated proceedings by December 5, 2007. IPC is unable to predict the outcome of the consolidated proceedings. For further discussion of Idaho Water Management Issues, see Part I, Item 2 - "MD&A - LEGAL AND ENVIRONMENTAL ISSUES."

6. REGULATORY MATTERS:

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

		June 30,		December 31,
		2007		2006
Idaho PCA current year:
	Accrual for the 2007-2008 rate year *	$	-	$	(3,484)
	Deferral for the 2008-2009 rate year		39,815		-
Idaho PCA true-up awaiting recovery (refund):
	Authorized May 2006		-		(11,689)
	Authorized May 2007		10,571		-
Oregon deferral:
	2001 costs		4,955		6,670
	2005 costs		-		2,889
	Total deferral (accrual)	$	55,341	$	(5,614)
* Includes $69 million of emission allowance sales to be credited to the customers during the 2007-2008 PCA 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 May 31, 2007, the IPUC approved IPC's 2007-2008 PCA filing. The filing increased the PCA component of customers' rates from the then existing level, which was $46.8 million below base rates, to a level that is $30.7 million above those base rates. This $77.5 million increase is net of $69.1 million of proceeds from sales of excess SO₂ emission allowances. The new rates were effective June 1, 2007.

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On June 1, 2006, IPC implemented the 2006-2007 PCA, which reduced the PCA component of customers' rates from the then-existing level, which was recovering $76.7 million above then-existing base rates, to a level that was $46.8 million below those base rates, a decrease of approximately $123.5 million.

Oregon: On April 28, 2006, IPC filed for an accounting order with the OPUC to defer net power supply costs for the period of May 1, 2006, through April 30, 2007. IPC requested authorization to defer an estimated $3.3 million, which is Oregon's jurisdictional share of the excess power supply costs. IPC also requested that it earn its Oregon authorized rate of return on the deferred balance and recover the amount through rates in future years, as approved by the OPUC. On April 25, 2007, a tentative settlement agreement was reached on the deferral application with the OPUC Staff and the Citizens' Utility Board in the amount of $2 million. This amount is subject to approval by the OPUC. The parties also agreed that IPC would file an application for an Oregon PCA mechanism.

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

On March 2, 2005, IPC filed for an accounting order with the OPUC to defer net power supply costs for the period of March 2, 2005 through February 28, 2006. The forecasted net power supply costs related to the Oregon jurisdiction that were included in this filing were $3 million. On March 5, 2007, IPC, the OPUC Staff and the Citizen's Utility Board entered into a stipulation under which the parties agreed that IPC appropriately deferred approximately $2.7 million during the 2005 deferral period. The stipulation also provided that, rather than amortizing the 2005 deferral into rates, IPC should offset the balance with the Oregon jurisdictional share of proceeds from the sale of excess SO₂ emission allowances and the benefit that IPC will receive from income taxes already paid on the sale of those allowances. When combined, these offsets exceed the 2005 deferral balance, and the excess was applied to the 2001 deferral balance. The OPUC approved the stipulation on April 2, 2007.

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

IPC and the IPUC Staff agreed in concept to a three-year pilot beginning January 1, 2007, and a stipulation was filed on December 18, 2006. The stipulation called for the implementation of a FCA mechanism pilot program as proposed by IPC in its original application with additional conditions and provisions related to customer count and weather normalization methodology, recording of the FCA deferral amount in reports to the IPUC and detailed reporting of demand side management (DSM) activities. The IPUC approved the stipulation on March 12, 2007. The pilot program began retroactively on January 1, 2007, and will run through 2009, with the first rate adjustment to occur on June 1, 2008, and subsequent rate adjustments to occur on June 1 of each year thereafter during the term of the pilot program. IPC accrued $1.1 million of FCA expense through the second quarter of 2007.

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Open Access Transmission Tariff (OATT)
On March 24, 2006, IPC submitted a revised OATT filing with the FERC requesting an increase in transmission rates. In the filing IPC proposed to move from a fixed rate to a formula rate, which allows for transmission rates to be updated each year based on FERC Form 1 data. The formula rate request included a rate of return on equity of 11.25 percent. The proposed rates would have produced an annual revenue increase of approximately $13 million based on 2004 test year data. The FERC accepted IPC's rates, effective June 1, 2006, subject to adjustment to conform to SFAS 109 tax accounting requirements, which lowered the estimated annual revenues to approximately $11 million. The rates are being collected subject to refund pending the outcome of the FERC hearing process. Settlement discussions were held in April and May of 2007 at which the parties to the proceeding reached settlement on all issues except the treatment of contracts in existence before the implementation of OATT in 1996 (Legacy Agreements). On June 15, 2007, the parties filed a settlement agreement with the FERC for the settled issues. The settlement agreement is awaiting FERC approval. Hearings have been held before the FERC regarding the treatment of the Legacy Agreements and an initial decision is expected in August 2007.

Pension Expense
In the 2003 Idaho general rate case, the IPUC disallowed recovery of pension expense because there were no current contributions being made to the plan. On March 20, 2007, IPC filed a request with the IPUC to clarify that IPC can consider future contributions made to the pension plan a recoverable cost of service. An order approving this application would not determine the methodology of recovery but would permit IPC to record a regulatory asset related to pension costs. On June 1, 2007, the IPUC issued its order authorizing IPC to account for its defined benefit pension expense on a cash basis, and to defer and account for accrued pension expense under SFAS 87, "Employers' Accounting for Pensions," as a regulatory asset. The IPUC acknowledged that it is appropriate for IPC to seek recovery in its revenue requirement of reasonable and prudently incurred pension expense based on actual cash contributions. IPC will begin deferring pension expense to a regulatory asset account to be matched with revenue when future pension contributions are recovered through rates. The deferral of pension expense would not begin until $4.1 million of past contributions still recorded on the balance sheet at December 31, 2006, have been expensed. For 2007, approximately $2.8 million will be deferred to a regulatory asset beginning in the third quarter. IPC did not request a carrying charge to be applied to the deferral of the accrued SFAS 87 expense.

7. SEGMENT INFORMATION:

IDACORP has identified two reportable segments: utility operations and IFS. ITI and IDACOMM, which had previously been identified as reportable segments, are now reported as discontinued operations (see Note 9).

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

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

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		Utility					All				Consolidated
		Operations		IFS			Other		Eliminations		Total
Three months ended June 30, 2007:
	Revenues	$	212,526		$	307	$	939	$	-	$	213,772
	Income (loss) from continuing operations		16,164			1,759		542		-		18,465

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

Total assets at June 30, 2007		$	3,287,266		$	126,997	$	148,996	$	(30,943)	$	3,532,316

Six months ended June 30, 2007:
	Revenues	$	418,455		$	605	$	1,424	$	-	$	420,484
	Income (loss) from continuing operations		39,495			3,621		(70)		-		43,046

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

8. BENEFIT PLANS:

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

						Deferred				Postretirement
		Pension Plan				Compensation Plan				Benefits
		2007		2006		2007		2006		2007		2006
Service cost		$	3,803	$	3,619	$	352	$	368	$	379	$	376
Interest cost			6,115		5,585		593		582		895		862
Expected return on plan assets			(8,351)		(7,670)		-		-		(690)		(630)
Amortization of transition
	obligation		-		-		-		-		510		510
Amortization of prior service cost			162		166		44		61		(134)		(134)
Amortization of net loss			-		65		141		211		132		219
	Net periodic benefit cost	$	1,729	$	1,765	$	1,130	$	1,222	$	1,092	$	1,203

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

						Deferred				Postretirement
		Pension Plan				Compensation Plan				Benefits
		2007		2006		2007		2006		2007		2006
Service cost		$	7,606	$	7,238	$	704	$	736	$	758	$	752
Interest cost			12,229		11,170		1,186		1,164		1,790		1,724
Expected return on plan assets			(16,693)		(15,340)		-		-		(1,380)		(1,260)
Amortization of net
	obligation at transition		-		-		-		-		1,020		1,020
Amortization of prior service cost			325		332		87		122		(268)		(268)
Amortization of net loss			-		130		283		422		264		438
	Net periodic benefit cost	$	3,467	$	3,530	$	2,260	$	2,444	$	2,184	$	2,406

IDACORP and IPC have not contributed and do not expect to contribute to their pension plan in 2007.

9. DISCONTINUED OPERATIONS:

In the second quarter of 2006, IDACORP decided to seek buyers for its fuel cell technology subsidiary ITI and its telecommunications subsidiary IDACOMM. IDACORP had been reviewing strategic alternatives for ITI and IDACOMM in order to focus on its core utility business. The planned disposals of these businesses met the criteria established for reporting them as assets held for sale as defined by SFAS 144. SFAS 144 requires that a long-lived asset classified as held for sale be measured at the lower of its carrying amount or fair value, less costs to sell, and requires the holder to cease depreciation and amortization. Based on an analysis of the fair value of each subsidiary, no adjustments to the carrying values were required for the year ended December 31, 2006.

On July 20, 2006, IDACORP completed the sale of all of the outstanding common stock of ITI to IdaTech UK Limited, a wholly-owned subsidiary of Investec Group Investments (UK) Limited. IDACORP recorded a gain of $11.5 million, net of tax, from this transaction.

On February 23, 2007, IDACORP completed the sale of all of the outstanding common stock of IDACOMM to American Fiber Systems, Inc.

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

		Three months ended				Six months ended
		June 30,				June 30,
		2007		2006		2007		2006

Revenues		$	-	$	3,403	$	1,278	$	8,704
Operating expenses			-		(7,466)		(1,309)		(15,447)
Other expense			-		(25)		(25)		(67)
Loss on disposal			-		-		(2,877)		-
Pre-tax losses			-		(4,088)		(2,933)		(6,810)
Income tax benefit			-		1,271		3,000		2,514
Income (losses) from discontinued
	operations	$	-	$	(2,817)	$	67	$	(4,296)

The assets and liabilities of IDACOMM were classified as held for sale on IDACORP's condensed consolidated balance sheet at December 31, 2006. A summary of the components of assets and liabilities held for sale is as follows (in thousands of dollars):

			December 31,
			2006
Assets
	Current assets		$	3,326
	Property and investments			20,789
	Other assets			287
		Total assets	$	24,402

Liabilities
	Current liabilities		$	2,606
	Other liabilities			8,773
		Total liabilities	$	11,379

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

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

We have reviewed the accompanying condensed consolidated balance sheet of IDACORP, Inc. and subsidiaries (the "Company") as of June 30, 2007, and the related condensed consolidated statements of income and comprehensive income for the three-month and six-month periods ended June 30, 2007 and 2006, and of cash flows for the six-month periods ended June 30, 2007 and 2006. These interim financial statements are the responsibility of the Company's management.

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

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

We have previously audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheet of IDACORP, Inc. and subsidiaries as of December 31, 2006, and the related consolidated statements of income, comprehensive income, shareholders' equity, and cash flows for the year then ended (not presented herein); and in our report dated February 28, 2007, we expressed an unqualified opinion on those consolidated financial statements, which included an explanatory paragraph related to the adoption of Statement of Financial Accounting Standards No. 158, Employers' Accounting for Defined Benefit Pension and Other Postretirement Plans - an amendment of FASB Statements No. 87, 88, 106, and 132(R). In our opinion, the information set forth in the accompanying condensed consolidated balance sheet as of December 31, 2006, is fairly stated, in all material respects, in relation to the consolidated balance sheet from which it has been derived.

