Edgar Filing: IDAHO POWER CO

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, 2010
	OR
	TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
	EXCHANGE ACT OF 1934
	For the transition period from __________ to __________
		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 have submitted electronically and posted on their corporate Web sites, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrants were required to submit and post such files). IDACORP, Inc.: Yes X No ___ Idaho Power Company: Yes No ___

Indicate by check mark whether the registrants are large accelerated filers, accelerated filers, non-accelerated filers, or smaller reporting companies. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act (check one):

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

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 July 31, 2010:
IDACORP, Inc.:	48,184,956
Idaho Power Company:	39,150,812, all held by IDACORP, Inc.

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

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

COMMONLY USED TERMS

ADITC	-	Accumulated Deferred Investment Tax Credits
AFUDC	-	Allowance for Funds Used During Construction
APCU	-	Annual Power Cost Update
BCC	-	Bridger Coal Company, a joint venture of IERCo
Cal ISO	-	California Independent System Operator
CalPX	-	California Power Exchange
CAMP	-	Comprehensive Aquifer Management Plan
CO₂	-	Carbon Dioxide
EIS	-	Environmental Impact Statement
EPA	-	Environmental Protection Agency
EPS	-	Earnings per share
ESA	-	Endangered Species Act
ESPA	-	Eastern Snake Plain Aquifer
FCA	-	Fixed Cost Adjustment mechanism
FERC	-	Federal Energy Regulatory Commission
GHG	-	Greenhouse gas
HCC	-	Hells Canyon Complex
Ida-West	-	Ida-West Energy, a subsidiary of IDACORP, Inc.
IE	-	IDACORP Energy, a subsidiary of IDACORP, Inc.
IERCo	-	Idaho Energy Resources Co., a subsidiary of Idaho Power Company
IFS	-	IDACORP Financial Services, a subsidiary of IDACORP, Inc.
IPUC	-	Idaho Public Utilities Commission
IRP	-	Integrated Resource Plan
IRS	-	Internal Revenue Service
IWRB	-	Idaho Water Resource Board
kW	-	Kilowatt
MD&A	-	Management’s Discussion and Analysis of Financial Condition and Results of Operations
MW	-	Megawatt
MWh	-	Megawatt-hour
NOx	-	Nitrogen Oxide
O&M	-	Operations and Maintenance
OATT	-	Open Access Transmission Tariff
OPUC	-	Oregon Public Utility Commission
PCA	-	Power Cost Adjustment
PCAM	-	Power Cost Adjustment Mechanism
PURPA	-	Public Utility Regulatory Policies Act of 1978
REC	-	Renewable Energy Certificate
RH BART	-	Regional Haze - Best Available Retrofit Technology
RPS	-	Renewable Portfolio Standards
SEC	-	Securities and Exchange Commission
SO₂	-	Sulfur Dioxide
SRBA	-	Snake River Basin Adjudication
Valmy	-	North Valmy Steam Electric Generating Plant
VIEs	-	Variable Interest Entities
WECC	-	Western Electricity Coordinating Council

TABLE OF CONTENTS
				Page
Part I. Financial Information:

	Item 1. Financial Statements (unaudited)
		IDACORP, Inc.:
			Condensed Consolidated Statements of Income	4
			Condensed Consolidated Balance Sheets	5-6
			Condensed Consolidated Statements of Cash Flows	7
			Condensed Consolidated Statements of Comprehensive Income	8
			Condensed Consolidated Statements of Equity	9
		Idaho Power Company:
			Condensed Consolidated Statements of Income	10
			Condensed Consolidated Balance Sheets	11-12
			Condensed Consolidated Statements of Capitalization	13
			Condensed Consolidated Statements of Cash Flows	14
			Condensed Consolidated Statements of Comprehensive Income	15
		Notes to the Condensed Consolidated Financial Statements		16-36
		Reports of Independent Registered Public Accounting Firm		37-38

	Item 2. Management’s Discussion and Analysis of Financial Condition and Results of
			Operations	39-74

	Item 3. Quantitative and Qualitative Disclosures About Market Risk			75

	Item 4. Controls and Procedures			76

Part II. Other Information:

	Item 1. Legal Proceedings			76

	Item 1A. Risk Factors			76-78

	Item 2. Unregistered Sales of Equity Securities and Use of Proceeds			78-79

	Item 6. Exhibits			80

Signatures				81

Exhibit Index				82

SAFE HARBOR STATEMENT

This report on 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,” and Part II, Item 1A – “RISK FACTORS,” and in IDACORP Inc.’s and Idaho Power Company’s Annual Report on Form 10-K for the year ended December 31, 2009, at Part I, Item 1A- “RISK FACTORS.” 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,” or similar expressions.

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

		Three months ended				Six months ended
		June 30,				June 30,
		2010		2009		2010		2009
		(thousands of dollars except for per share amounts)
Operating Revenues:
Electric utility:
General business		$	204,277	$	198,215	$	408,022	$	386,142
Off-system sales		17,769		26,667		52,175		55,198
Other revenues		18,744		17,636		33,053		29,207
Total electric utility revenues		240,790		242,518		493,250		470,547
Other		963		1,116		1,466		1,661
Total operating revenues		241,753		243,634		494,716		472,208
Operating Expenses:
Electric utility:
Purchased power		30,349		26,867		51,523		60,568
Fuel expense		27,558		24,475		64,744		63,608
Power cost adjustment		28,071		26,762		76,395		42,621
Other operations and maintenance		75,125		74,593		147,219		143,133
Energy efficiency programs		8,765		8,673		13,799		12,731
Depreciation		28,726		26,832		57,309		52,795
Taxes other than income taxes		5,805		5,088		11,485		10,150
Total electric utility expenses		204,399		193,290		422,474		385,606
Other expense		749		872		1,590		1,495
Total operating expenses		205,148		194,162		424,064		387,101
Operating Income		36,605		49,472		70,652		85,107
Other Income, Net		3,012		4,058		7,493		10,979
Earnings (Losses) of Unconsolidated Equity-
Method Investments		380		(2,620)		(1,998)		(2,218)
Interest Expense:
Interest on long-term debt		19,427		18,282		38,868		34,922
Other interest expense, net of AFUDC		(2,038)		(117)		(2,491)		719
Total interest expense		17,389		18,165		36,377		35,641
Income Before Income Taxes		22,608		32,745		39,770		58,227
Income Tax (Benefit) Expense		(16,629)		5,175		(15,324)		11,970
Net Income		39,237		27,570		55,094		46,257
Adjustment for (income) loss attributable to
noncontrolling interests		(28)		(95)		178		102
Net Income Attributable to IDACORP, Inc.		$	39,209	$	27,475	$	55,272	$	46,359
Weighted Average Common Shares Outstanding-
	Basic (000’s)	47,888		46,958		47,831		46,895
Weighted Average Common Shares Outstanding-
	Diluted (000’s)	48,048		46,977		47,966		46,927
Earnings Per Share of Common Stock:
Earnings Attributable to IDACORP, Inc.-Basic		$	0.82	$	0.59	$	1.16	$	0.99
Earnings Attributable to IDACORP, Inc.-Diluted		$	0.82	$	0.58	$	1.15	$	0.99
Dividends Declared Per Share of Common Stock		$	0.30	$	0.30	$	0.60	$	0.60
The accompanying notes are an integral part of these statements.

IDACORP, Inc.
Condensed Consolidated Balance Sheets
(unaudited)

	June 30,		December 31,
	2010		2009
Assets	(thousands of dollars)

Current Assets:
Cash and cash equivalents	$	29,488	$	52,987
Receivables:
Customer (net of allowance of $1,311 and $1,805, respectively)	64,216		74,987
Other (net of allowance of $1,457 and $1,073, respectively)	23,171		11,922
Taxes receivable	1,874		-
Accrued unbilled revenues	51,399		51,272
Materials and supplies (at average cost)	47,436		48,054
Fuel stock (at average cost)	29,206		25,634
Prepayments	10,340		11,111
Deferred income taxes	31,817		31,773
Other	5,917		2,666
Total current assets	294,864		310,406

Investments	197,657		195,298

Property, Plant and Equipment:
Utility plant in service	4,212,394		4,160,178
Accumulated provision for depreciation	(1,586,118)		(1,558,538)
Utility plant in service- net	2,626,276		2,601,640
Construction work in progress	363,982		289,188
Utility plant held for future use	7,106		7,151
Other property, net of accumulated depreciation	18,807		19,029
Property, plant and equipment- net	3,016,171		2,917,008

Other Assets:
American Falls and Milner water rights	22,641		24,226
Company-owned life insurance	27,079		26,654
Regulatory assets	676,820		720,401
Long-term receivables (net of allowance of $1,861 and $2,157, respectively)	3,993		4,217
Other	41,562		40,517
Total other assets	772,095		816,015

Total	$	4,280,787	$	4,238,727

The accompanying notes are an integral part of these statements.