DELOITTE & TOUCHE LLP

Boise, Idaho
August 7, 2007

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

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

We have reviewed the accompanying condensed consolidated balance sheet and statement of capitalization of Idaho Power Company and subsidiary (the "Company") as of June 30, 2007, and the related condensed consolidated statements of income and comprehensive income for the three-month and six-month periods ended June 30, 2007 and 2006, and of cash flows for the six-month periods ended June 30, 2007 and 2006. 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, 2006, and the related consolidated statements of income, comprehensive income, retained earnings, and cash flows for the year then ended (not presented herein); and in our report dated February 28, 2007, we expressed an unqualified opinion on those consolidated financial statements, which included an explanatory paragraph related to the adoption of Statement of Financial Accounting Standards No. 158, Employers' Accounting for Defined Benefit Pension and Other Postretirement Plans - an amendment of FASB Statements No. 87, 88, 106, and 132(R). In our opinion, the information set forth in the accompanying condensed consolidated balance sheet and statement of capitalization as of December 31, 2006, is fairly stated, in all material respects, in relation to the consolidated balance sheet and statement of capitalization from which it has been derived.

DELOITTE & TOUCHE LLP

Boise, Idaho
August 7, 2007

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

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

INTRODUCTION:

In Management's Discussion and Analysis of Financial Condition and Results of Operations (MD&A), the general financial condition and results of operations for IDACORP, Inc. and its subsidiaries (collectively, IDACORP) and Idaho Power Company and its subsidiary (collectively, IPC) are discussed.

IDACORP is a holding company formed in 1998 whose principal operating subsidiary is IPC. IDACORP is subject to the provisions of the Public Utility Holding Company Act of 2005, which provides certain access to books and records to the Federal Energy Regulatory Commission (FERC) and state utility regulatory commissions and imposes certain record retention and reporting requirements on IDACORP.

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

IDACORP's other subsidiaries include:

IDACORP Financial Services, Inc. (IFS), an investor in affordable housing and other real estate investments;
Ida-West Energy Company (Ida-West), an operator of small hydroelectric generation projects that satisfy the requirements of the Public Utility Regulatory Policies Act of 1978 (PURPA); and
IDACORP Energy (IE), a marketer of energy commodities, which wound down operations in 2003.

In the second quarter of 2006, IDACORP management designated the operations of IDACORP Technologies, Inc. (ITI) and IDACOMM, Inc. (IDACOMM) as assets held for sale, as defined by Statement of Financial Accounting Standards No. 144. IDACORP's condensed consolidated financial statements reflect the reclassification of the results of these businesses as discontinued operations for all periods presented. Discontinued operations are discussed in more detail in Note 9 to IDACORP's and IPC's Condensed Consolidated Financial Statements and later in the MD&A.

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

On February 23, 2007, IDACORP completed the sale of all of the outstanding common stock of IDACOMM to American Fiber Systems, Inc.

While reading the MD&A, please refer to 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, 2006, and the Quarterly Report on Form 10-Q for the quarter ended March 31, 2007, 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

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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 and compliance with 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, provision of transmission services, relicensing of hydroelectric projects, recovery of purchased power expenses, recovery of other capital investments, present or prospective wholesale and retail competition (including but not limited to retail wheeling and transmission costs) and other refund proceedings;
Changes arising from the Energy Policy Act of 2005;
Litigation and regulatory proceedings, including those resulting from the energy situation in the western United States, and penalties 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, transmission and distribution 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 or the development of another transmission group;
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 and other natural risks, such as earthquake, flood, drought, lightning, wind and fire, acts of war or terrorism;
Market conditions that could affect the operations and prospects of IDACORP's subsidiaries or their competitors;
Increasing health care costs and the resulting effect on medical benefits 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.

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EXECUTIVE OVERVIEW:

Second quarter 2007 financial results
IDACORP's second quarter 2007 earnings were $18.5 million, a decrease of $1.4 million compared to the same period in 2006. Diluted earnings per share were $0.42, a decrease of $0.05 per share compared to 2006.

The key components of the change in IDACORP's net income for the second quarter are:

IPC's earnings decreased to $16.2 million, a $5.4 million or $0.14 per diluted share decrease from the prior year. The key factors affecting IPC's earnings include (amounts shown are net of income taxes):

Increased retail sales contributed $7.1 million to gross margin (general business revenues and off-system sales less resource costs and rate-related amortizations). Warmer and drier conditions in the second quarter of 2007 led to higher irrigation loads as compared to the prior year. IPC continued to experience moderate customer growth, with the average number of general business customers increasing 12,819 over the same period in 2006, an increase of three percent.
Increased costs to supply power, net of rate adjustments, reduced gross margin by $4.6 million. Poor hydroelectric generating conditions in the second quarter of 2007 increased IPC's reliance on typically more expensive thermal generation and purchased power, and reduced wholesale sales. IPC's hydroelectric generation contributed only 51 percent of total system generation for the second quarter of 2007, as compared to 71 percent for the same period in 2006.
Increases in Other O&M expenses reduced earnings by $5.5 million compared to 2006. The increase is primarily the result of higher third-party transmission costs, higher labor-related expenses, higher maintenance expenses for IPC's coal-fired generation facilities and distribution facilities, and higher legal, regulatory and compliance expenses.
Gain on sales of excess SO₂ emission allowances was $0.5 million in 2007, compared to $4.7 million in 2006. IPC recorded a gain on the sale of 4,000 excess emission allowances in the second quarter of 2007, compared to 78,000 in the second quarter of 2006.

Discontinued operations had no impact on earnings in the second quarter of 2007 as compared to a loss of $2.8 million (net of tax) in the second quarter of 2006, an increase of $0.06 per diluted share. Discontinued operations includes the operations of ITI, which was sold in July 2006, and IDACOMM, which was sold in February 2007.

Losses at the holding company decreased $1.9 million, an improvement of $0.04 per share, reflecting a reduction in operating expenses and the effect of intra-period tax allocations recorded at the holding company.

Year-to-date 2007 financial results
IDACORP's year-to-date 2007 earnings were $43.1 million, a decrease of $2.2 million compared to the same period in 2006. Diluted earnings per share were $0.98 as compared to $1.06 in 2006, a decrease that is a result of lower earnings and increases in shares outstanding.

The key factors contributing to the change in IDACORP's net income in 2007 are:

IPC's earnings decreased to $39.5 million, a $7.1 million or $0.19 per diluted share decrease from the prior year. The key factors affecting IPC's earnings for 2007 include (amounts shown are net of income taxes):

Increased retail sales contributed $9.1 million to gross margin (general business revenues and off-system sales less resource costs and rate-related amortizations). Warmer and drier conditions in 2007 led to higher irrigation loads as compared to the prior year. IPC continued to experience moderate customer growth, with the average number of general business customers increasing 13,324 over the same period in 2006, an increase of three percent.

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Increased costs to supply power, net of rate increases, reduced gross margin by $5.9 million. Poor hydroelectric generating conditions in 2007 increased IPC's reliance on typically more expensive thermal generation and purchased power, and reduced wholesale sales. IPC's hydroelectric generation contributed only 51 percent of total system generation for 2007, as compared to 67 percent for the same period in 2006.
Increases in Other O&M expenses reduced earnings by $9.3 million compared to 2006. The increase is primarily the result of higher labor-related expenses, higher maintenance expenses for IPC's coal-fired generation facilities and distribution facilities, higher legal, regulatory and compliance expenses, and higher third-party transmission costs.
Gain on sale of excess SO₂ emission allowances was $0.5 million, compared to $5.0 million in 2006. IPC recorded a gain on the sale of 4,000 excess emission allowances in 2007, compared to 78,000 in 2006.

Discontinued operations had no material impact on earnings in 2007 as compared to a loss of $4 million (net of tax) in 2006, an increase of $0.10 per diluted share. Discontinued operations includes the operations of ITI, which was sold in July 2006, and IDACOMM, which was sold in February 2007.

Losses at the holding company decreased $1.5 million, an improvement of $0.04 per share, reflecting a reduction in operating expenses and the effect of intra-period tax allocations recorded at the holding company.

Hydroelectric generating conditions
Significantly below normal winter precipitation and stream flow conditions negatively impacted hydroelectric generation for the first half of 2007 as compared to the same period in 2006. On August 1, 2007, the National Weather Service's Northwest River Forecast Center reported that Brownlee reservoir inflow for April through July 2007 was to be 2.8 maf, or 45 percent of average, a reduction from the 3.0 maf, or 48 percent of average, projected on May 7, 2007. With current and forecasted stream flow conditions, IPC expects to generate between 6.0 and 6.5 million MWh from its hydroelectric facilities in 2007, compared to 9.2 million MWh in 2006.

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

Power Cost Adjustment
On June 1, 2007, IPC implemented its annual Power Cost Adjustment (PCA), which results in a $77.5 million, or 14.5 percent on average, increase in the rates of Idaho customers. The increase in rates is a direct result of significantly below normal winter precipitation and deteriorated stream flow conditions during the first half of 2007. In years where water is plentiful and IPC can fully utilize its extensive hydroelectric system, power production costs are lower and IPC can pass those benefits to its customers in the form of rate reductions. In years when water is in short supply, as it was this past winter, the higher costs of supplying power by other means are shared with IPC's customers.

General Rate Case filing
On June 8, 2007, IPC filed an application with the IPUC requesting an average base rate increase of 10.35 percent for its Idaho customers. Base rates primarily reflect IPC's cost of providing electrical service to its customers, including equipment and infrastructure. IPC's proposal would increase revenues $63.9 million annually and allow IPC to begin recovery of its capital investments and higher operating costs. The application included a requested return on equity of 11.5 percent and an overall rate of return of 8.561 percent. IPC has requested that the rate increase become effective by January 2008.

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Capital requirements
IPC is experiencing a cycle of heavy infrastructure investment to address customer energy, capacity and reliability needs and aging plant and equipment. IPC's aging hydroelectric and thermal generation facilities require upgrades and component replacement. In addition, costs related to relicensing hydroelectric facilities and complying with the new licenses are substantial. Continuing load growth also requires that IPC add to its transmission system and distribution facilities to provide new service and to maintain reliability. Planned expenditures include distribution lines for new customers and several high-voltage transmission lines.

July 2007 high temperatures
IPC's service territory experienced record-setting high temperatures during July 2007. Due to these weather conditions and continued customer growth, IPC set three new all-time peaks between July 5 and July 13, 2007, with the highest, 3,193 MW being set on July 13, 2007. The previous hourly system peak of 3,084 MW, was set in 2006. IPC was able to meet all of its load requirements during these periods of increased demand through its system generation and by increasing the amount of purchased power.

IPC/PacifiCorp (MidAmerican) Memorandum of Understanding
IPC and PacifiCorp are jointly exploring a project to build two 500-kV lines between the Jim Bridger plant and Boise. The lines would be designed to meet the growth in customers' electricity needs and increase electrical transmission capacity across southern Idaho. If built, it is expected that portions of the project would be completed between 2012 and 2014 and IPC estimates that its share of project costs would be between $800 million and $1.2 billion.

CRITICAL ACCOUNTING POLICIES AND ESTIMATES:

IDACORP's and IPC's discussion and analysis of their financial condition and results of operations are based upon their condensed consolidated financial statements, which have been prepared in accordance with GAAP. The preparation of these financial statements requires IDACORP and IPC to make estimates and judgments that affect the reported amounts of assets, liabilities, revenues and expenses and related disclosure of contingent assets and liabilities. On an ongoing basis, IDACORP and IPC evaluate these estimates including those estimates related to rate regulation, benefit costs, contingencies, litigation, impairment of assets, income taxes, unbilled revenue 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, 2006, and have not changed materially from that discussion.

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RESULTS OF OPERATIONS:

This section of the MD&A takes a closer look at the significant factors that affected IDACORP's and IPC's earnings during the three and six months ended June 30, 2007. In this analysis, the results for 2007 are compared to the same period in 2006.

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

		Three Months Ended					Six Months Ended
		June 30,					June 30,
		2007			2006		2007	2006
Continuing operations:
IPC - Utility operations		$	16,164	$	21,612	$	39,495	$	46,633
IDACORP Financial Services			1,759		2,069		3,621		4,231
Ida-West Energy			836		1,030		1,042		1,363
IDACORP Energy			(21)		90		(76)		(111)
Holding Company			(273)		(2,128)		(1,036)		(2,488)
Income from continuing operations			18,465		22,673		43,046		49,628
Income (Losses) from discontinued operations			-		(2,817)		67		(4,296)
	Net income	$	18,465	$	19,856	$	43,113	$	45,332

Average common shares outstanding (diluted)			43,884		42,702		43,845	42,642
Diluted earnings (loss) per share:
	Income from continuing operations	$	0.42	$	0.53	$	0.98	$	1.16
	Losses from discontinued operations	$	-	$	(0.06)	$	-	$	(0.10)
	Diluted earnings per share	$	0.42	$	0.47	$	0.98	$	1.06

Utility Operations

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

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

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

	MWh
	Hydroelectric	Thermal	Total system	Purchased
	Generation	Generation	Generation	Power	Total
Three months ended:
June 30, 2007	1,539	1,461	3,000	1,527	4,527
June 30, 2006	3,038	1,215	4,253	1,786	6,039

Six months ended:
June 30, 2007	3,385	3,208	6,593	2,502	9,095
June 30, 2006	5,866	2,938	8,804	2,703	11,507

Significantly below normal winter precipitation and stream flow conditions negatively impacted hydroelectric generation during the first half of 2007 compared to 2006. On August 1, 2007, the National Weather Service's Northwest River Forecast Center indicated that Brownlee reservoir inflow for April through July 2007 was 2.8 maf, or 45 percent of average, a reduction from the 3.0 maf, or 48 percent of average, projected on May 7, 2007. Storage in selected federal reservoirs upstream of Brownlee as of July 31, 2007, was 70 percent of average. With current and forecasted stream flow conditions, IPC expects to generate between 6.0 and 6.5 million MWh from its hydroelectric facilities in 2007, compared to 9.2 million MWh in 2006.

IPC's system load peaks in the summer and winter, with the larger peak demand occurring in the summer. IPC's record system peak of 3,193 MW occurred on July 13, 2007. IPC was able to meet system load requirements and off-system sales requirements and had sufficient operating reserves in place.

General business revenue: The following table presents IPC's general business revenues, MWh sales, average number of customers and Boise, Idaho weather conditions for the three and six months ended June 30:

			Three Months Ended June 30,				Six Months Ended June 30,
			2007		2006		2007		2006
Revenue
	Residential		$	62,886	$	64,005	$	141,468	$	152,442
	Commercial			39,983		40,511		76,191		83,541
	Industrial			23,294		27,006		45,393		56,893
	Irrigation			36,049		27,688		36,411		28,517
		Total	$	162,212	$	159,210	$	299,463	$	321,393
MWh
	Residential			1,067		1,024		2,531		2,440
	Commercial			939		873		1,882		1,785
	Industrial			835		845		1,707		1,721
	Irrigation			815		593		820		607
		Total		3,656		3,335		6,940		6,553
Customers (average)
	Residential			396,282		385,980		395,373		384,494
	Commercial			61,279		58,701		61,014		58,490
	Industrial			127		132		126		132
	Irrigation			18,050		18,106		17,957		18,030
		Total		475,738		462,919		474,470		461,146

Heating degree-days				573		588		2,909		3,001
Cooling degree-days				288		269		288		269
Precipitation (inches)				2.24		3.83		4.02		8.20

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Heating and cooling degree-days are common measures used in the utility industry to analyze the demand for electricity and indicate when customers would use electricity for heating and air conditioning. A degree-day measures how much the average daily temperature varies from 65 degrees. Each degree of temperature above 65 degrees is counted as one cooling degree-day, and each degree of temperature below 65 degrees is counted as one heating degree-day.
General business revenue increased $3 million for the second quarter of 2007, primarily due to higher usage and customer counts, partially offset by a reduction in average rates.

Usage: Weather variations resulted in a $14 million increase in general business revenue as compared to the second quarter of 2006. Particularly dry conditions positively impacted irrigation revenues as compared with the prior year (precipitation was 42 percent lower as compared to the second quarter of 2006). Warm weather conditions also increased residential and commercial usage.
Customers: General business customer growth improved revenue $3 million for the quarter, as IPC continued to experience moderate customer growth in its service territory. The residential and commercial customer bases rose three percent and four percent, respectively, over the second quarter of the prior year.
Rates: Rate changes negatively impacted general business revenue by $15 million as compared to the second quarter of 2006. A PCA reduction on June 1, 2006, decreased rates by an average of 19.3 percent but was moderated by a base rate increase of 3.2 percent on June 1, 2006, and an average rate increase of 14.5 percent resulting from the PCA effective June 1, 2007. Prior year revenues also included approximately $4 million related to a rate case tax settlement and an irrigation load reduction rate adjustment, both of which were recovered from June 2005 to May 2006 (with a corresponding reduction to other revenues).

General business revenue decreased $22 million year-to-date 2007, primarily due to lower rates. The rate decreases were partially offset by higher usage and customer counts.

Rates: Rates negatively impacted general business revenue by $42 million as compared to 2006. A PCA reduction on June 1, 2006, decreased rates by an average of 19.3 percent but was moderated by a base rate increase of 3.2 percent on June 1, 2006, and the new PCA rate increase of 14.5 percent on average effective June 1, 2007. Prior year revenues also included approximately $10 million related to a rate case tax settlement and an irrigation load reduction rate adjustment, both of which were recovered from June 2005 to May 2006 (with a corresponding reduction to other revenues).
Usage: Weather variations resulted in a $14 million increase in general business revenue as compared to 2006. Particularly dry conditions positively impacted irrigation revenues as compared to the prior year (precipitation was 51 percent lower as compared to 2006). Warm weather conditions also increased residential and commercial usage.
Customers: General business customer growth improved revenue $6 million for the year, as IPC continued to experience moderate customer growth in its service territory. The residential and commercial customer bases rose three percent and four percent, respectively, over the prior year.

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

	Three months ended					Six months ended
	June 30,					June 30,
	2007		2006			2007	2006

Revenue	$	37,177	$	75,598	$	95,016	$	179,839
MWh sold		526		2,343		1,490		4,286
Revenue per MWh	$	70.70	$	32.27	$	63.77	$	41.95

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Deteriorated stream flow conditions for the quarter and year-to-date significantly decreased hydroelectric generation and electricity available for surplus sales. Revenue declines from lower sales volumes were moderated by higher prices. Prior year prices were lower because of abundant energy supplies in the region. Beginning in 2007, IPC is utilizing financial hedge instruments in addition to physical forward power transactions for the purpose of mitigating price risk related to conforming to IPC's energy risk management policy, managing IPC's energy portfolio to meet customer load, and reacting to changes in market conditions to minimize net power supply costs.

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

		Three months ended				Six months ended
		June 30,				June 30,
		2007		2006		2007		2006

Transmission services and property rental		$	11,016	$	10,313	$	20,284	$	17,429
DSM revenues			2,548		-		4,663		-
Rate case tax settlement			-		(1,891)		-		(4,846)
Irrigation load reduction			-		(2,207)		-		(5,518)
Provision for rate refund			(427)		(175)		(971)		(175)
	Total	$	13,137	$	6,040	$	23,976	$	6,890

Beginning in January 2007, a new IPUC accounting order became effective for the treatment of IPC's DSM expenses. DSM costs were recorded in Other operations and maintenance expenses and were offset by the same amount recorded in Other revenues resulting in no net effect on earnings. See "Other operating and maintenance expenses."

The remaining increase in Other revenues is largely due to higher wheeling revenues and to the completed amortization of tax settlement and irrigation lost revenue accruals. From June 2005 to May 2006, IPC was collecting and recording in general business revenues, with a corresponding reduction to Other revenues, amounts related to a 2003 Idaho general rate case tax settlement and amounts related to an irrigation load reduction program. Revenues for the rate case tax settlement were accrued from September 2004 to May 2005.

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

	Three months ended				Six months ended
	June 30,				June 30,
	2007			2006	2007		2006

Purchases	$	80,467	$	74,808	$	131,285	$	130,733
MWh purchased		1,527		1,786		2,502		2,703
Cost per MWh purchased	$	52.70	$	41.88	$	52.47	$	48.36

The increase in purchased power is primarily due to higher energy prices. Lower market prices in the first half of 2006 were caused by abundant energy supplies in the region. Prior year purchase volume was also higher, a result of third-party forward purchases required by the energy risk management policy (early water predictions for 2006 suggested continued drought conditions, which did not actually materialize). The volume of purchase activities is the result of conforming to IPC's energy risk management policy, managing IPC's energy portfolio to meet customer load, and reacting to changes in market conditions to minimize net power supply costs. Beginning in 2007, IPC is utilizing financial hedge instruments in addition to physical forward power transactions for the purpose of mitigating price risk related to conforming to IPC's energy risk management policy, managing IPC's energy portfolio to meet customer load, and reacting to changes in market conditions to minimize net power supply costs.

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

	Three months ended					Six months ended
	June 30,					June 30,
	2007			2006		2007	2006

Fuel expense	$	27,520	$	21,954	$	58,432	$	48,923
Thermal MWh generated		1,462		1,215		3,208		2,938
Cost per MWh	$	18.83	$	18.07	$	18.21	$	16.65

Fuel expense increased in large part due to increased utilization of coal-fired and gas-fired resources, a result of poor hydroelectric generating conditions. Rising fuel prices also contributed to the increase. The increased cost of coal is due primarily to higher market demand and higher production costs at the Jim Bridger coal mine as well as higher rail transportation costs. The rise in rail transportation costs was driven by higher diesel fuel costs, including an adjustable fuel surcharge.

PCA: PCA expense represents the effects of IPC's PCA regulatory mechanism in Idaho and Oregon deferrals of net power supply costs, which are discussed in more detail below in "REGULATORY MATTERS - Deferred (Accrued) Net Power Supply Costs."

In the second quarter of 2007, lower off-system sales, coupled with increased coal and natural gas utilization, caused a significant increase in net power supply costs (fuel and purchased power less off-system sales) over the amounts in the annual PCA forecast. This increase in net power supply costs was largely a result of deteriorated hydroelectric generating conditions in 2007, resulting in the deferral of costs which will be recovered in subsequent rate years. As the deferred costs are recovered in rates, the deferred balances are amortized.

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

		Three months ended				Six months ended
		June 30,				June 30,
		2007		2006		2007			2006
Current year power supply cost accrual (deferral)		$	(39,633)	$	2,839	$	(57,966)	$	43,718
Amortization of prior year authorized balances			(2,539)		1,761		(5,742)		4,349
	Total power cost adjustment	$	(42,172)	$	4,600	$	(63,708)	$	48,067

Other operating and maintenance expenses: Other operations and maintenance expenses increased $9 million (excluding $3 million of DSM costs), or 13 percent, for the quarter and $15 million (excluding $5 million of DSM costs), or 12 percent, year-to-date as compared to the same periods in 2006.

The second quarter 2007 increase was primarily attributable to:

An increase of $2 million in third-party transmission costs;
An increase in labor-related expense of $2 million;
An increase in maintenance expenses of $2 million as a result of planned outages and maintenance activities at coal-fired plants and increased maintenance of distribution lines; and
An increase of $2 million in legal, regulatory, and compliance expenses.