IDACORP, Inc.
Condensed Consolidated Balance Sheets
(unaudited)

	June 30,		December 31,
	2010		2009
Liabilities and Equity	(thousands of dollars)

Current Liabilities:
Current maturities of long-term debt	$	129,800	$	9,340
Notes payable	17,500		53,750
Accounts payable	78,075		83,818
Taxes accrued	21,456		10,184
Interest accrued	21,821		20,056
Other	70,323		41,081
Total current liabilities	338,975		218,229

Other Liabilities:
Deferred income taxes	559,862		574,450
Regulatory liabilities	301,568		287,780
Other	357,740		346,994
Total other liabilities	1,219,170		1,209,224

Long-Term Debt	1,288,802		1,409,730

Commitments and Contingencies

Equity:
IDACORP, Inc. shareholders’ equity:
Common stock, no par value (120,000,000 shares authorized;
48,164,439 and 47,925,882 shares issued, respectively)	762,903		756,475
Retained earnings	675,601		649,180
Accumulated other comprehensive loss	(8,678)		(8,267)
Treasury stock (7,365 and 29,191 shares at cost, respectively)	(17)		(53)
Total IDACORP, Inc. shareholders’ equity	1,429,809		1,397,335
Noncontrolling interest	4,031		4,209
Total equity	1,433,840		1,401,544

Total	$	4,280,787	$	4,238,727

The accompanying notes are an integral part of these statements.

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

	Six months ended
	June 30,
	2010		2009
Operating Activities:	(thousands of dollars)
Net income	$	55,094	$	46,257
Adjustments to reconcile net income to net cash provided by
operating activities:
Depreciation and amortization	61,023		55,434
Deferred income taxes and investment tax credits	(19,726)		7,548
Changes in regulatory assets and liabilities	78,974		38,358
Non-cash pension expense	2,952		2,209
Losses of unconsolidated equity-method investments	1,998		2,218
Distributions from unconsolidated equity-method investments	-		7,710
Allowance for other funds used during construction	(8,020)		(2,498)
Other non-cash adjustments to net income, net	(148)		1,728
Change in:
Accounts receivable and prepayments	6,613		(8,869)
Accounts payable and other accrued liabilities	(8,495)		(28,293)
Taxes accrued/receivable	9,279		18,155
Other current assets	(3,081)		(11,940)
Other current liabilities	18,215		(1,464)
Other assets	(2,512)		(1,831)
Other liabilities	(4,951)		(14,090)
Net cash provided by operating activities	187,215		110,632
Investing Activities:
Additions to property, plant and equipment	(166,687)		(100,271)
Proceeds from the sale of utility assets	19,230		-
Proceeds from the sale of non-utility assets	-		2,250
Investments in affordable housing	(6,147)		(6,174)
Proceeds from the sale of emission allowances and renewable energy certificates	3,497		2,341
Investments in unconsolidated affiliates	(2,020)		-
Proceeds from the sale of available-for-sale securities	-		8,965
Other	3,468		(3,319)
Net cash used in investing activities	(148,659)		(96,208)
Financing Activities:
Issuance of long-term debt	-		100,000
Retirement of long-term debt	(1,064)		(8,735)
Dividends on common stock	(28,830)		(28,230)
Net change in short-term borrowings	(36,250)		(72,151)
Issuance of common stock	5,299		4,927
Acquisition of treasury stock	(846)		(1,408)
Other	(364)		(1,653)
Net cash used in financing activities	(62,055)		(7,250)
Net (decrease) increase in cash and cash equivalents	(23,499)		7,174
Cash and cash equivalents at beginning of the period	52,987		8,828
Cash and cash equivalents at end of the period	$	29,488	$	16,002
Supplemental Disclosure of Cash Flow Information:
Cash (received) paid during the period for:
Income taxes	$	(3,387)	$	(11,785)
Interest (net of amount capitalized)	$	33,662	$	32,956
Non-cash investing activities
Additions to property, plant and equipment in accounts payable	$	21,435	$	5,578
Investments in affordable housing	$	3,168	$	6,000
The accompanying notes are an integral part of these statements.

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

	Three months ended
	June 30,
	2010		2009
	(thousands of dollars)

Net Income	$	39,237	$	27,570

Other Comprehensive Income (Loss):
Net unrealized holding (losses) gains arising during the period,
net of tax of ($758) and $734	(1,181)		1,143
Unfunded pension liability adjustment, net of tax
of $114 and $87	177		136
Total Comprehensive Income	38,233		28,849
Comprehensive income attributable to noncontrolling interests	(28)		(95)
Comprehensive Income Attributable to IDACORP, Inc.	$	38,205	$	28,754

The accompanying notes are an integral part of these statements.

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

	Six months ended
	June 30,
	2010		2009
	(thousands of dollars)

Net Income	$	55,094	$	46,257

Other Comprehensive Income (Loss):
Net unrealized holding (losses) gains arising during the period,
net of tax of ($492) and $164	(765)		256
Unfunded pension liability adjustment, net of tax
of $227 and $174	354		272
Total Comprehensive Income	54,683		46,785
Comprehensive loss attributable to noncontrolling interests	178		102
Comprehensive Income Attributable to IDACORP, Inc.	$	54,861	$	46,887

The accompanying notes are an integral part of these statements.

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

	Six months ended
	June 30,
	2010		2009
	(thousands of dollars)
Common Stock
Balance at beginning of period	$	756,475	$	729,576
Issued	5,299		4,927
Other	1,129		377
Balance at end of period	762,903		734,880

Retained Earnings
Balance at beginning of period	649,180		581,605
Net income attributable to IDACORP, Inc.	55,272		46,359
Common stock dividends ($0.60 per share)	(28,851)		(28,229)
Balance at end of period	675,601		599,735

Accumulated Other Comprehensive Income (Loss)
Balance at beginning of period	(8,267)		(8,707)
Unrealized (loss) gain on securities (net of tax)	(765)		256
Unfunded pension liability adjustment (net of tax)	354		272
Balance at end of period	(8,678)		(8,179)

Treasury Stock
Balance at beginning of period	(53)		(37)
Issued	882		1,424
Acquired	(846)		(1,408)
Balance at end of period	(17)		(21)
Total IDACORP, Inc. shareholders’ equity at end of period	1,429,809		1,326,415

Noncontrolling Interests
Balance at beginning of period	4,209		4,434
Net loss attributed to noncontrolling interest	(178)		(102)
Other	-		(250)
Balance at end of period	4,031		4,082
Total equity at end of period	$	1,433,840	$	1,330,497

The accompanying notes are an integral part of these statements.

Idaho Power Company
Condensed Consolidated Statements of Income
(unaudited)

		Three months ended				Six months ended
		June 30,				June 30,
		2010		2009		2010		2009
		(thousands of dollars)
Operating Revenues:
General business		$	204,277	$	198,215	$	408,022	$	386,142
Off-system sales		17,769		26,667		52,175		55,198
Other revenues		18,744		17,636		33,053		29,207
Total operating revenues		240,790		242,518		493,250		470,547

Operating Expenses:
Operation:
Purchased power		30,349		26,867		51,523		60,568
Fuel expense		27,558		24,475		64,744		63,608
Power cost adjustment		28,071		26,762		76,395		42,621
Other operations and maintenance		75,125		74,593		147,219		143,133
Energy efficiency programs		8,765		8,673		13,799		12,731
Depreciation		28,726		26,832		57,309		52,795
Taxes other than income taxes		5,805		5,088		11,485		10,150
Total operating expenses		204,399		193,290		422,474		385,606

Income from Operations		36,391		49,228		70,776		84,941

Other Income (Expense):
Allowance for equity funds used during construction		4,362		1,734		8,020		2,498
Earnings (losses) of unconsolidated equity-method
	investments	1,987		(649)		2,335		2,653
Other (expense) income, net		(1,410)		1,648		(1,171)		7,944
Total other income		4,939		2,733		9,184		13,095

Interest Charges:
Interest on long-term debt		19,427		18,268		38,868		34,835
Other interest		1,178		1,350		2,031		2,929
Allowance for borrowed funds used during construction		(3,287)		(1,658)		(5,478)		(2,785)
Total interest charges		17,318		17,960		35,421		34,979

Income Before Income Taxes		24,012		34,001		44,539		63,057

Income Tax (Benefit) Expense		(14,816)		7,675		(12,510)		17,447

Net Income		$	38,828	$	26,326	$	57,049	$	45,610

The accompanying notes are an integral part of these statements.

Idaho Power Company
Condensed Consolidated Balance Sheets
(unaudited)

	June 30,		December 31,
	2010		2009
Assets	(thousands of dollars)

Electric Plant:
In service (at original cost)	$	4,212,394	$	4,160,178
Accumulated provision for depreciation	(1,586,118)		(1,558,538)
In service- net	2,626,276		2,601,640
Construction work in progress	363,982		289,188
Held for future use	7,106		7,151
Electric plant- net	2,997,364		2,897,979

Investments and Other Property	108,921		108,299

Current Assets:
Cash and cash equivalents	25,118		21,625
Receivables:
Customer (net of allowance of $1,311 and $1,805, respectively)	64,216		74,987
Other (net of allowance of $202 and $185, respectively)	21,810		10,463
Taxes receivable	21,640		3,585
Accrued unbilled revenues	51,399		51,272
Materials and supplies (at average cost)	47,436		48,054
Fuel stock (at average cost)	29,206		25,634
Prepayments	10,141		10,960
Deferred income taxes	7,931		7,887
Other	5,409		2,115
Total current assets	284,306		256,582

Deferred Debits:
American Falls and Milner water rights	22,641		24,226
Company-owned life insurance	27,079		26,654
Regulatory assets	676,820		720,401
Other	40,384		39,249
Total deferred debits	766,924		810,530

Total	$	4,157,515	$	4,073,390

The accompanying notes are an integral part of these statements.