The year-to-date 2007 increase was primarily attributable to:

An increase in labor-related expense of $4 million;
An increase in maintenance expenses of $4 million as a result of planned outage and maintenance activities at coal-fired plants and increased maintenance of distribution lines;
An increase of $3 million in legal, regulatory and compliance expenses;
An increase of $1 million in third-party transmission costs; and
An increase of approximately $1 million from the FCA mechanism, which became effective beginning January 1, 2007.

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IPC's DSM programs provide opportunities for all customer classes to balance their energy needs with best-practice energy usage to minimize consumption while realizing the benefits of reliable electrical service. IPC's 2006 IRP laid the groundwork for the planning and implementation of future programs, including the addition of three new DSM programs. In addition to the DSM programs identified in the 2006 IRP, IPC has also continued to pursue other customer-focused DSM initiatives, including conservation programs and educational opportunities.

Non-utility operations

IFS: IFS' contribution decreased slightly in 2007 to $2 million and $4 million for the second quarter and year-to-date, respectively. IFS' income is derived principally from the generation of federal income tax credits and accelerated tax depreciation benefits related to its investments in affordable housing and historic rehabilitation developments. IFS generated $4 million and $7 million of tax credits in the second quarter and year-to-date, respectively, and expects to continue delivering tax benefits at a level commensurate with the ongoing needs of IDACORP.

Discontinued Operations: In the second quarter of 2006, IDACORP management designated the operations of ITI and IDACOMM as assets held for sale, as defined by SFAS 144. The operations of these entities are presented as discontinued operations in IDACORP's financial statements.

On February 23, 2007, IDACORP completed the sale of all of the outstanding common stock of IDACOMM to American Fiber Systems, Inc.

Discontinued operations had no material impact on earnings in 2007, as compared to a net loss of $3 million and $4 million for the three and six months ended June 30, 2006, respectively.

Income Taxes

In accordance with interim reporting requirements, IDACORP and IPC use an estimated annual effective tax rate for computing their provisions for income taxes. IDACORP's effective rate on continuing operations for the six months ended June 30, 2007, was 16.2 percent, compared to 23.6 percent for the six months ended June 30, 2006. IPC's effective tax rate for the six months ended June 30, 2007, was 34.3 percent, compared to 39.4 percent for the six months ended June 30, 2006.

LIQUIDITY AND CAPITAL RESOURCES:

Discontinued operations
Cash flows from discontinued operations are included with the cash flows from continuing operations in IDACORP's Consolidated Statements of Cash Flows. The cash flows of IDACORP's discontinued operations have reduced net cash provided by operating activities and increased net cash used in investing activities, except for the cash received in February 2007 from the sale of IDACOMM and in July 2006 from the sale of ITI. The absence of cash flows from these discontinued operations is expected to positively impact liquidity and capital resources in future periods.

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Operating cash flows
IDACORP's and IPC's operating cash flows for the six months ended June 30, 2007, were both $41 million. Compared to 2006, operating cash flows decreased approximately $105 million and $75 million for IDACORP and IPC, respectively. The decreases are primarily the result of power supply costs deferred for future recovery under IPC's PCA mechanism, partially offset by decreased income tax payments of $31 million and $50 million, respectively.

Investing cash flows
IDACORP's and IPC's investing cash outflows for the six months ended June 30, 2007, were $113 million and $120 million, respectively, compared to $101 million and $100 million, respectively, for the six months ended June 30, 2006. Utility construction at IPC accounted for substantially all of its cash outflows. For IDACORP, IPC's investing outflows were partially offset by $7 million cash received from the sale of IDACOMM in 2007. Cash inflows from emission allowance sales were $3 million and $11 million in 2007 and 2006, respectively.

Financing cash flows
Debt issuances: On June 22, 2007, IPC issued $140 million of its 6.30% First Mortgage Bonds, Secured Medium-Term Notes, Series F, due June 15, 2037. IPC used the net proceeds to pay down outstanding commercial paper, which had increased to $164 million in June 2007 because of capital expenditures and reduced operating cash flows.

Equity Issuances: In June 2007, IDACORP received $8 million from the issuance of 254,500 shares of common stock under its Continuous Equity Program (CEP). An additional $8 million was received in July 2007 for the issuance of 245,500 shares under the CEP. The average price of these issuances was $32.04.

Under IDACORP's dividend reinvestment and stock purchase plan and employee savings plan, IDACORP issued 128,463 common shares for proceeds of $4 million.

Capital requirements
IDACORP's internal cash generation after dividends is expected to provide less than the full amount of total capital requirements for 2007 through 2009, 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. As discussed in IDACORP's 2006 Form 10-K, IDACORP may fund capital requirements with a combination of internally generated funds, the use of revolving credit facilities and the issuance of long-term debt and equity.

Long-term Financing
IPC currently has in place a shelf registration statement that can be used for the issuance of an aggregate principal amount of $100 million of first mortgage bonds (including medium-term notes).

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The IDACORP Facility and the IPC Facility both contain a covenant requiring each company to maintain a leverage ratio of consolidated indebtedness to consolidated total capitalization of no more than 65 percent as of the end of each fiscal quarter. At June 30, 2007, the leverage ratios for both IDACORP and IPC were 51 percent. At June 30, 2007, IDACORP was in compliance with all other covenants of the IDACORP Facility and IPC was in compliance with all other covenants of the IPC Facility. See IDACORP's and IPC's Current Report on Form 8-K filed on May 1, 2007, for a discussion of the terms of the IDACORP Facility and the IPC Facility.

Contractual obligations
There have been no material changes in contractual obligations, outside of the ordinary course of business, since December 31, 2006, except for a new power purchase agreement entered into by IPC with Telocaset Wind Power Partners, LLC, that is expected to total approximately $400 million over its 20-year life. This contract is discussed more fully in "REGULATORY MATTERS - Integrated Resource Plan - Wind RFP."

LEGAL AND ENVIRONMENTAL ISSUES:

Legal and Other Proceedings

Reference is made to IDACORP's and IPC's Annual Report on Form 10-K for the year ended December 31, 2006, and Quarterly Report on Form 10-Q for the quarter ended March 31, 2007, for a discussion of all material pending legal proceedings to which IDACORP and IPC and their subsidiaries are parties. The following discussion provides a summary of material developments that occurred in those proceedings during the period covered by this report and of any new material proceedings instituted during the period covered by this report.

Wah Chang: Wah Chang's appeal to the U.S. Court of Appeals for the Ninth Circuit of the February 11, 2005, dismissal of the case by the Honorable Robert H. Whaley, sitting by designation in the U.S. District Court for the Southern District of California, was orally argued on April 10, 2007. The matter now awaits decision by the Ninth Circuit. IDACORP, IPC and IE intend to vigorously defend their position in this proceeding and believe this matter will not have a material adverse effect on their consolidated financial positions, results of operations or cash flows.

Western Energy Proceedings at the FERC:

California Refund: In April 2001, the FERC issued an order stating that it was establishing a price mitigation plan for sales in the California Wholesale electricity market. That plan included the potential for orders directing electricity sellers into California from October 2, 2000 through June 20, 2001 to refund the 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. On July 25, 2001, the FERC issued an order initiating the California Refund proceeding including evidentiary hearings to determine the scope and methodology for determining refunds. On February 17, 2006, IE and IPC jointly filed with the California Parties (Pacific Gas & Electric Company, San Diego Gas & Electric Company, Southern California Edison, the California

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Public Utilities Commission, the California Electricity Oversight Board, the California Department of Water Resources and the California Attorney General) an Offer of Settlement at the FERC. A number of other parties, representing substantially less than the majority of potential refund claims, chose to opt out of the Settlement. After consideration of comments, the FERC approved the Offer of Settlement on May 22, 2006.

On June 21, 2006, the Port of Seattle, Washington filed a request for rehearing of the FERC order approving the Settlement. The FERC issued an order on October 5, 2006, denying the Port of Seattle's request for rehearing. On October 24, 2006, the Port of Seattle petitioned the U.S. Court of Appeals for the Ninth Circuit for review of the FERC orders approving the Settlement. The Ninth Circuit consolidated that review petition with the large number of review petitions already consolidated before it and has stayed further action on the consolidated cases, while the court's mediator and FERC representatives work on achieving settlements with other parties. On January 23, 2007, IPC and IE filed a motion to sever the Port of Seattle's petition for review from the bulk of cases pending in the Ninth Circuit with which it had been consolidated. IPC and IE also filed a motion to dismiss the Port of Seattle's petition for review. On April 11, 2007, the Ninth Circuit filed an order denying IPC's and IE's motion to sever. The motion to dismiss was denied without prejudice to renew when briefs are filed. IPC and IE are unable to predict when or how the Ninth Circuit might rule on Port of Seattle's petition for review.

Market Manipulation: As part of the California and Pacific Northwest Refund proceedings, on November 20, 2002 the FERC issued an order permitting discovery and the submission of evidence regarding market manipulation by sellers during the western energy crisis of 2000 and 2001. 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" or anomalous market behavior ("partnership") in violation of the California Independent System Operator and California Power Exchange 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. Originally, eight parties sought rehearing of the "gaming" settlement. The FERC approved the motion to dismiss the "partnership" proceeding on January 23, 2004.

On October 11, 2006, the FERC issued an Order denying rehearing of its earlier approval of the "gaming" Settlement. On October 24, 2006, the Port of Seattle, Washington appealed to the U.S. Court of Appeals for the Ninth Circuit FERC's denial of its request for rehearing of its order granting approval of the settlement of the gaming allegations against IE and IPC. On November 17, 2006, the Ninth Circuit consolidated the Port of Seattle's review petition with a large number of review petitions previously consolidated and has stayed further action on the consolidated cases while the court's mediator and FERC representatives work on achieving settlements with other parties.

In addition, a number of parties have petitioned the Ninth Circuit Court of Appeals contending that the scope of the show cause proceedings was too narrow, but these petitions have been stayed. IE and IPC are unable to predict the outcome of these matters.

Pacific Northwest Refund: On June 19, 2001, the FERC expanded its price mitigation plan for the California Wholesale electricity market discussed above under "California Refund" to the entire western electrically interconnected system. This expansion led to the Pacific Northwest Refund proceeding. On September 24, 2001, the FERC Administrative Law Judge submitted recommendations and findings to the FERC finding that prices in the Pacific Northwest during the December 25, 2000 through June 20, 2001 time period should be governed by the Mobile-Sierra standard of public interest rather than the just and reasonable standard, that the Pacific Northwest spot markets were competitive and that no refunds should be allowed. The FERC declined to order refunds on June 25, 2003 and multiple parties then appealed to the Ninth Circuit Court of Appeals. IE and IPC were parties in the FERC proceeding and are participating in the appeal. Briefing on the appeal was completed on May 25, 2005, and oral argument was held on January 8, 2007. The Settlement in the California Refund proceeding resolves all claims the California Parties have against IE and IPC in the Pacific Northwest proceeding. IE and IPC are unable to predict the outcome of these matters.

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On May 21, 2007, the U.S. District Court for the District of Idaho (Judge Edward J. Lodge) granted the defendants' motion to dismiss the amended complaint because it failed to satisfy the pleading requirements for loss causation. The court also denied the plaintiffs' request to further amend the complaint.

Sierra Club Lawsuit-Bridger: In February 2007, the Sierra Club and the Wyoming Outdoor Council filed a complaint against PacifiCorp in federal district court in Cheyenne, Wyoming alleging violations of air quality opacity standards at the Jim Bridger coal-fired plant (Plant) in Sweetwater County, Wyoming. Opacity is an indication of the amount of light obscured in the flue gas of a power plant. A formal answer to the complaint was filed by PacifiCorp on April 2, 2007, in which PacifiCorp denied almost all of the allegations and asserted a number of affirmative defenses. IPC is not a party to this proceeding but has a one-third ownership interest in the Plant. PacifiCorp owns a two-thirds interest and is the operator of the Plant. The complaint alleges thousands of opacity permit limit violations by PacifiCorp and seeks a declaration that PacifiCorp has violated opacity limits, a permanent injunction ordering PacifiCorp to comply with such limits, civil penalties of up to $32,500 per day per violation and the plaintiff's costs of litigation, including reasonable attorney fees.

The U.S. District Court has set this matter for trial commencing in April 2008. Discovery in the matter is ongoing. IPC continues to monitor the status of this matter, but is unable to predict its outcome and is unable to estimate what effect this matter may have on its consolidated financial position, results of operations or cash flows.

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 and IPC's Consolidated Financial Statements. Resolution of any of these matters will take time and the companies cannot predict the outcome of any of these proceedings. The companies believe that their reserves are adequate for these matters.

Other Matters: The Bennett Mountain combustion turbine suffered a mechanical failure on July 11, 2006. IPC's investigation has revealed that during construction a bolt was negligently installed by a third party. The bolt came loose, causing extensive mechanical damage. The plant was down from July 12, 2006, through September 6, 2006. IPC has received reimbursement for the bulk of the total repair costs from its insurance carrier and is attempting to recover an additional $3 to $4 million from the responsible third parties. IPC is unable to predict the likelihood of such recovery.

Environmental Issues
The section below summarizes and provides an update of environmental issues as discussed in IDACORP's and IPC's Annual Report on Form 10-K for the year ended December 31, 2006, and Quarterly Report on Form 10-Q for the quarter ended March 31, 2007.

Idaho Water Management Issues: From 2000 through 2005, and year-to-date 2007, below normal precipitation and stream flows have exacerbated a developing water shortage in Idaho, manifested by a number of water issues including declining Snake River base flows and declining levels in the Eastern Snake Plain Aquifer (ESPA), a large underground aquifer that has been estimated to hold between 200 - 300 maf of water. These issues are of interest to IPC because of their potential impacts on generation at IPC's hydroelectric projects.

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As a result of declines in river flows, in 2003 several surface water users filed delivery calls with the Idaho Department of Water Resources (IDWR), demanding that it manage ground water withdrawals pursuant to the prior appropriation doctrine of "first in time is first in right" and curtail junior ground water rights that are depleting the aquifer and affecting flows to senior surface water rights. These delivery calls have resulted in several administrative actions before the IDWR to enforce senior water rights as well as judicial actions before the state court challenging the constitutionality of state regulations used by the IDWR to conjunctively administer ground and surface water rights. Because IPC holds water rights that are dependent on the Snake River, spring flows and the overall condition of the ESPA, IPC continues to participate in these actions, as necessary, to protect its water rights.

IPC, together with other interested water users and state interests, also continues to explore and encourage the development of a long-term management plan that will protect the ESPA and the Snake River from further depletion. On February 14, 2007, the Idaho Water Resource Board (IWRB) presented the framework for an ESPA management plan to the Idaho Legislature recommending the development of a Comprehensive Aquifer Management Plan (CAMP). The proposed goal of the CAMP is to sustain the economic viability and social and environmental health of the ESPA by adaptively managing a balance between water use and supplies. The IWRB estimates that the development of the CAMP will take 16 months. Through House Concurrent Resolution 28 and House Bill 320, the Idaho Legislature appropriated funds and directed the IWRB to proceed with the development of the CAMP. Pursuant the IWRB recommendation in the CAMP Framework, an advisory committee has been established to make recommendations to the IWRB on the development of the CAMP. IPC sits on the CAMP advisory committee and will be working with the IWRB on the development of the CAMP.

IPC is also engaged in the Snake River Basin Adjudication (SRBA), a general stream adjudication, commenced in 1987, to define the nature and extent of water rights in the Snake River basin in Idaho, including the water rights of IPC. The initiation of the SRBA resulted from the Swan Falls Agreement, an agreement entered into by IPC and the Governor and Attorney General of Idaho in October 1984 to resolve litigation relating to IPC's water rights at its Swan Falls project. IPC has filed claims to its water rights for hydropower and other uses in the SRBA. Other water users in the basin have also filed claims to water rights. Parties to the SRBA may file objections to water right claims that adversely affect or injure their claimed water rights and the court then adjudicates the claims and objections and enters a decree defining a party's water right. IPC has filed claims for all of its hydropower water rights in the SRBA, is actively protecting those water rights, and is objecting to claims that may potentially injure or affect those water rights. One such claim involves a notice of claim of ownership filed on December 22, 2006, by the State of Idaho, for a portion of the water rights held by IPC that are subject to the Swan Falls Agreement.

On May 10, 2007, in order to protect its claims and the availability of water for power purposes at its facilities, and in response to the claim of ownership filed by the State, IPC filed a complaint and petition for declaratory and injunctive relief regarding the status and nature of IPC's water rights and the respective rights and responsibilities of the parties under the Swan Falls Agreement. The complaint was filed in the Idaho District Court for the Fifth Judicial District, the court with jurisdiction over the SRBA, against the State of Idaho, the Governor, the Attorney General, the IDWR and the Director of the IDWR.

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On July 23, 2007, the court issued an Order granting in part and denying in part the State's motion to dismiss, consolidating the issues into a consolidated subcase before the court, providing for discovery during the objection period and setting a scheduling conference for December 17, 2007. In its Order, the court denied the majority of the State's motion to dismiss, refusing to dismiss the complaint and finding that the court has jurisdiction to hear and determine virtually all the issues raised by IPC's complaint that relate to IPC's water rights and the effect of the Swan Falls Agreement upon those water rights. This includes the issues of ownership, whether IPC's water rights are subordinated to recharge and how those water rights are to be administered relative to other water rights on the same or connected resources. The court did find that by virtue of a state statute the IDWR, and its director, could not be parties to the SRBA and therefore stayed IPC's claims against the IDWR and its director pending resolution of the issues to be litigated in the SRBA, or until further order of the court.

Air Quality Issues: IPC owns two natural gas combustion turbine power plants and co-owns three coal-fired power plants that are subject to air quality regulation. The natural gas-fired plants, Danskin and Bennett Mountain, are located in Idaho. The coal-fired plants are: Jim Bridger (33 percent interest) located in Wyoming; Boardman (ten percent interest) located in Oregon; and North Valmy (50 percent interest) located in Nevada. The Clean Air Act establishes controls on the emissions from stationary sources like those owned by IPC in Idaho, Nevada, Oregon, and Wyoming. The Environmental Protection Agency (EPA) adopts many of the standards and regulations under the Clean Air Act while states have the primary responsibility for implementation and administration of these air quality programs. IPC continues to actively monitor, evaluate and work on air quality issues pertaining to the Clean Air Mercury Rule (CAMR), possible legislative amendment of the Clean Air Act, emerging greenhouse gas programs at the federal, regional and state levels, New Source Review permitting, National Ambient Air Quality Standards, and Regional Haze - Best Available Retrofit Technology. Low NOx burner technology and mercury continuous emission monitor installation are progressing at all three coal-fired power plants.

In December 2006, National Ambient Air Quality Standards for fine particulate matter adopted by EPA became effective. This new standard has been challenged by a number of groups in the U.S. Court of Appeals for the District of Columbia Circuit. All of the counties in Idaho, Nevada, Oregon, and Wyoming where IPC's power plants operate are currently designated as meeting attainment with federal air quality standards, including the new particulate matter standard. Nevertheless, under the new fine particulate standards, three years of data are being collected to determine the attainment status of all U.S. counties. The impact of these new standards will not be known until these data are collected, analyzed, and released to the public and the associated regulatory programs are promulgated and implemented.

The CAMR, issued by the EPA on March 15, 2005, limits 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 response to the CAMR, the Idaho Department of Environmental Quality (IDEQ) proposed two new rules to the Idaho Environmental Quality Commission: a rule to opt out of the federal mercury cap-and-trade program, and a rule to prohibit the construction and operation of a coal-fired power plant in Idaho. In April 2006, the governor of Idaho signed House Bill 791, which placed a two year moratorium on applying for or issuance of permits, licenses or construction of certain coal-fired power plants in Idaho. The moratorium expires on April 7, 2008. During the 2007 Idaho state legislative session, the state did not reject the proposal to opt out of the cap-and-trade program, therefore accepting the opt out rule. IPC has no current plans impacted by the moratorium or opting out of the CAMR cap-and-trade program.

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Greenhouse Gases: IPC continues to monitor and evaluate the possible adoption of national, regional, or state climate change and greenhouse gas (GHG) requirements that would affect electric utilities. At the national level, numerous GHG bills have been introduced in the U.S. Senate and House of Representatives during 2006 and 2007. Debate continues in Congress on the direction and scope of U.S. policy on climate change and regulation of GHGs. In the western U.S., California's governor signed an executive order in 2005 to reduce GHGs in that state to designated historical levels. In August 2006, California enacted a GHG emission performance standard applicable to all electricity generated within the state or delivered from outside the state. Oregon passed the Global Warming Integration Act in June 2007 which, among other things, established the Oregon Global Warming Commission and state-wide GHG emission reduction goals. The Washington state legislature passed a bill in April 2007 setting climate pollution reduction and clean energy goals. Emission performance standards affecting electric utility contracts and power plant projects are included. Other regional and state GHG initiatives appear likely. National, regional or state GHG requirements, if enacted and applicable, could result in significant costs to IPC to comply with restrictions on carbon dioxide or other GHG emissions.

As part of IPC's resource planning protocol, the IRP process considers GHG emissions regulation and other environmental factors when evaluating potential portfolios. Environmental impacts have been and will continue to be integral components of resource decisions. Information about IDACORP's carbon dioxide emissions is included in the report Benchmarking Air Emissions of the 100 Largest Electric Power Producers in the United States - 2004. This report was released by the Ceres Investor Coalition, the Natural Resources Defense Council and the Public Service Enterprise Group Inc. in April 2006. The report lists IPC's 2004 carbon dioxideemissions at 1,222.0 lbs/MWh, as compared to the reported average for the 100 largest power producers of 1,341.8 lbs/MWh. IPC's carbon dioxide emissions on a lbs/MWh basis fluctuate with the amount of hydroelectric generation. Even during a low water year like 2004, IPC's emissions were below the average of the 100 largest power producers. During 2006, IPC's carbon dioxide emissions were approximately 917 lbs/MWh.

REGULATORY MATTERS:

General Rate Cases
Idaho: On June 8, 2007, IPC filed an application with the IPUC requesting an average rate increase of approximately 10.35 percent for its Idaho customers in order to begin recovery of its capital investments and higher operating costs. IPC's proposal would increase its revenues $63.9 million annually. The application included a requested return on equity of 11.5 percent and an overall rate of return of 8.561 percent. IPC filed its case based upon a 2007 forecast test year, a first for IPC in the Idaho jurisdiction. Since IPC's last general rate case filing in 2005, IPC projects that it will have placed in service an additional $300 million of investment in its electrical system during 2006 and 2007. IPC also requested a $29.16 per MWh Load Growth Adjustment Rate (LGAR), which subtracts the cost of serving new Idaho retail customers from the power supply costs IPC is allowed to include in the PCA. The existing LGAR is $29.41 per MWh. The impact of the new LGAR on IPC will ultimately be determined by future growth. By IPUC order, the LGAR is reset in general rate case proceedings. IPC has requested that the rate increase become effective by January 2008. IPC is unable to predict what relief the IPUC will grant.

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

		June 30,		December 31,
		2007		2006
Idaho PCA current year:
	Accrual for the 2007-2008 rate year *	$	-	$	(3,484)
	Deferral for the 2008-2009 rate year		39,815		-
Idaho PCA true-up awaiting recovery (refund):
	Authorized May 2006		-		(11,689)
	Authorized May 2007		10,571		-
Oregon deferral:
	2001 costs		4,955		6,670
	2005 costs		-		2,889
	Total deferral (accrual)	$	55,341	$	(5,614)
* Includes $69 million of emission allowance sales to be credited to the customers during the 2007-2008 PCA year.