Idaho Power Company
Condensed Consolidated Balance Sheets
(unaudited)

	June 30,		December 31,
	2010		2009
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	648,758		638,758
Capital stock expense	(2,097)		(2,097)
Retained earnings	575,876		547,695
Accumulated other comprehensive loss	(8,678)		(8,267)
Total common stock equity	1,311,736		1,273,966

Long-term debt	1,288,802		1,409,730
Total capitalization	2,600,538		2,683,696

Current Liabilities:
Long-term debt due within one year	121,064		1,064
Accounts payable	77,564		83,128
Notes and accounts payable to related parties	1,473		1,736
Taxes accrued	9,366		-
Interest accrued	21,821		20,056
Other	69,252		40,002
Total current liabilities	300,540		145,986

Deferred Credits:
Deferred income taxes	599,328		611,749
Regulatory liabilities	301,568		287,780
Other	355,541		344,179
Total deferred credits	1,256,437		1,243,708

Commitments and Contingencies

Total	$	4,157,515	$	4,073,390

The accompanying notes are an integral part of these statements.

Idaho Power Company
Condensed Consolidated Statements of Capitalization
(unaudited)

	June 30,		December 31,
	2010		2009
	(thousands of dollars)
Common Stock Equity:
Common stock	$	97,877	$	97,877
Premium on capital stock	648,758		638,758
Capital stock expense	(2,097)		(2,097)
Retained earnings	575,876		547,695
Accumulated other comprehensive loss	(8,678)		(8,267)
Total common stock equity	1,311,736		1,273,966

Long-Term Debt:
First mortgage bonds:
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
6.025% Series due 2018	120,000		120,000
6.15% Series due 2019	100,000		100,000
4.50 % Series due 2020	130,000		130,000
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		140,000
6.25% Series due 2037	100,000		100,000
Total first mortgage bonds	1,215,000		1,215,000
Amount due within one year	(120,000)		-
Net first mortgage bonds	1,095,000		1,215,000

Pollution control revenue bonds:
5.15% Series due 2024	49,800		49,800
5.25% Series 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	7,446		8,509
Note guarantee due within one year	(1,064)		(1,064)
Unamortized premium/discount- net	(2,925)		(3,060)

Total long-term debt	1,288,802		1,409,730

Total Capitalization	$	2,600,538	$	2,683,696
The accompanying notes are an integral part of these statements.

Idaho Power Company

Condensed Consolidated Statements of Cash Flows
(unaudited)

	Six months ended
	June 30,
	2010		2009
Operating Activities:	(thousands of dollars)
Net income	$	57,049	$	45,610
Adjustments to reconcile net income to net cash provided by
operating activities:
Depreciation and amortization	60,709		55,030
Deferred income taxes and investment tax credits	(17,559)		3,354
Changes in regulatory assets and liabilities	78,974		38,358
Non-cash pension expense	2,952		2,209
Earnings of unconsolidated equity-method investments	(2,335)		(2,653)
Distributions from unconsolidated equity-method investments	-		7,460
Allowance for other funds used during construction	(8,020)		(2,498)
Other non-cash adjustments to net income	(2,474)		736
Change in:
Accounts receivables and prepayments	6,250		(8,665)
Accounts payable	(8,315)		(29,800)
Taxes accrued/receivable	(8,791)		34,350
Other current assets	(3,081)		(11,940)
Other current liabilities	18,211		(1,234)
Other assets	(2,512)		(1,831)
Other liabilities	(4,309)		(14,094)
Net cash provided by operating activities	166,749		114,392
Investing Activities:
Additions to utility plant	(166,687)		(100,271)
Proceeds from the sale of utility assets	19,230		-
Proceeds from the sale of non-utility assets	-		2,250
Proceeds from the sale of emission allowances and renewable energy certificates	3,497		2,341
Investments in unconsolidated affiliates	(2,020)		-
Other	2,890		(3,359)
Net cash used in investing activities	(143,090)		(99,039)
Financing Activities:
Issuance of long-term debt	-		100,000
Retirement of long-term debt	(1,064)		(1,064)
Dividends on common stock	(28,869)		(28,376)
Net change in short term borrowings	-		(76,120)
Capital contribution from parent	10,000		-
Other	(233)		(1,411)
Net cash used in financing activities	(20,166)		(6,971)
Net increase in cash and cash equivalents	3,493		8,382
Cash and cash equivalents at beginning of the period	21,625		3,141
Cash and cash equivalents at end of the period	$	25,118	$	11,523
Supplemental Disclosure of Cash Flow Information:
Cash paid (received) during the period for:
Income taxes	$	15,335	$	(18,286)
Interest (net of amount capitalized)	$	32,706	$	32,380
Non-cash investing activities:
Additions to property, plant and equipment in accounts payable	$	21,435	$	5,578
The accompanying notes are an integral part of these statements.

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

	Three months ended
	June 30,
	2010		2009
	(thousands of dollars)

Net Income	$	38,828	$	26,326

Other Comprehensive Income (Loss):
Net unrealized holding (losses) gains arising during the period,
net of tax of ($758) and $734	(1,181)		1,143
Unfunded pension liability adjustment, net of tax
of $114 and $87	177		136
Total Comprehensive Income	$	37,824	$	27,605

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,
	2010		2009
	(thousands of dollars)

Net Income	$	57,049	$	45,610

Other Comprehensive Income (Loss):
Net unrealized holding (losses) gains arising during the period,
net of tax of ($492) and $164	(765)		256
Unfunded pension liability adjustment, net of tax
of $227 and $174	354		272
Total Comprehensive Income	$	56,638	$	46,138

The accompanying notes are an integral part of these statements.

IDACORP, INC. AND IDAHO POWER COMPANY

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(unaudited)

1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES:

This Quarterly Report on Form 10-Q is a combined report of IDACORP, Inc. (IDACORP) and Idaho Power Company (Idaho Power). Therefore, the Notes to the condensed consolidated financial statements apply to both IDACORP and Idaho Power. However, Idaho Power 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 Idaho Power. 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.

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.

Principles of Consolidation

IDACORP’s and Idaho Power’s consolidated financial statements include the accounts of each company, the subsidiaries that the companies control, and any variable interest entities (VIEs) for which the companies are the primary beneficiaries. All intercompany balances have been eliminated in consolidation. Investments in subsidiaries that the companies do not control and investments in VIEs for which the companies 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 of accounting.

In January 2010, IDACORP and Idaho Power adopted amendments to prior consolidation guidance. The amendments affected the overall consolidation analysis of VIEs and required IDACORP and Idaho Power to reconsider their previous conclusions relating to the consolidation of VIEs, including (1) whether an entity is a VIE, (2) whether either IDACORP or Idaho Power are the VIE’s primary beneficiary, and (3) what type of financial statement disclosures are required. The adoption of this guidance did not change the entities that IDACORP or Idaho Power consolidate.

The entities that IDACORP and Idaho Power consolidate consist primarily of the wholly-owned subsidiaries discussed above. In addition, IDACORP consolidates one VIE, Marysville Hydro Partners (Marysville), which is a joint venture owned 50 percent by Ida-West and 50 percent by Environmental Energy Company (EEC). Marysville has approximately $20 million of assets, primarily a hydroelectric plant, and approximately $16 million of intercompany long-term debt, which is eliminated in consolidation. EEC has borrowed amounts from Ida-West to fund a portion of its required capital contributions to Marysville. The loans are payable from EEC’s share of distributions and are secured by the stock of EEC and EEC’s interest in Marysville. Ida-West is the primary beneficiary because the ownership of the intercompany note and the EEC note result in it controlling the entity. Creditors of Marysville have no recourse to the general credit of IDACORP and there are no other arrangements that could require IDACORP to provide financial support to Marysville or expose IDACORP to losses.

Through IERCo, Idaho Power holds a variable interest in BCC, a VIE for which it is not the primary beneficiary. IERCo is not the primary beneficiary because the power to direct the activities that most significantly impact the economic performance of BCC is shared with the joint venture partner. IERCo’s carrying value is $88 million and its maximum exposure to loss at BCC is the carrying value, any additional future contributions to the mine, and the $63 million guarantee for reclamation costs at the mine that is discussed further in Note 8 – “Commitments.”

Through IFS, IDACORP also holds variable interests in VIEs for which it is not the primary beneficiary. These VIEs are historic rehabilitation and affordable housing developments in which IFS holds limited partnership interests ranging from five to 99 percent. As a limited partner, IFS does not control these entities and they are not consolidated. These investments were acquired between 1996 and 2010. IFS’s maximum exposure to loss in these developments is limited to its net carrying value, which was $79 million at June 30, 2010.

Financial Statements

In the opinion of IDACORP and Idaho Power, the accompanying unaudited condensed consolidated financial statements contain all adjustments necessary to present fairly their consolidated financial positions as of June 30, 2010, consolidated results of operations for the three and six months ended June 30, 2010, and 2009, and consolidated cash flows for the six months ended June 30, 2010, and 2009. 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 should be read in conjunction with the audited consolidated financial statements included in IDACORP’s and Idaho Power’s Annual Report on Form 10-K for the year ended December 31, 2009. The results of operations for the interim periods are not necessarily indicative of the results to be expected for the full year.

Use of Estimates

The preparation of condensed consolidated financial statements in accordance with generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosures of contingent liabilities, as of the date of the financial statements, and the reported amounts of revenues and expenses during the reporting period. Actual results experienced could differ materially from those estimates.

Reclassifications

Certain prior year amounts have been reclassified to conform to the current year presentation. The reclassifications did not impact IDACORP’s and Idaho Power’s net income or total equity, and include the following:

Third-party transmission expense was combined with purchased power in IDACORP and Idaho Power’s condensed consolidated statements of income as the balance of the third party transmission expense alone is immaterial;
Gain on sale of emission allowances was combined with other operations and maintenance in IDACORP and Idaho Power's condensed consolidated statements of income as the balance of gain on sale of emission allowances alone is immaterial;
Other operations and maintenance in the operating expenses section of Idaho Power’s condensed consolidated statements of income were combined to be consistent with presentation in IDACORP's condensed consolidated statements of income;
Allowance for uncollectible accounts was offset against associated accounts receivable and presented in a parenthetical notation in IDACORP and Idaho Power's condensed consolidated balance sheets;
Excess tax benefits from share-based payment arrangements was combined with other non-cash adjustments to net income in the operating section and with other in the financing section of IDACORP's condensed consolidated statements of cash flows; and
Amortization of affordable housing was removed from depreciation and amortization and combined with undistributed earnings of unconsolidated subsidiaries, the total of which was then separated into losses of unconsolidated equity-method investments and distributions from unconsolidated equity method investments in the operating section of IDACORP's condensed consolidated statements of cash flows.

New Accounting Pronouncements

In July 2010, the Financial Accounting Standards Board issued guidance that significantly expands the required disclosures concerning the credit quality of certain types of receivables and the allowance for credit losses. This guidance is effective for IDACORP and Idaho Power as follows: (1) disclosures concerning end-of-period information are effective for the December 31, 2010, financial statements; and (2) disclosures about activity occurring during a reporting period are effective beginning with the quarter ending March 31, 2011. Because this guidance relates only to disclosures, it is not expected to have a material effect on IDACORP’s and Idaho Power’s consolidated financial statements.

2. INCOME TAXES:

In accordance with interim reporting requirements, IDACORP and Idaho Power use an estimated annual effective tax rate for computing their provisions for income taxes. An estimate of annual income tax expense (or benefit) is made each interim period using estimates for annual pre-tax income, income tax adjustments, and tax credits. The estimated annual effective tax rates do not include discrete events such as tax law changes, examination settlements, or method changes. Discrete events are recorded in the period in which they occur.

The estimated annual effective tax rate is applied to year-to-date pre-tax income to achieve income tax expense (or benefit) for the interim period consistent with the annual estimate. In subsequent interim periods, income tax expense (or benefit) for the period is computed as the difference between the year-to-date amount reported for the previous interim period and the current period’s year-to-date amount.

An analysis of income tax expense for the three months ended June 30 is as follows (in thousands of dollars):

		IDACORP				Idaho Power
		2010		2009		2010		2009
Income tax provision		$	4,046	$	5,175	$	5,859	$	7,675
ADITC amortization reversal			4,512		-		4,512		-
Accounting method change			(25,187)		-		(25,187)		-
	Income tax (benefit) expense	$	(16,629)	$	5,175	$	(14,816)	$	7,675
Effective tax rate			(73.6)%		15.8%		(61.7)%		22.6%

An analysis of income tax expense for the six months ended June 30 is as follows (in thousands of dollars):

		IDACORP				Idaho Power
		2010		2009		2010		2009
Income tax provision		$	8,960	$	11,970	$	11,774	$	17,447
Accounting method change			(25,187)		-		(25,187)		-
Medicare Part D subsidy			903		-		903		-
	Income tax (benefit) expense	$	(15,324)	$	11,970	$	(12,510)	$	17,447
Effective tax rate			(38.4)%		20.5%		(28.1)%		27.7%

The decrease in the 2010 estimated annual effective tax rates as compared to the same periods of 2009 is primarily due to Idaho Power’s tax accounting method change for repair-related expenditures (discussed below), and lower pre-tax earnings at IDACORP and Idaho Power, partially offset by a charge related to the federal health care legislation enacted in the first quarter of 2010. Regulatory flow-through tax adjustments at Idaho Power and tax credits at IFS for the six months ended June 30, 2010 were comparable to the same period in 2009.

Based on its current estimate of 2010 return on equity, Idaho Power does not expect to amortize any additional accumulated deferred investment tax credits (ADITC). Accordingly, the $4.5 million of additional ADITC amortization recorded in the first quarter of 2010 was reversed in the second quarter of 2010. For further information regarding ADITC amortization, see Note 3 – “Regulatory Matters - Idaho Settlement Agreement.”

Tax Accounting Method Change

In June 2010, Idaho Power completed its evaluation of a tax accounting method change for its 2009 tax year that would allow a current income tax deduction for repair-related expenditures on its utility assets that are currently capitalized for financial reporting and tax purposes. Idaho Power intends to make this method change following the automatic consent procedures with the filing of IDACORP’s 2009 consolidated federal income tax return in September 2010. For the three months ended June 30, 2010, Idaho Power recorded an estimated net tax benefit of $25.2 million related to the cumulative method change adjustment (tax years 1999 through 2009) and has included an annual deduction estimate in its 2010 income tax provision, which resulted in a $3.6 million net tax benefit. Idaho Power’s prescribed regulatory accounting treatment requires immediate income recognition for temporary tax differences of this type. A regulatory asset is established to reflect Idaho Power’s ability to recover increased income tax expense when such temporary differences reverse. Idaho Power expects to recognize cash tax benefits associated with the method change by the end of 2010 through offsets to current estimated tax payments and direct tax refunds.

In conjunction with recording the estimated tax benefit for the method change, Idaho Power also increased its current liability for uncertain tax positions by $10.9 million. If recognized, the $10.9 million balance of unrecognized tax benefits would affect the effective tax rate. The tax method is currently being audited under IDACORP’s 2009 Compliance Assurance Process (CAP) examination (discussed below) and, on a national level, aspects of the method related to electric utility transmission and distribution property are the subject of an Internal Revenue Service (IRS) Industry Issue Resolution program.

Status of Audit Proceedings

In May 2009, IDACORP formally entered the IRS CAP program for its 2009 tax year. The CAP program provides for IRS examination throughout the year. The 2009 examination is expected to be completed in 2010. In January 2010, IDACORP was accepted into CAP for its 2010 tax year. IDACORP and Idaho Power are unable to predict the outcome of these examinations.

Specifically within the 2009 CAP examination, the IRS began its audit of Idaho Power’s current method of uniform capitalization. In September 2009, the IRS issued Industry Director Directive #5 (IDD), which discusses the IRS’s compliance priorities and audit techniques related to the allocation of mixed service costs in the uniform capitalization methods of electric utilities. The IRS and Idaho Power are jointly working through the impact the IDD guidance has on Idaho Power’s uniform capitalization method. Initial estimates indicate the potential income and cash benefits associated with settlement of this matter to be in excess of the repairs method change recorded in the second quarter. Idaho Power expects that the examination of this method will be completed during the third quarter of 2010; however, the timing of final settlement with the IRS, and thereby the recognition of the income and cash impacts, has yet to be determined. Resolution of this matter would also result in a $1.1 million decrease to Idaho Power’s unrecognized tax benefits for its 2009 uniform capitalization deduction.

Tax Impacts of Health Care Acts

As discussed further in Note 10 – “Benefit Plans,” the Patient Protection and Affordable Care Act and the Health Care and Education Reconciliation Act were enacted in March 2010. As a result of this legislation, in the first quarter of 2010, Idaho Power reduced its deferred tax asset related to future deductible retiree prescription drug expenses by $2.3 million, increased regulatory assets by $2.4 million, increased deferred tax liabilities by $1 million, and incurred a charge of $0.9 million. No charges resulting from the legislation were incurred in the second quarter of 2010.

3. REGULATORY MATTERS:

Deferred Net Power Supply Costs

Changes in deferred net power supply costs for the six months ended June 30, 2010 were as follows (in thousands of dollars):

			Idaho		Oregon⁽¹⁾		Total
Balance at December 31, 2009		$	71,412	$	13,221	$	84,633
Impact of current period net power supply costs			(23,282)		(593)		(23,875)
Prior costs expensed and recovered through rates			(51,671)		(849)		(52,520)
SO₂ allowances and REC sales credited to account			(2,307)		-		(2,307)
Interest and other			106		428		534
	Balance at June 30, 2010	$	(5,742)	$	12,207	$	6,465

⁽¹⁾ Oregon power supply cost deferrals are subject to a statute that specifically limits rate amortizations of deferred costs to six percent of gross Oregon revenue per year (approximately $2 million). Deferrals are amortized sequentially.

Idaho Settlement Agreement

On January 13, 2010, the Idaho Public Utilities Commission (IPUC) approved a settlement agreement among Idaho Power, several of Idaho Power’s customers, the IPUC Staff, and other parties. Significant elements of the settlement agreement include:

A general rate moratorium in effect until January 1, 2012. The moratorium does not apply to other specified revenue requirement proceedings, such as the power cost adjustment (PCA), the fixed cost adjustment (FCA), pension funding, advanced metering infrastructure (AMI), energy efficiency rider, and government imposed fees.
A specified distribution of the expected reduction in 2010 PCA rates that would reduce customer rates, provide some general rate relief to Idaho Power, and reset base power supply costs for the PCA. This provision anticipated a significant reduction in PCA rates for the 2010-2011 PCA year. The PCA reduction and base rate adjustment is discussed in “2010 Idaho PCA Filing and Order” below.
A provision to share with Idaho customers 50 percent of any Idaho-jurisdictional earnings in excess of a 10.5 percent return on equity in any calendar year from 2009 to 2011.
A provision to allow additional amortization of ADITC if Idaho Power’s actual return on equity in its Idaho jurisdiction is below 9.5 percent in any calendar year from 2009 to 2011. Idaho Power is permitted to amortize additional ADITC in an amount up to $45 million over the three-year period, but could use no more that $15 million in any one year unless there is a carryover. Carryover amounts are added to the $15 million annual allowance up to a maximum amortization of $25 million in any one year.