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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.

Oregon: On April 28, 2006, IPC filed for an accounting order with the OPUC to defer net power supply costs for the period of May 1, 2006, through April 30, 2007, in anticipation of higher than "normal" power supply expenses. In the Oregon general rate case, "normal" power supply expenses were set at a negative number (meaning that under normal water conditions IPC should be able to sell enough surplus energy to pay for all fuel and purchased power expenses and still have revenue left over to offset other costs). IPC requested authorization to defer an estimated $3.3 million, which is Oregon's jurisdictional share of the excess power supply costs. IPC also requested that it earn its Oregon authorized rate of return on the deferred balance and recover the amount through rates in future years, as approved by the OPUC. Settlement discussions were held on April 25, 2007, and a tentative settlement agreement was reached on the deferral application with the OPUC Staff and the Citizens' Utility Board in the amount of $2 million. This amount is subject to approval by the OPUC. The parties also agreed that IPC would file an application for an Oregon PCA mechanism. On April 25, 2007, the parties agreed in principal to a settlement stipulation which would resolve the 2006-2007 deferral case. IPC has drafted a stipulation which is currently being circulated for comment. Oregon PCA mechanism discussions are expected to continue under a separate docket.

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

On March 2, 2005, IPC filed for an accounting order with the OPUC to defer net power supply costs for the period of March 2, 2005 through February 28, 2006, in anticipation of continued low water conditions. The forecasted net power supply costs related to the Oregon jurisdiction that were included in this filing were $3 million. On March 5, 2007, IPC, the OPUC Staff and the Citizen's Utility Board entered into a stipulation under which the parties agreed that IPC appropriately deferred approximately $2.7 million during the 2005 deferral period. The stipulation also provided that, rather than amortizing the 2005 deferral into rates, IPC should offset the balance with the Oregon jurisdictional share of proceeds from the sale of excess SO₂ emission allowances and the benefit that IPC will receive from income taxes already paid on the sale of those allowances. The OPUC approved the stipulation on April 2, 2007.When combined, these offsets exceed the 2005 deferral balance, and the excess was applied to the 2001 deferral balance.

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IPC and the IPUC Staff agreed in concept to a three-year pilot beginning January 1, 2007, and a stipulation was filed on December 18, 2006. The stipulation called for the implementation of a FCA mechanism pilot program as proposed by IPC in its original application with additional conditions and provisions related to customer count and weather normalization methodology, recording of the FCA deferral amount in reports to the IPUC and detailed reporting of DSM activities. The IPUC approved the stipulation on March 12, 2007. The pilot program began retroactively on January 1, 2007, and will run through 2009, with the first rate adjustment to occur on June 1, 2008, and subsequent rate adjustments to occur on June 1 of each year thereafter during the term of the pilot program. IPC accrued $1.1 million of FCA expense through the second quarter of 2007.

Cassia Wind Farm Complaint
On September 13, 2006, Cassia Gulch Wind Park, LLC and Cassia Wind Farm, LLC (collectively Cassia) filed a complaint against IPC with the IPUC requesting the IPUC to determine that the cost responsibility for specified transmission system upgrades to meet contingency planning conditions should not be assigned to PURPA qualifying facilities connecting to the system, but rather should be rolled into IPC's plant-in-service rate base and recovered through rates to retail and transmission customers. The estimated costs of transmission system upgrades included in this complaint that relate to connecting Cassia to IPC's system are $60 million. Comments were filed in October and November 2006, and oral arguments were held in November 2006. On June 13, 2007, IPC and Cassia filed a Joint Motion to Dismiss the underlying complaint and to approve a related settlement stipulation.

The key component of the stipulation is the concept of "redispatch." IPC's estimated cost of approximately $60 million to complete necessary transmission network upgrades was based on the assumption that the requesting projects in the transmission queue would not be dispatchable. Under the stipulation, Cassia agrees to install, at its expense, equipment and communication facilities necessary to reduce its energy output to a predetermined set-point within ten minutes of when IPC requests the reduction. Based on these provisions, the original estimate of $60 million decreases to approximately $11 million. Under the stipulation, IPC would fund 25 percent of any upgrade investment, which would be recoverable through rates, while the developer would fund 25 percent that is non-recoverable and 50 percent that is recoverable over time. The stipulation also addresses responsibility for network upgrade costs, sharing of network upgrade costs, refunds and interests on refunds and security for payment. The deadline for filing written comments or protests was July 25, 2007. The deadline for filing reply comments was August 6, 2007.

AMI Report
IPC filed its Advanced Metering Infrastructure (AMI) Status Report with the IPUC on May 1, 2007, in compliance with Commission Order No. 30102. The report details IPC's resolution of the AMI-related issues identified in the December 2005 AMI Status Report. IPC will submit to the IPUC no later than September 1, 2007, a supplement to the report detailing its assessment of how it will proceed with AMI deployment.

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Federal Regulatory Matters
The Bonneville Power Administration Residential Exchange Program: The Pacific Northwest Electric Power Planning and Conservation Act of 1980, through the Residential Exchange Program, provides access to the benefits of low-cost federal hydroelectric power to residential and small farm customers of the region's investor-owned utilities. The program is administered by the Bonneville Power Administration (BPA). IPC entered into settlement agreements with the BPA which settled IPC's rights under the Residential Exchange Program for the fiscal year 2002-2006 rate period and for the fiscal year 2007-2011 rate period. Pursuant to these agreements between the BPA and IPC, benefits from the BPA were passed through to IPC's Idaho and Oregon residential and small-farm customers in the form of electricity bill credits.

Several of the BPA's publicly owned and the direct-service industry customers filed lawsuits against the BPA with the United States Court of Appeals for the Ninth Circuit challenging certain aspects of the BPA's agreements with IPC, as well as those with other investor-owned utilities, and challenging the level of benefits previously paid to investor-owned utility customers. On May 3, 2007, the Ninth Circuit Court of Appeals ruled that the settlement agreements entered into between the BPA and the investor-owned utilities (including IPC) are inconsistent with the Northwest Power Act. On May 21, 2007, the BPA notified IPC and six other investor-owned utilities that it was immediately suspending the Residential Exchange Program payments that the utilities pass through to their residential and small-farm customers in the form of electricity bill credits. IPC took action with both the IPUC and the OPUC to reduce the level of credit on its customers' bill to zero, effective June 1, 2007.

Since these benefits were passed through to IPC's customers, the outcome of this matter is not expected to have a significant effect on IPC's financial condition or results of operations. IPC is working, along with the other northwest investor-owned utilities, northwest state public utility commissions and the BPA, to craft an agreement so that residential and small farm customers of IPC can resume sharing in the benefits of the federal Columbia River power system.

FERC Investigation: On March 28, 2007, the FERC advised IPC that the FERC was commencing a preliminary, non-public investigation into the pricing and availability of transmission capacity into and out of IPC's IPCO point of delivery and transactions related to that transmission capacity during the period January 1, 2003 to present. Subsequently, the FERC made a data request in connection with this investigation, IPC responded to that data request on June 1, 2007, and supplemented its response on July 27, 2007. IPC is unable to predict the outcome of this investigation.

FERC Proceedings:
Open Access Transmission Tariff (OATT): On March 24, 2006, IPC submitted a revised OATT filing with the FERC requesting an increase in transmission rates. The purpose of the filing was to implement formula rates for the IPC OATT in order to more adequately reflect the costs that IPC incurs in providing transmission service. In the filing IPC proposed to move from a fixed rate to a formula rate, which allows for transmission rates to be updated each year based on FERC Form 1 data. The formula rate request included a rate of return on equity of 11.25 percent. The proposed rates would have produced an annual revenue increase of approximately $13 million based on 2004 test year data. On May 31, 2006, the FERC accepted IPC's rates, effective June 1, 2006, subject to adjustment to conform to SFAS 109 tax accounting requirements, which lowered the estimated annual revenues to approximately $11 million. The rates are being collected subject to refund pending the outcome of the FERC hearing process. Settlement discussions were held in April and May of 2007 at which the parties to the proceeding reached settlement on all issues except the treatment of contracts in existence before the implementation of OATT in 1996 (Legacy Agreements). On June 15, 2007, the parties filed a settlement agreement with the FERC for the settled issues. The settlement agreement is awaiting FERC approval. IPC estimates the impact of the settlement will reduce expected revenues by $1 million to $2 million Hearings have been held before the FERC regarding the treatment of the Legacy Agreements and an initial decision is expected in August 2007.

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FERC Order 890: In February 2007, the FERC issued Order No. 890 adopting a final rule designed to strengthen the pro forma open access transmission tariff (OATT) by providing greater consistency and increasing transparency. The FERC had stated in its Notice of Proposed Rulemaking leading to the final rule that "as a general matter, the purpose of this rulemaking is to strengthen the pro forma OATT to ensure that it achieves its original purpose - remedying undue discrimination - not to create new market structures." The most significant revisions to the pro forma OATT relate to the development of more consistent methodologies for calculating available transfer capability, changes to the transmission planning process, changes to the pricing of certain generator and energy imbalances to encourage efficient scheduling behavior and to exempt intermittent generators, and changes regarding long-term point-to-point transmission service, including the addition of conditional firm long-term point-to-point transmission service, and generation re-dispatch.

As a transmission provider with an OATT on file with the FERC, IPC is required to comply with the requirements of the new rule. A major requirement of the new rule was to file a revised pro forma OATT on July 13, 2007. IPC made the required FERC filing and is currently operating under the new tariff.

Certain details related to the rule, such as the precise methodology that will be used to calculate available transfer capability, remain to be determined prospectively, and thus it is difficult to make a precise determination of the overall effect of this new rule on IPC's transmission operations or wholesale marketing function. However, at least on a preliminary basis, the rule is not anticipated to have a significant impact on IPC's financial results. Nonetheless, the final rule includes a wide range of provisions addressing the provision of transmission services, and as the new tariff is implemented there is likely to be a significant impact on IPC's transmission operations, planning and wholesale marketing functions.

FERC Order 693: Pursuant to section 215 of the Federal Power Act (FPA), on March 16, 2007, the FERC issued Order No. 693 in which it approved 83 of the 107 reliability standards proposed by the North American Electric Reliability Corporation (NERC). Previously, the FERC certified the NERC as the electric reliability organization responsible for developing and enforcing mandatory reliability standards. Collectively, the reliability standards define overall acceptable performance with regard to operation, planning and design of the North American Bulk-Power System. As the FERC recognized in Order No. 693, most of these reliability standards are already being adhered to on a voluntary basis. Compliance with these standards became mandatory and subject to the FERC's penalty authority in June 2007. Since then, additional reliability standards have been submitted by the NERC to the FERC for approval. In July 2007, the FERC denied requests for rehearing of Order No. 693. IPC has reviewed all requirements, procedures and documentation to ensure compliance with these standards and submitted all necessary information by the effective date of June 18, 2007. The FERC's action is not expected to have a material impact on IPC's operations.

Northern Tier Transmission Group
IPC, along with four other transmission-owning entities covering all or parts of the transmission system in six western states, has formed the Northern Tier Transmission Group (NTTG). The goal of the group is to improve overall operation and expansion of the high-voltage transmission network. The group continues to make progress on four major initiatives: improving generation control performance (the first generation control became operational in March 2007); compliance with the new FERC Order 890 through cooperative efforts in developing process and information exchange; providing improved information on available transmission capacity; and conducting open, participatory transmission planning processes which will result in identifying specific transmission projects in 2007. Several projects have been identified for the "fast-track" planning process and work has begun on engineering analysis. One of these projects is IPC's joint project with PacifiCorp (MidAmerican) to evaluate building two high voltage transmission lines as discussed below. Additionally, NTTG is working on the process and documentation for its own compliance with FERC Order 890 for regional planning. Each utility will individually submit the resulting plan as a required attachment to its OATT.