Because Idaho Power’s 2009 Idaho-jurisdiction return on equity was between 9.5 and 10.5 percent, the sharing and additional amortization provisions were not triggered, and the ADITC available for additional amortization in 2010 is $25 million. Idaho Power recorded additional ADITC amortization of $4.5 million in the first quarter of 2010, but reversed the entire $4.5 million in the second quarter based on updated estimates of annual 2010 return on equity. The actual amount of additional ADITC recorded in the full year 2010 and 2011 will depend on Idaho Power’s annual return on year-end equity and the amounts recorded in each quarter will vary and may ultimately be reversed.

The settlement agreement also included a provision to reestablish the base level for net power supply costs effective with the June 1, 2010, PCA rate change.

2010 Idaho PCA Filing and Order

On May 28, 2010, the IPUC issued an order approving a $146.9 million decrease in the PCA, along with a base rate increase of $88.7 million. The net effect of these two rate adjustments was an overall decrease in customer rates of $58.2 million, or 6.49 percent, effective June 1, 2010. Idaho Power’s PCA application was approved as filed with the IPUC, with the exception of a $0.2 million interest expense adjustment relating to base power supply costs.

Other Idaho 2010 Filings and Orders

Rate Filings and Orders: On May 28, 2010, the IPUC issued the following orders approving rate filings made in March 2010:

Fixed Cost Adjustment: Idaho Power’s FCA filing for the 2009 calendar year proposed to collect $6.3 million for one year, a $3.6 million annual increase over current rates. The $6.3 million reflects amounts accrued in 2009 under the mechanism. Beginning June 1, 2010, Idaho Power implemented the rate increase to residential and small general service customers. The IPUC also extended the FCA pilot program for two years, through December 31, 2011.
Pension: Idaho Power filed a request to recover $5.4 million of pension contributions that it is required to make on or before September 15, 2010. In accordance with prior IPUC orders, Idaho Power had been deferring its Idaho-jurisdiction pension expense to a regulatory asset. On February 17, 2010, the IPUC approved a recovery methodology that would permit Idaho Power to include in future rate cases a reasonable recovery and amortization of cash contributions. The IPUC approved Idaho Power’s request to increase rates by $5.4 million, or 0.77 percent, effective June 1, 2010. The IPUC’s order provided that the allowance of recovery of this contribution does not guarantee that the IPUC will similarly approve future recovery of contributions, without further justification, but reiterated its authorization to continue regulatory treatment of current pension expenses. In addition to the $5.4 million of regulatory assets approved for recovery discussed above, as of June 30, 2010, Idaho Power had $46.6 million of Idaho jurisdiction regulatory assets associated with deferred pension expenses that, based on its evaluation, are probable of recovery.
AMI: Idaho Power filed for a $2.4 million annual increase in base rates for costs related to AMI. The IPUC approved Idaho Power’s application as submitted, authorizing the rate increase effective June 1, 2010.

Energy Efficiency Prudency Determination: On March 15, 2010, Idaho Power filed an application with the IPUC requesting an order designating energy efficiency expenditures of $50.7 million incurred in 2008 and 2009 as prudently incurred expenses. A determination and order from the IPUC is pending.

On April 14, 2010, the IPUC completed its review of energy efficiency rider expenditures that Idaho Power made from 2002 through 2007. All rider expenditures during that time period were found to be prudently incurred and approved for ratemaking purposes.

Oregon Regulatory Matters

Oregon 2009 General Rate Case Settlement: In connection with Idaho Power’s general rate case filing, on February 24, 2010, the Oregon Public Utility Commission (OPUC) approved a $5 million, or 15.4 percent, increase in Oregon base rates. The new rates were effective March 1, 2010, and are based on a return on equity of 10.175 percent and an overall rate of return of 8.061 percent.

Oregon Power Cost Recovery Mechanisms: Idaho Power’s power cost recovery mechanism in Oregon has two components- the power cost adjustment mechanism (PCAM) and the annual power cost update (APCU). On February 26, 2010, Idaho Power filed its PCAM application for the 2009 year with the OPUC. The filing stated that actual net power supply costs were within the deadband, which is the range of deviations within which Idaho Power absorbs power supply cost increases or decreases, resulting in no request for a deferral. On April 15, 2010, Idaho Power filed with the OPUC a stipulation combining its March power supply cost forecast and 2009 October update. The stipulation was approved on May 24, 2010, and resulted in an overall increase of $2.2 million, or 5.5 percent, in Oregon rates, effective June 1, 2010.

Annual OATT Update

On June 1, 2010, Idaho Power posted its Draft Informational Filing (DIF) for its Open Access Transmission Tariff (OATT) on its Open Access Same-Time Information System (OASIS) Internet platform. The DIF is the draft computation of Idaho Power’s transmission rate for service under its OATT, which is updated annually. The new draft rate submitted by Idaho Power was $19.60 per kW/yr, a 23.8 percent increase over the present rate of $15.83

per kW/yr. Several third parties have submitted data requests in connection with Idaho Power’s DIF, and Idaho Power is currently responding to those data requests. If approved by the FERC, the new rates would be effective as of October 1, 2010 for a one year period.

4. LONG-TERM DEBT:

As of June 30, 2010, IDACORP had approximately $574 million remaining on a shelf registration statement that can be used for the issuance of debt securities or common stock.

In April 2010, Idaho Power received approval from the IPUC, the OPUC, and the Public Service Commission of Wyoming for the issuance of up to $500 million in aggregate principal amount of one or more series of first mortgage bonds and unsecured debt securities. The order from the IPUC approved the issuance of the securities over a two-year period, beginning on April 19, 2010, subject to extension upon request to the IPUC. On May 12, 2010, Idaho Power filed a shelf registration statement with the Securities and Exchange Commission (SEC) for the sale of up to $500 million of first mortgage bonds and debt securities. The SEC declared the registration statement effective on May 25, 2010. To facilitate the issuance of the first mortgage bonds, on June 17, 2010, Idaho Power entered into a Selling Agency Agreement with ten banks named in the agreement in connection with the potential issuance and sale from time to time of up to $500 million aggregate principal amount of first mortgage bonds, secured medium term notes, Series I, under Idaho Power’s Indenture of Mortgage and Deed of Trust, dated as of October 1, 1937, as amended and supplemented. As of August 5, 2010, Idaho Power had not sold any first mortgage bonds or debt securities under the May 2010 shelf registration statement.

5. NOTES PAYABLE:

Credit Facilities

IDACORP has a $100 million credit facility and Idaho Power has a $300 million credit facility, both of which expire on April 25, 2012. Commercial paper may be issued up to the amounts supported by the credit facilities. Under these facilities the companies pay a facility fee on the commitment, quarterly in arrears, based on its rating for senior unsecured long-term debt securities without third-party credit enhancement as provided by Moody’s Investors Service and Standard & Poor’s Ratings Services.

At June 30, 2010, no loans were outstanding on either IDACORP’s facility or Idaho Power’s facility. At June 30, 2010, Idaho Power had regulatory authority to incur up to $450 million of short-term indebtedness.

Balances and interest rates of IDACORP’s short-term borrowings were as follows at June 30, 2010, and December 31, 2009 (in thousands of dollars).

		June 30, 2010		December 31, 2009
IDACORP
	Commercial paper outstanding	$	17,500	$	53,750
	Weighted-average annual interest rate		0.46%		0.41%

Idaho Power had no short-term borrowings under its facility at either date.

6. COMMON STOCK:

IDACORP Common Stock

The following table summarizes shares of IDACORP common stock issued during the six months ended June 30, 2010:

		Shares issued
Balance at December 31, 2009		47,925,882
Dividend reinvestment and stock purchase plan		77,273
Employee savings plan		55,248
Long-term incentive and compensation plan (LTICP) ⁽¹⁾		92,743
Restricted stock plan		13,293
	Balance at June 30, 2010	48,164,439

⁽¹⁾ Included in the LTICP activity are 15,800 shares that were issued pursuant to the exercise of stock options on December 30, 2009, and settled on January 4, 2010.

IDACORP enters into sales agency agreements as a means of selling its common stock from time to time. As of June 30, 2010, there were 2.1 million shares remaining available to be sold under the current sales agency agreement.

Idaho Power Common Stock

On June 28, 2010, IDACORP contributed $10 million of additional equity to Idaho Power. No additional shares of Idaho Power common stock were issued.

Restrictions on Dividends

Idaho Power’s Revised Code of Conduct approved by the IPUC on April 21, 2008, states that Idaho Power will not pay any dividends to IDACORP that will reduce Idaho Power’s common equity capital below 35 percent of its total adjusted capital without IPUC approval.

Idaho Power’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 violate the covenants in their respective credit facilities or Idaho Power’s Revised Code of Conduct. At June 30, 2010, the leverage ratios for IDACORP and Idaho Power were 50 percent and 52 percent, respectively. Based on these restrictions, IDACORP’s and Idaho Power’s dividends were limited to $657 million and $553 million, respectively, at June 30, 2010. There are additional covenants, subject to exceptions, that prohibit or restrict: certain investments or acquisitions, mergers or sale or disposition of property without consent; the creation of certain liens; and any agreements restricting dividend payments to the company from any material subsidiary. At June 30, 2010, IDACORP and Idaho Power were in compliance with all facility covenants.

7. EARNINGS PER SHARE:

The following table presents the computation of IDACORP’s basic and diluted earnings per share (EPS) for the three and six months ended June 30, 2010 and 2009 (in thousands, except for per share amounts):

				Three months ended				Six months ended
				June 30,				June 30,
				2010		2009		2010		2009
Numerator:
	Net income attributable to IDACORP, Inc.			$	39,209	$	27,475	$	55,272	$	46,359
Denominator:
	Weighted-average common shares outstanding - basic				47,888		46,958		47,831		46,895
	Effect of dilutive securities:
		Options			41		9		41		11
		Restricted Stock			119		10		94		21
			Weighted-average common shares outstanding - diluted		48,048		46,977		47,966		46,927
Basic earnings per share				$	0.82	$	0.59	$	1.16	$	0.99
Diluted earnings per share				$	0.82	$	0.58	$	1.15	$	0.99

The diluted EPS computation excludes 343,835 and 344,918 options for the three and six months ended June 30, 2010, respectively, because the options’ exercise prices were greater than the average market price of the common stock during that period. For the same periods in 2009, there were 685,581 and 686,533 options excluded from the diluted EPS computation for the same reason. In total, 574,704 options were outstanding at June 30, 2010, with expiration dates between 2010 and 2015.

8. COMMITMENTS:

Purchase Obligations

The following items are the only material changes to purchase obligations made outside of the ordinary course of business during the first six months of 2010:

• Idaho Power entered into a power purchase agreement with USG Oregon, LLC for the purchase of energy from the Neal Hot Springs Unit #1 geothermal electric generation facility. The project will be located near Vale, Oregon and the expected output will be approximately 22 megawatts (MW), with an estimated on-line date of late 2012. Idaho Power’s purchases under the contract are expected to total $569 million from 2012 to 2037. On May 20, 2010, the IPUC issued an order approving the purchase of energy under the agreement and stated that the purchases would be allowed as prudently incurred expenses for ratemaking purposes.

• In the second quarter, Idaho Power entered into several purchased power agreements with wind and other alternate energy developers. These agreements are expected to total approximately $109 million from 2011 to 2031.

• In April 2010, Idaho Power entered into multiple service agreements with Northwest Pipeline for rate schedule TF-1, Firm Transportation. Idaho Power estimates it will spend approximately $32 million on the firm transportation service agreements. The service agreements commence in 2011 with varying end dates ranging through 2042.

• In June 2010, Idaho Power entered into a contract with Union Pacific Corporation for the transportation of coal. Idaho Power has agreed to spend approximately $47 million over the term of the contract from 2011 to 2014.

Guarantees

Idaho Power has agreed to guarantee the performance of reclamation activities and obligations at BCC, of which IERCo owns a one-third interest. This guarantee, which is renewed each December, was $63 million at June 30,

2010. BCC has a reclamation trust fund set aside specifically for the purpose of paying these reclamation costs. BCC continually assesses the adequacy of the reclamation trust fund and its estimate of future reclamation costs. To ensure that the reclamation trust fund maintains adequate reserves, BCC has the ability to add a per-ton surcharge to coal sales. In 2010, BCC began applying a nominal surcharge to coal sales in order to maintain adequate reserves in the reclamation trust fund. Because of the existence of the fund and the ability to apply a per-ton surcharge, the estimated fair value of this guarantee is minimal.

IDACORP and Idaho Power enter into financial agreements and power purchase and sale agreements that include indemnification provisions relating to certain claims or liabilities that may arise from the transactions contemplated by these agreements. Generally, a maximum obligation is not explicitly stated in the indemnification provisions and, therefore, the overall maximum amount of the obligation under such indemnifications cannot be reasonably estimated. IDACORP and Idaho Power periodically evaluate the likelihood of incurring costs under such indemnities based on their historical experience and the evaluation of the specific indemnities. As of June 30, 2010, management believes the likelihood is remote that IDACORP or Idaho Power would be required to perform under such indemnification provisions or otherwise incur any significant losses with respect to such indemnifications. Neither IDACORP nor Idaho Power has recorded any liability on their respective condensed consolidated balance sheets with respect to these indemnifications.

9. CONTINGENCIES:

In the course of their respective businesses, IDACORP, Idaho Power, and their respective subsidiaries have in the past and expect in the future to become involved in various claims, controversies, disputes, and other contingent matters, including the items described in this Note. Some of these claims, controversies, disputes, and other contingent matters involve litigation or other contested proceedings. IDACORP, Idaho Power, and their respective subsidiaries intend to vigorously protect and defend their interests and pursue their rights. However, no assurance can be given as to the ultimate outcome of any particular matter because litigation and other contested proceedings are inherently subject to numerous uncertainties. For matters that affect Idaho Power’s operations, Idaho Power intends to seek, to the extent permissible and appropriate, recovery of incurred costs through the ratemaking process.

Western Energy Proceedings at the FERC

In this report, the term “western energy situation” is used to refer to the California energy crisis that occurred during 2000 and 2001, and the energy shortages, high prices, and blackouts in the western United States. High prices for electricity in California and in western wholesale markets during 2000 and 2001 caused numerous purchasers of electricity in those markets to initiate proceedings seeking refunds or other forms of relief and the FERC to initiate its own investigations. Some of these proceedings (referred to in this report as the western energy proceedings) remain pending before the FERC or on appeal to the United States Court of Appeals for the Ninth Circuit (Ninth Circuit).

There are more than 200 petitions pending in the Ninth Circuit for review of numerous FERC orders regarding the western energy situation. Decisions in these appeals may have implications with respect to other pending cases, including those to which Idaho Power or IE are parties. Idaho Power and IE intend to vigorously defend their positions in these proceedings, but are unable to predict the outcome of these matters. Except as to the matters described below under “Pacific Northwest Refund,” Idaho Power and IE believe that settlement releases they have obtained that are described below under “California Refund” and “Market Manipulation” will restrict potential claims that might result from the disposition of the pending Ninth Circuit review petitions and that these matters will not have a material adverse effect on their consolidated financial positions, results of operations, or cash flows.

California Refund: This proceeding originated with an effort by agencies of the State of California and investor-owned utilities in California to obtain refunds for a portion of the spot market sales from sellers of electricity into California markets from October 2, 2000, through June 20, 2001. The FERC has issued numerous orders establishing price mitigation plans for sales in the California wholesale electricity market, including the methodology for determining refunds. IE and numerous other parties have petitioned the Ninth Circuit for review of the FERC’s orders on California refunds. As additional FERC orders have been issued, further petitions for review have been filed before the Ninth Circuit, which from time to time has identified discrete cases that can proceed to briefing and decision while it stayed action on the other consolidated cases.

On May 22, 2006, the FERC approved an Offer of Settlement between and among IE and Idaho Power, the California Parties (consisting of Pacific Gas & Electric Company, San Diego Gas & Electric Company, Southern California Edison Company, the California Public Utilities Commission, the California Electricity Oversight Board, the California Department of Water Resources (CDWR), and the California Attorney General) and additional parties that elected to be bound by the settlement. The settlement disposed of matters encompassed by the California refund proceeding, as well as market manipulation claims and investigations relating to the western energy situation among and between the parties agreeing to be bound by it. Although many market participants agreed to be bound by the settlement, other market participants, representing a small minority of potential refund claims, initially elected not to be bound by the settlement. From time to time, as the California Parties have reached settlements with those other market participants, they have elected to opt into the IE-Idaho Power-California Parties’ settlement. The settlement provided for approximately $23.7 million of IE’s and Idaho Power’s estimated $36 million rights to accounts receivable from the California Independent System Operator (Cal ISO) and the California Power Exchange (CalPX) to be assigned to an escrow account for refunds and for an additional $1.5 million of accounts receivable to be retained by the CalPX until the conclusion of the litigation. The additional $1.5 million of accounts receivable retained by the CalPX is available to fund the claims of non-settling parties if they prevail in the remaining litigation of these California market matters. Any additional amounts owed to non-settling parties would be funded by other amounts owed to IE and Idaho Power by the Cal ISO and CalPX, or directly by IE and Idaho Power, and any excess funds remaining at the end of the case would be returned to IE and Idaho Power. The remaining IE and Idaho Power receivables were paid to IE and Idaho Power under the settlement.

In an August 2006 decision, the Ninth Circuit ruled that all transactions that occurred within the CalPX and the Cal ISO markets from October 2, 2000 to June 21, 2001 were proper subjects of the refund proceeding. In that decision the Ninth Circuit refused to expand the proceedings into the bilateral market, required the FERC to consider claims that some market participants had violated governing tariff obligations at an earlier date than the refund effective date, and expanded the scope of the refund proceeding to include transactions within the CalPX and Cal ISO markets outside the limited 24-hour spot market and energy exchange transactions. Parts of the decision exposed sellers to increased claims for potential refunds. The Ninth Circuit issued its mandate on April 15, 2009, thereby officially returning the cases to the FERC for further action consistent with the court’s decision.

On November 19, 2009, the FERC issued an order to implement the Ninth Circuit’s remand. The remand order established a trial-type hearing in which participants will be permitted to submit information regarding (i) specified tariff violations committed by any public utility seller from January 1, 2000 to October 2, 2000 resulting in a transaction that set a market clearing price for the trading period when the violation occurred, and (ii) claims for refunds for multi-day transactions and energy exchange transactions entered into during the refund period (October 2, 2000 to June 20, 2001). Numerous parties, including IE and Idaho Power, filed motions to clarify the FERC’s order. Although IE and Idaho Power are unable to predict when or how the FERC will rule on these motions, the effect of the remand order for IE and Idaho Power is confined to the minority of market participants that are not bound by the IE-Idaho Power-California Parties’ settlement described above. On July 16, 2010, the FERC Chief Administrative Law Judge designated a presiding administrative law judge to establish hearing procedures. IE and Idaho Power believe the remanded proceedings will not have a material adverse effect on their consolidated financial positions, results of operations, or cash flows.