IPC/PacifiCorp (MidAmerican) Memorandum of Understanding
IPC and PacifiCorp are jointly exploring a project to build two 500 kV lines between the Jim Bridger plant and Boise. The lines would be designed to meet growth in customers' need for electricity and increase electrical transmission capacity across southern Idaho. This project has been submitted to the Western Electricity Coordinating Council (WECC) for the first phase of the ratings process. In this phase, a review team will be established from members of the WECC prior to the commencement of the study to analyze the impact of the project to the existing system. When the study is complete, necessary modifications will be made to the engineering design and the final rating will be obtained prior to the beginning of construction. Additionally, the planning and project management personnel for both companies have met to begin organizing the initial phases of this project. IPC and PacifiCorp are finalizing a cost sharing agreement for expenses associated with the analysis work of the initial phases. It is expected that portions of the project would be completed between 2012 and 2014. If the project is constructed, IPC estimates that its share of project costs would be between $800 million and $1.2 billion.

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Integrated Resource Plan
IPC filed its 2006 IRP with the IPUC in September 2006 and with the OPUC in October 2006. The IPUC accepted the 2006 IRP in March 2007; acceptance in Oregon is still pending. The 2006 IRP previewed IPC's load and resource situation for the next twenty years, analyzed potential supply-side and demand-side options and identified near-term and long-term actions.

With its acceptance of the 2006 IRP, the IPUC requested that IPC align the submittal of its next IRP with those submitted by other utilities. To comply with this request IPC intends to provide an update on the status of the 2006 IRP to both the IPUC and OPUC in June of 2008 and file a new IRP in June of 2009.

Wind RFP: In February 2007, the IPUC approved a Power Purchase Agreement with Telocaset Wind Power Partners, LLC, a subsidiary of Horizon Wind Energy, for 100 MW (nameplate) of wind generation from the Elkhorn Wind Project located in eastern Oregon. Construction has begun and the project is expected to begin delivering energy in late 2007.

Geothermal RFP: An RFP for geothermal-powered generation was released on June 2, 2006. IPC identified US Geothermal as the successful bidder in March 2007 and is currently negotiating a Power Purchase Agreement for 45.5 MW of geothermal energy.

Coal-fired Resource Screening and Evaluation: In the 2006 IRP, IPC identified the need for a coal-fired resource beginning in 2013. As a result of discussions with potential resource participants, IPC and Spokane, Washington-based Avista Utilities entered into an agreement to jointly investigate possible future coal-fired resources. Under the arrangement, the utilities studied the options for base load coal-fired generation to meet their collective IRP forecast needs. Information submittals from interested parties were received in October 2006. In early April 2007, Avista and IPC sent a joint letter to developers providing an update on the coal-based resource assessment process. The letter also indicated that the combined Avista-IPC joint assessment would be suspended and that each company would proceed independently toward resource acquisition. IPC is continuing its evaluation of coal-based resource alternatives. In April 2007, IPC notified developers of its short-list of projects selected for further screening and evaluation. In addition, IPC continues to evaluate other coal-fired resource opportunities, including expansion of its jointly-owned facilities.

Relicensing of Hydroelectric Projects
The section below summarizes and provides an update of relicensing projects as discussed in IDACORP's and IPC's Annual Report on Form 10-K for the year ended December 31, 2006, and Quarterly Report on Form 10-Q for the quarter ended March 31, 2007.

IPC, like other utilities that operate nonfederal hydroelectric projects on qualified waterways, obtains licenses for its hydroelectric projects from the FERC. These licenses last for 30 to 50 years depending on the size, complexity, and cost of the project. IPC is actively pursuing the relicensing of the Hells Canyon Complex and Swan Falls projects.

Hells Canyon Complex: The most significant ongoing relicensing effort is the Hells Canyon Complex (HCC), which provides approximately two-thirds of IPC's hydroelectric generating capacity and 40 percent of its total generating capacity. The current license for the HCC expired at the end of July 2005. Until the new multi-year license is issued, IPC operates the project under an annual license issued by the FERC. The license application was filed in July 2003 and accepted by the FERC for filing in December 2003. The FERC is now processing the application consistent with the requirements of the Federal Power Act (FPA), the National Environmental Policy Act of 1969, as amended (NEPA), the Energy Policy Act and other applicable federal laws. Consistent with the requirements of NEPA, the FERC Staff will prepare an environmental impact statement (EIS) for the Hells Canyon project, which the FERC will use to determine whether, and under what conditions, to issue a new license for the project.

On July 28, 2006, the FERC released the draft EIS. Because this is a draft EIS, containing only FERC Staff conclusions, it cannot be relied upon to accurately predict what measures will be included in the final EIS or the outcome of the relicensing process.

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In November 2006, IPC and other parties to the licensing proceeding filed comments with the FERC on the draft EIS. The FERC is now in the process of reviewing the comments to the draft EIS and is expected to release a final EIS in late 2007 or early 2008.
In conjunction with the EIS process, on August 1, 2006, the FERC requested formal consultation with the National Marine Fisheries Service (NMFS) and the U.S. Fish and Wildlife Service (USFWS) (collectively the Services), pursuant to section 7 of the Endangered Species Act (ESA) with regard to the effect of relicensing the HCC on several aquatic and terrestrial species listed as threatened under the ESA. IPC is cooperating with the USFWS, the NMFS and the FERC in an effort to address ESA concerns associated with the licensing of the HCC.

On January 31, 2007, IPC filed Water Quality Certification Applications, under section 401 of the Clean Water Act (CWA), with the States of Oregon and Idaho. Because the HCC is located on the Snake River where it forms the border between Idaho and Oregon, section 401 of the CWA requires as a prerequisite to the licensing of the project by the FERC that each state certify that any discharge from the project complies with applicable state water quality standards. IPC is working with the Oregon Department of Environmental Quality and the Idaho Department of Environmental Quality to ensure that state water quality standards are met so that the project can be appropriately certified.

At June 30, 2007, $90 million of HCC relicensing costs were included in construction work in progress. The relicensing costs are recorded and will be held in construction work in progress until a new multi-year license is issued by the FERC, at which time the charges will be transferred to electric plant in service. Relicensing costs and costs related to a new license will be submitted to regulators for recovery through the ratemaking process.

Swan Falls Project: The license for the Swan Falls hydroelectric project expires in 2010. On March 10, 2005, IPC issued a Formal Consultation Package with agencies, Native American tribes and the public regarding the relicensing of the Swan Falls project. IPC is in the process of compiling information and performing studies in preparation for filing an application for a new license with the FERC. IPC expects to file a draft license application in the fall of 2007, with the final application being filed in June 2008.

At June 30, 2007, $3 million of Swan Falls project relicensing costs were included in construction work in progress. The relicensing costs are recorded and will be held in construction work in progress until a new multi-year license is issued by the FERC, at which time the charges will be transferred to electric plant in service. Relicensing costs and costs related to a new license will be submitted to regulators for recovery through the ratemaking process.

Shoshone Falls Expansion: On August 17, 2006, IPC filed a License Amendment Application with the FERC, which would allow IPC to upgrade the Shoshone Falls project from 12.5 MW to 62.5 MW. In March 2007, IPC received from the FERC a draft Environmental Assessment (EA) and Notice of Ready for Environmental Analysis, which provided for a 60-day comment period for interested entities. IPC has responded to the comments received and anticipates the FERC will issue a final EA during summer 2007 and an Order approving the License Amendment Application shortly thereafter.

IPC has filed a Water Right Application which is currently being reviewed by the IDWR.

OTHER MATTERS:

Adopted Accounting Pronouncements
FIN 48: As discussed in Note 2 to IDACORP's and IPC's Condensed Consolidated Financial Statements, both companies adopted FASB Interpretation No. 48, "Accounting for Uncertainty in Income Taxes - an interpretation of FASB Statement No. 109" (FIN 48) on January 1, 2007, as required. IDACORP and IPC recorded an increase of $15.1 million to opening retained earnings for the cumulative effect of adopting FIN 48.

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

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ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

IDACORP and IPC are exposed to market risks, including changes in interest rates, changes in commodity prices, credit risk and equity price risk. The following discussion summarizes these risks and the financial instruments, derivative instruments and derivative commodity instruments sensitive to changes in interest rates, commodity prices and equity prices that were held at June 30, 2007.

Interest Rate Risk
IDACORP and IPC manage interest expense and short- and long-term liquidity through a combination of fixed rate and variable rate debt. Generally, the amount of each type of debt is managed through market issuance, but interest rate swap and cap agreements with highly rated financial institutions may be used to achieve the desired combination.

Variable Rate Debt: As of June 30, 2007, IDACORP and IPC had $269 million and $210 million, respectively, in floating rate debt, net of temporary investments. Assuming no change in either company's financial structure, if variable interest rates were to average one percentage point higher than the average rate on June 30, 2007, interest expense for the year ending December 31, 2007, would increase and pre-tax earnings would decrease by approximately $2.7 million for IDACORP and $2.1 million for IPC.

Fixed Rate Debt: As of June 30, 2007, IDACORP and IPC had outstanding fixed rate debt of $969 million and $936 million, respectively. The fair market value of this debt was $937 million and $904 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 $80 million for IDACORP and IPC if interest rates were to decline by one percentage point from their June 30, 2007 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, 2006. In a limited manner starting in 2007, IPC began utilizing financial energy instruments in addition to physical forward power transactions for the purpose of mitigating price risk related to securing adequate energy to meet utility load requirements in accordance with IPC's Energy Risk Management Policy. This practice falls within the parameters of IPC's Energy Risk Management Policy and these instruments are not used for trading purposes. These financial instruments are used in essentially the same manner as forward transactions to mitigate price risk but are considered derivative instruments under SFAS 133 and are therefore reported at fair value in IDACORP's and IPC's financial statements. Because of the PCA mechanism, IPC records the changes in fair value of derivative instruments related to power supply as regulatory assets or liabilities.

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, 2006.

Equity Price Risk
IDACORP's and IPC's equity price risk has not changed materially from that reported in the Annual Report on Form 10-K for the year ended December 31, 2006.

ITEM 4. CONTROLS AND PROCEDURES

Disclosure controls and procedures:

IDACORP:
The Chief Executive Officer and the Chief Financial Officer of IDACORP, based on their evaluation of IDACORP's disclosure controls and procedures (as defined in Exchange Act Rule 13a-15(e)) as of June 30, 2007, have concluded that IDACORP's disclosure controls and procedures are effective.

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IPC:
The Chief Executive Officer and the Chief Financial Officer of IPC, based on their evaluation of IPC's disclosure controls and procedures (as defined in Exchange Act Rule 13a-15(e)) as of June 30, 2007, have concluded that IPC's disclosure controls and procedures are effective.
Changes in internal control over financial reporting:

There have been no changes in IDACORP's or IPC's internal control over financial reporting during the quarter ended June 30, 2007, that have materially affected, or are reasonably likely to materially affect, IDACORP's or IPC's internal control over financial reporting.

PART II - OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS

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

ITEM 1A. RISK FACTORS

Idaho Power Company's increasing reliance on purchased power exposes it to greater market risk and could increase costs and reduce earnings and cash flows. Increases in both the number of customers and the demand for energy as well as reduced hydroelectric generation have resulted and may continue to result in increased reliance on purchased power to meet customer load requirements. Idaho Power Company's power cost adjustment mechanism in Idaho absorbs 90 percent of the volatility in net power supply costs allocated to that jurisdiction but leaves ten percent to be absorbed by Idaho Power Company. In addition, since the Federal Energy Regulatory Commission implemented market-based wholesale power rates in 1997, the price volatility of electricity has substantially increased from what it was at the inception of the power cost adjustment. As Idaho Power Company's reliance on purchased power continues to increase, the risks associated with the remaining ten percent could increase costs and reduce earnings and cash flows.

This additional risk factor should be read in conjunction with the risk factors included in IDACORP's and IPC's Annual Report on Form 10-K for the year ended December 31, 2006.

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

Restrictions on Dividends:
A covenant under the IDACORP and IPC Credit Facilities requires IDACORP and IPC to maintain leverage ratios of consolidated indebtedness to consolidated total capitalization of no more than 65 percent at the end of each fiscal quarter. See "MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS - LIQUIDITY AND CAPITAL RESOURCES - Financing Programs - Credit Facilities." IPC's ability to pay dividends on its common stock held by IDACORP and IDACORP's ability to pay dividends on its common stock are limited to the extent payment of such dividends would cause their leverage ratios to exceed 65 percent. At June 30, 2007, the leverage ratios for IDACORP and IPC were 51 percent and 51 percent, respectively.

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.

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Issuer Purchases of Equity Securities:

IDACORP, Inc. Common Stock

						(d) Maximum Number
					(c) Total Number of	(or Approximate
		(a) Total	(b)		Shares Purchased	Dollar Value) of
		Number of	Average		as Part of Publicly	Shares that May Yet
		Shares	Price Paid		Announced Plans or	Be Purchased Under
Period		Purchased 1	per Share		Programs	the Plans or Programs

April 1 - April 30, 2007		-	$	-	-	-
May 1 - May 31, 2007		272		34.45	-	-
June 1 - June 30, 2007		-		-	-	-
	Total	272	$	34.45	-	-

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

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

IDACORP, Inc.:

(a)

Regular annual meeting of IDACORP, Inc.'s shareholders, held May 17, 2007, in Boise, Idaho .

(b)

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

Judith A. Johansen

Jon H. Miller

J. LaMont Keen

Robert A. Tinstman

Director elected at the meeting for a two-year term:

Christine King

Continuing Directors:

Gary G. Michael

Richard G. Reiten

Peter S. O'Neill

Joan H. Smith

Jan B. Packwood

Thomas J. Wilford

(c)

To elect five Director Nominees:

Name

For

Withheld

Total Voted

Judith A. Johansen

36,971,100

971,384

37,942,484

J. LaMont Keen

36,958,724

954,276

37,913,000

Jon H. Miller

36,966,709

948,290

37,912,999

Robert A. Tinstman

36,969,905

942,010

37,911,915

Christine King

36,967,344

944,572

37,911,916

To ratify the appointment of Deloitte & Touche LLP as the independent registered public

accounting firm for the fiscal year ending December 31, 2007:

Class of Stock

For

Against

Abstain

Total Voted

Common

36,952,165

714,118

245,632

37,911,915

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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 June 30, 2003, 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 September 30, 2003, 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.
	File number 1-3198, Form 8-K filed 10/10/06, as Exhibit 4, Forty-first, October 1, 2006.
	File number 1-3198, Form 8-K filed 6/4/07, as Exhibit 4, Forty-second, May 1, 2007.

*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 June 30, 2000, 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 September 30, 2003, 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. File number 33-00440, Post-Effective Amendment No. 2 to Form S-3, 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)	First Amendment to Rights Agreement, dated as of May 14, 2007, between IDACORP, Inc. and Wells Fargo Bank, N.A., as successor to The Bank of New York, as Rights Agent. File number 333-143404, Form S-8, filed on 5/31/07, as Exhibit 4(g).

*4(g)	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(h)	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(i)	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 June 30, 2000, 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, 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	Idaho Power Company Security Plan for Senior Management Employees I - a non-qualified, deferred compensation plan, amended and restated effective December 31, 2004. File number 1-14465, 1-3198, Form 10-Q for the quarter ended September 30, 2006, filed on 11/2/06, as Exhibit 10(h)(i).

*10(h)(ii)1	Idaho Power Company Security Plan for Senior Management Employees II, a non-qualified, deferred compensation plan, effective January 1, 2005, as amended July 20, 2006. File number 1-14465, 1-3198, Form 10-Q for the quarter ended September 30, 2006, filed on 11/2/06, as Exhibit 10(h)(xxxv).

*10(h)(iii) 1	IDACORP, Inc. Restricted Stock Plan, as amended July 20, 2006. File number 1-14465, 1-3198, Form 10-Q for the quarter ended September 30, 2006, filed on 11/2/06, as Exhibit 10(h)(iii).

*10(h)(iv) 1	IDACORP, Inc. Restricted Stock Plan - Form of Restricted Stock Agreement (time-vesting) (July 20, 2006). File number 1-14465, 1-3198, Form 10-Q for the quarter ended September 30, 2006, filed on 11/2/06, as Exhibit 10(h)(vi).

*10(h)(v) 1	IDACORP, Inc. Restricted Stock Plan - Form of Performance Stock Agreement (July 20, 2006). File number 1-14465, 1-3198, Form 10-Q for the quarter ended September 30, 2006, filed on November 2, 2006, as Exhibit 10(h)(vii).

*10(h)(vi) 1	The Revised Security Plan for Board of Directors - a non-qualified, deferred compensation plan, as amended and restated effective July 20, 2006. File number 1-14465, 1-3198, Form 10-Q for the quarter ended September 30, 2006, filed on 11/2/06, as Exhibit 10(h)(viii).

*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 Officer Indemnification Agreement for Officers of IDACORP, Inc. and IPC, as amended July 20, 2006. File number 1-14465, 1-3198, Form 10-Q for the quarter ended September 30, 2006, filed on 11/2/06, as Exhibit 10(h)(xix).

*10(h)(ix)1	Form of Director Indemnification Agreement for Directors of IDACORP, Inc., as amended July 20, 2006. File number 1-14465, 1-3198, Form 10-Q for the quarter ended September 30, 2006, filed on 11/2/06, as Exhibit 10(h)(xx).

*10(h)(x)1	Form of Change in Control Agreement between IDACORP, Inc. and Officers of IDACORP and IPC (senior vice president and higher), as amended July 20, 2006. File number 1-14465, 1-3198, Form 10-Q for the quarter ended September 30, 2006, filed on 11/2/06, as Exhibit 10(h)(x).

*10(h)(xi) 1	Form of Change in Control Agreement between IDACORP, Inc. and Officers of IDACORP and IPC (below senior vice president), as amended July 20, 2006. File number 1-14465, 1-3198, Form 10-Q for the quarter ended September 30, 2006, filed on 11/2/06, as Exhibit 10(h)(xi).

*10(h)(xii) 1	IDACORP, Inc. 2000 Long-Term Incentive and Compensation Plan, as amended July 20, 2006. File number 1-14465, 1-3198, Form 10-Q for the quarter ended September 30, 2006, filed on 11/2/06, as Exhibit 10(h)(xii).

*10(h)(xiii)1	IDACORP, Inc. 2000 Long-Term Incentive and Compensation Plan - Form of Stock Option Award Agreement (July 20, 2006). File number 1-14465, 1-3198, Form 10-Q for the quarter ended September 30, 2006, filed on 11/2/06, as Exhibit 10(h)(xvi).

*10(h)(xiv)1	IDACORP, Inc. 2000 Long-Term Incentive and Compensation Plan - Form of Restricted Stock Award Agreement (time vesting) (July 20, 2006). File number 1-14465, 1-3198, Form 10-Q for the quarter ended September 30, 2006, filed on 11/2/06, as Exhibit 10(h)(xvii).

*10(h)(xv)1	IDACORP, Inc. 2000 Long-Term Incentive and Compensation Plan - Form of Restricted Stock Award Agreement (performance vesting) (July 20, 2006). File number 1-14465, 1-3198, Form 10-Q for the quarter ended September 30, 2006, filed on 11/2/06, as Exhibit 10(h)(xviii).

*10(h)(xvi)1	IDACORP, Inc. 2000 Long-Term Incentive and Compensation Plan - Form of Performance Share Award Agreement (performance with two goals) (July 20, 2006). File number 1-14465, 1-3198, Form 10-Q for the quarter ended September 30, 2006, filed on 11/2/06, as Exhibit 10(h)(xxxiii).

*10(h)(xvii)1	IDACORP, Inc. Executive Incentive Plan. File Number 1-14465, 1-3198, Form 8-K, filed on 2/27/07, as Exhibit 10.1.

*10(h)(xviii)1	Idaho Power Company Executive Deferred Compensation Plan, as amended July 20, 2006. File number 1-14465, 1-3198, Form 10-Q for the quarter ended September 30, 2006, filed on 11/2/06, as Exhibit 10(h)(xxxvi).

*10(h)(xix)1	IDACORP, Inc. and IPC 2007 Compensation for Non-Employee Directors of the Board of Directors. File number 1-14465, 1-3198, Form 10-Q for the quarter ended March 31, 2007, filed on 5/9/07, as Exhibit 10(h)(xix).

*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 June 30, 2003, filed on 8/7/03, as Exhibit 10(k).

*10(l)	$100 Million Five-Year Amended and Restated Credit Agreement, dated as of April 25, 2007, among IDACORP, Inc., various lenders, Wachovia Bank, National Association, as administrative agent, swingline lender and LC issuer, JPMorgan Chase Bank, N.A., as syndication agent, and KeyBank National Association, Wells Fargo Bank, N.A. and Bank of America, N.A., as documentation agents, and Wachovia Capital Markets, LLC and J. P. Morgan Securities Inc., as joint lead arrangers and joint book runners. File number 1-14465, Form 10-Q for the quarter ended March 31, 2007, filed on 5/9/07, as Exhibit 10(l).



*10(m)	$300 Million Five-Year Amended and Restated Credit Agreement, dated as of April 25, 2007, among Idaho Power Company, various lenders, Wachovia Bank, National Association, as administrative agent, swingline lender and LC issuer, JPMorgan Chase Bank, N.A., as syndication agent, and KeyBank National Association, US Bank National Association and Bank of America, N.A., as documentation agents, and Wachovia Capital Markets, LLC and J. P. Morgan Securities Inc., as joint lead arrangers and joint book runners. File number 1-3198, Form 10-Q for the quarter ended March 31, 2007, filed on 5/9/07, as Exhibit 10(m).

*10(n)	Loan Agreement, dated October 1, 2006, between Sweetwater County, Wyoming and IPC. File number 1-3198, Form 8-K, filed on 10/10/2006, as Exhibit 10.1.

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 December 31, 2006, filed on 3/1/07 as Exhibit 21.

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

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

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

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

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

32(b)	IPC Section 1350 certification.

99	Earnings press release for second quarter 2007.

1 Management contract or compensatory plan or arrangement

56 - 61

Table of Contents

SIGNATURES

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

IDACORP, Inc.

(Registrant)

Date	August 8, 2007	By:	/s/ J. LaMont Keen
			J. LaMont Keen
			President and Chief Executive Officer

Date	August 8, 2007	By:	/s/ Darrel T. Anderson
			Darrel T. Anderson
			Senior Vice President - Administrative Services
			and Chief Financial Officer

IDAHO POWER COMPANY

(Registrant)

Date	August 8, 2007	By:	/s/ J. LaMont Keen
			J. LaMont Keen
			President and Chief Executive Officer

Date	August 8, 2007	By:	/s/ Darrel T. Anderson
			Darrel T. Anderson
			Senior Vice President - Administrative Services
			and Chief Financial Officer

Table of Contents

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 second quarter 2007.