In 2005, the FERC established a framework for sellers wanting to demonstrate that the generally applicable FERC refund methodology interfered with the recovery of costs. IE and Idaho Power made such a cost filing, which was rejected by the FERC. On June 18, 2009, FERC issued an order stating that it was not ruling on IE's and Idaho Power's request for rehearing of the cost filing rejection because their request had been withdrawn in connection with the IE-Idaho Power-California Parties' settlement. On July 8, 2009, IE and Idaho Power sought further rehearing at the FERC because their withdrawal pertained only to the parties with whom IE and Idaho Power had settled. On June 18, 2009, in a separate order, the FERC ruled that only net refund recipients were responsible for the costs associated with cost filings. While most net refund recipients are bound by the settlement, until the Cal ISO completes its refund calculations it is uncertain whether there are any net refund recipients who are not bound by the settlement. If there are no such parties, then IE's and Idaho Power's request for rehearing will be moot. On May 18, 2010, the FERC denied rehearing. On June 25, 2010, IE and Idaho Power filed a petition for review of the pertinent FERC orders in the Ninth Circuit. IE and Idaho Power are unable to predict how or when the Ninth Circuit might rule, but the effect of any such ruling is confined to obligations of IE and Idaho Power to the small minority of

claims of market participants that are not bound by the settlement. Accordingly, IE and Idaho Power believe this matter will not have a material adverse effect on their consolidated financial positions, results of operations, or cash flows.

Market Manipulation: On June 25, 2003, the FERC ordered approximately 50 entities that participated in the western wholesale power markets between January 1, 2000 and June 20, 2001, including Idaho Power, to show cause why certain trading practices did not constitute gaming or other forms of proscribed market behavior in concert with another party (partnership) in violation of the Cal ISO and CalPX Tariffs. In 2004, the FERC dismissed the partnership show cause proceeding against Idaho Power. Later in 2004, the FERC approved a settlement of the gaming proceeding without finding of wrongdoing by Idaho Power.

The orders establishing the scope of the show cause proceedings are presently the subject of review petitions in the Ninth Circuit. On March 29, 2010, IE and Idaho Power filed a motion with the Ninth Circuit to dismiss 11 of the 12 petitions for review of the FERC’s orders establishing the scope of the show cause proceedings as they relate to IE and Idaho Power. Although IE and Idaho Power had obtained the consent to the motion from the 11 petitioners in those proceedings, the Ninth Circuit misconstrued the motion and instead granted on April 1, 2010 a motion to withdraw IE and Idaho Power interventions in the review proceedings. On April 9, 2010, with the consent of the same 11 petitioners, IE and Idaho Power filed a motion for reconsideration with the Ninth Circuit, again requesting dismissal of the 11 petitions as they pertain to IE and Idaho Power. On May 28, 2010, the Ninth Circuit denied reconsideration. Although IE and Idaho Power are unable to predict how or when the Ninth Circuit will act on the review petitions, in light of the settlement described above, IE and Idaho Power believe this matter will not have a material adverse effect on their consolidated financial positions, results of operations, or cash flows.

On June 25, 2003, the FERC also issued an order instituting an investigation of anomalous bidding behavior and practices in the western wholesale markets for the time period May 1, 2000 through October 1, 2000, but the FERC terminated its investigations as to Idaho Power on May 12, 2004. California government agencies and California investor-owned utilities have appealed the FERC’s termination of this investigation as to Idaho Power and more than 30 other market participants. IE and Idaho Power are unable to predict the outcome of these petitions for review proceedings, but believe that the settlement releases govern any potential claims that might arise and that this matter will not have a material adverse effect on their consolidated financial positions, results of operations, or cash flows.

Pacific Northwest Refund: On July 25, 2001, the FERC issued an order establishing a proceeding separate from the California refund proceeding to determine whether there may have been unjust and unreasonable charges for spot market sales in the Pacific Northwest during the period December 25, 2000 through June 20, 2001, because the spot market in the Pacific Northwest was affected by the dysfunction in the California market. In 2003, the FERC terminated the proceeding and declined to order refunds, but in 2007 the Ninth Circuit issued an opinion, in Port of Seattle, Washington v. FERC, remanding to the FERC the orders that declined to require refunds. The Ninth Circuit’s opinion instructed the FERC to consider whether evidence of market manipulation would have altered the agency’s conclusions about refunds and directed the FERC to include sales originating in the Pacific Northwest to the CDWR in the scope of proceeding. The Ninth Circuit officially returned the case to the FERC on April 16, 2009. On September 4, 2009, IE and Idaho Power joined with a number of other parties in a joint petition for a writ of certiorari to the U.S. Supreme Court, which was denied on January 11, 2010.

In separate filings, the California Parties, which no longer include the California Electricity Oversight Board, and the City of Tacoma, Washington (Tacoma) and the Port of Seattle, Washington (Port of Seattle) asked the FERC to reorganize and restructure the case to enable them to pursue claims that all spot market sales in the Cal ISO and CalPX markets and in the Pacific Northwest from January 1, 2000 through June 20, 2001 should be subject to refund and repriced, because market manipulation and tariff violations affected spot market prices. Their requests would expand the scope of the refund period in the Pacific Northwest proceeding from the December 25, 2000 through June 20, 2001 period previously considered by the FERC. On May 22, 2009, the California Parties filed a motion with the FERC to sever claims regarding sales originating in the Pacific Northwest to CDWR from the remainder of the Pacific Northwest proceedings and to consolidate their claims regarding these sales with ongoing proceedings in cases that IE and Idaho Power have settled, as well as with a new complaint filed on May 22, 2009 by the California Attorney General against parties with whom the California Parties have not settled (Brown Complaint). IE and Idaho Power, along with a number of other parties, filed their opposition to the motion of the California Parties.

Many other parties also filed responses to the motion of the California Parties. Tacoma and the Port of Seattle jointly filed a motion on August 4, 2009 with the FERC in connection with the California refund proceeding, the Lockyer remand pending before the FERC (involving claims of failure to file quarterly transaction reports with the FERC, from which IE and Idaho Power previously were dismissed), the Brown Complaint, and the Pacific Northwest refund remand proceeding. The Tacoma and the Port of Seattle motion asks the FERC to require refunds from all sellers in the Pacific Northwest spot markets for the expanded period (January 1, 2000 through June 20, 2001). IE and Idaho Power joined with a number of other sellers in the Pacific Northwest markets during 2000 and 2001 in opposing the motion of Tacoma and the Port of Seattle. On April 19, 2010, the California Parties filed a motion with the FERC renewing the requests contained in their May 22, 2009 motion and on May 3, 2010, IE and Idaho Power joined with a number of other parties opposing the renewal request. On July 21, 2010, the Port of Seattle and Tacoma once again filed a motion requesting that the FERC either summarily dispose of the case or set it for hearing, and the California Parties, answering a pleading in the Brown Complaint, renewed their request for consolidation. The FERC has not acted on the Ninth Circuit remand or the motions. IE and Idaho Power intend to vigorously defend their positions in these proceedings but are unable to predict the outcome of these matters or estimate the impact these matters may have on their consolidated financial positions, results of operations, or cash flows.

Sierra Club Lawsuit – Bridger

In February 2007, the Sierra Club and the Wyoming Outdoor Council filed a complaint against PacifiCorp in the U.S. District Court for the District of Wyoming alleging thousands of violations by PacifiCorp of air quality opacity standards at the Jim Bridger coal-fired plant in Sweetwater County, Wyoming. Opacity is an indication of the amount of light obscured by the flue gas of a power plant. The complaint sought a declaration that PacifiCorp had violated opacity limits, a permanent injunction ordering PacifiCorp to comply with such limits, civil penalties and reimbursement of plaintiffs’ costs of litigation. Idaho Power was 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. On April 15, 2010, the parties jointly filed a proposed consent decree resolving the pending litigation, and the consent decree was entered by the court on June 8, 2010. Idaho Power is fully reserved for the contingency, and entry of the consent decree will not have a material adverse effect on Idaho Power’s consolidated financial position, results of operations, or cash flows.

Sierra Club Lawsuit – Boardman

In September 2008, the Sierra Club and four other non-profit corporations filed a complaint against Portland General Electric Company (PGE) in the U.S. District Court for the District of Oregon alleging opacity permit limit violations at the Boardman coal-fired plant located in Morrow County, Oregon. The complaint also alleged violations of the Clean Air Act, related federal regulations, and the Oregon State Implementation Plan relating to PGE’s construction and operation of the plant. The complaint sought a declaration that PGE had violated opacity limits, a permanent injunction ordering PGE to comply with such limits, injunctive relief requiring PGE to remediate alleged environmental damage and ongoing impacts, civil penalties of up to $32,500 per day per violation, and reimbursement of plaintiffs’ costs of litigation, including reasonable attorneys’ fees. Idaho Power is not a party to this proceeding but has a 10 percent ownership interest in the Boardman plant. PGE owns 65 percent of the plant and is the operator of the plant. On December 5, 2008, PGE filed a motion to dismiss nine of the twelve claims asserted by the plaintiffs in their complaint, and on September 30, 2009, the court denied most of PGE’s motion to dismiss. Idaho Power continues to monitor the status of this matter but is unable to predict its outcome or what effect this matter may have on its consolidated financial position, results of operations, or cash flows.

Snake River Basin Adjudication

Idaho Power 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 Idaho Power.

On March 25, 2009, Idaho Power and the State of Idaho entered into a settlement agreement with respect to the 1984 Swan Falls Agreement and Idaho Power's water rights under the Swan Falls Agreement, which settlement agreement is subject to certain conditions discussed below. The settlement agreement will also resolve litigation

between Idaho Power and the State of Idaho relating to the Swan Falls Agreement that was filed by Idaho Power on May 10, 2007, with the Idaho District Court for the Fifth Judicial Circuit, which has jurisdiction over SRBA matters, including the Swan Falls case.

The settlement agreement resolves the pending litigation by clarifying that Idaho Power’s water rights in excess of minimum flows at its hydroelectric facilities between Milner Dam and Swan Falls Dam are subordinate to future upstream beneficial uses, including aquifer recharge. The agreement commits the State of Idaho and Idaho Power to further discussions on important water management issues concerning the Swan Falls Agreement and the management of water in the Snake River Basin. It also recognizes that water management measures that enhance aquifer levels, springs and river flows, such as aquifer recharge projects, benefit both agricultural development and hydropower generation and deserve study to determine their economic potential, their impact on the environment, and their impact on hydropower generation. These will be a part of the Comprehensive Aquifer Management Plan (CAMP) approved by the Idaho Water Resource Board for the Eastern Snake Plain Aquifer (ESPA), which includes limits on the amount of aquifer recharge. Idaho Power is a member of the ESPA CAMP advisory committee and implementation committee.

On April 24, 2009, the Governor of Idaho signed into law legislation approving provisions contained in the settlement agreement. On May 6, 2009, as part of the settlement, Idaho Power, the Governor of Idaho, and the Idaho Water Resource Board executed a memorandum of agreement relating to future aquifer recharge efforts and further assurances as to limitations on the amount of aquifer recharge. Idaho Power and the State of Idaho also filed a joint motion to the SRBA court to dismiss the Swan Falls case and enter the stipulated water right decrees set forth in the settlement agreement. Parties representing groundwater users in the Eastern Snake Plain Aquifer objected to some of the language proposed by Idaho Power and the State of Idaho relating to water rights in the decrees to be entered by the SRBA court as contemplated by the settlement agreement. Specifically, the concerns relate to the language describing the subordination of the rights and its interplay with the original Swan Falls settlement document and implementing legislation. On January 4, 2010, the court issued an order approving the overall settlement subject to certain modifications to the draft water right decrees proposed by the company and the State of Idaho. Idaho Power continues to work with the State of Idaho and the parties to reach an agreement consistent with the court’s order regarding the language of the decrees.

U.S. Bureau of Reclamation Proceedings

Idaho Power filed a complaint on October 15, 2007, and an amended complaint on September 30, 2008, in the U.S. District Court of Federal Claims in Washington, D.C. against the U.S. Bureau of Reclamation (USBR). The complaint relates to a 1923 contract right for delivery of water to Idaho Power’s hydropower projects on the Snake River, to recover damages from the USBR for the lost generation resulting from reduced flows, and for a prospective declaration of contractual rights and obligations of the parties. Over the past several months, Idaho Power has been working with the U.S. and Idaho interests (including the State of Idaho and upstream water users) in an effort to resolve certain state water right issues pending in the SRBA that are common to both the SRBA and the pending federal case. Current discussions primarily relate to modification to state policy and the Idaho water plan that promote more efficient operation of the upper Snake River reservoir system to optimize the release and shaping of Snake River flows for hydroelectric generation downstream during the high-load winter months. In an effort to promote efficiency, the parties have agreed to present certain legal issues associated with the 1923 contract to the court in the SRBA case that are expected to resolve issues in the pending federal case. The SRBA court has scheduled the presentation of these issues to the court by the fall of 2010. Idaho Power and the USBR have agreed to stay further proceedings in the federal case pending the resolution of these issues in the SRBA case. Idaho Power is unable to predict the outcome of this matter or what effect it may have on its financial position, results of operations, or cash flows.

Oregon Trail Heights Fire

On August 25, 2008, a fire ignited beneath an Idaho Power distribution line in Boise, Idaho. It was fanned by high winds and spread rapidly, resulting in one death, the destruction of 10 homes, and damage or alleged fire-related losses to approximately 30 others. Following the investigation, the Boise Fire Department determined that the fire was linked to a piece of line hardware on one of Idaho Power's distribution poles and that high winds contributed to the fire and its resultant damage. Idaho Power has received notice of claims from a number of the homeowners and

their insurers and while it has continued investigation of these claims, Idaho Power has reached settlements with a number of the individuals or their insurers who have alleged damages resulting from the fire. Idaho Power is insured up to policy limits against liability for claims in excess of its self-insured retention. Idaho Power has accrued a reserve for any loss that is probable and reasonably estimable, including insurance deductibles, and believes this matter will not have a material adverse effect on its consolidated financial position, results of operations, or cash flows.

Other Legal Proceedings

IDACORP, Idaho Power, and/or IE are parties to legal claims, actions, and proceedings in addition to those discussed above. Resolution of any of these matters will take time and the companies cannot predict the outcome of any of these proceedings. The companies currently believe that their reserves are adequate for these matters and that resolution of these matters, taking into account existing reserves, will not have a material adverse effect on IDACORP’s or Idaho Power’s consolidated financial positions, results of operations, or cash flows.

10. BENEFIT PLANS:

Idaho Power has a noncontributory defined benefit pension plan covering most employees. The benefits under the plan are based on years of service and the employee’s final average earnings. In addition, Idaho Power has a nonqualified deferred compensation plan for certain senior management employees and directors called the Senior Management Security Plan (SMSP). Idaho Power also maintains a defined benefit postretirement plan (consisting of health care and death benefits) that covers all employees who were enrolled in the active group plan at the time of retirement as well as their spouses and qualifying dependents. Idaho Power also has an Employee Savings Plan that complies with Section 401(k) of the Internal Revenue Code and covers substantially all employees. Idaho Power matches specified percentages of employee contributions to the Employee Savings Plan.

The following table shows the components of net periodic benefit costs for the pension, SMSP, and postretirement benefits plans for the three months ended June 30 (in thousands of dollars):

							Senior Management				Postretirement
			Pension Plan				Security Plan				Benefits
			2010		2009		2010		2009		2010		2009
Service cost			$	4,277	$	4,052	$	386	$	403	$	340	$	278
Interest cost				7,229		6,985		751		713		897		900
Expected return on plan assets				(6,277)		(5,895)		-		-		(640)		(545)
Amortization of transition obligation				-		-		-		-		510		510
Amortization of prior service cost				162		163		58		58		(134)		(133)
Amortization of net loss				1,913		2,308		233		165		144		231
	Net periodic benefit cost			7,304		7,613		1,428		1,339		1,117		1,241
Costs not recognized due to the
	effects of regulation ⁽¹⁾			(6,599)		(7,613)		-		-		-		-
	Net periodic benefit cost
		recognized for financial
		reporting ⁽²⁾	$	705	$	-	$	1,428	$	1,339	$	1,117	$	1,241

⁽¹⁾Under IPUC order, income statement recognition of Pension Plan costs has been deferred until costs are recovered through rates. See Note 3 - "Regulatory Matters" for information on Idaho Power's 2010 pension rate filing.
⁽²⁾Net periodic benefit costs for the pension plan are recognized for the Oregon jurisdiction and non-regulated subsidiaries, and beginning in June 2010, for the Idaho and FERC jurisdictions.

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

							Senior Management				Postretirement
			Pension Plan				Security Plan				Benefits
			2010		2009		2010		2009		2010		2009
Service cost			$	8,836	$	8,257	$	771	$	805	$	680	$	610
Interest cost				14,560		13,932		1,502		1,427		1,795		1,782
Expected return on plan assets				(12,577)		(11,983)		-		-		(1,280)		(1,073)
Amortization of transition obligation				-		-		-		-		1,020		1,020
Amortization of prior service cost				325		326		116		116		(268)		(267)
Amortization of net loss				3,838		4,428		466		330		287		421
	Net periodic benefit cost			14,982		14,960		2,855		2,678		2,234		2,493
Costs not recognized due to the
	effects of regulation⁽¹⁾			(14,026)		(14,960)		-		-		-		-
	Net periodic benefit cost
		recognized for financial
		reporting ⁽²⁾	$	956	$	-	$	2,855	$	2,678	$	2,234	$	2,493

⁽¹⁾ Under IPUC order, income statement recognition of Pension Plan costs has been deferred until costs are recovered through rates. See Note 3 – “Regulatory Matters” for information on Idaho Power’s 2010 pension rate filing.
⁽²⁾Net periodic benefit costs for the pension plan are recognized for the Oregon jurisdiction and non-regulated subsidiaries, and beginning in June 2010, for the Idaho and FERC jurisdictions.

Benefit Plan-Related Legislation

The Patient Protection and Affordable Care Act and the Health Care and Education Reconciliation Act were enacted in March 2010. One provision of this legislation eliminates the deductibility of employer health care costs for retiree prescription drug expenses that are covered by federal subsidy payments equivalent to Medicare Part D. While this provision is not effective until 2013, relevant income tax accounting guidance requires recognition of the future effects of new law in the period of enactment. Due to the regulatory treatment of postretirement benefit costs, the increase in certain postretirement costs relating to the legislation is deferred as a regulatory asset. See Note 2 – “Income Taxes” for the tax impacts recorded as a result of this legislation.

In June 2010, the Preservation of Access to Care for Medicare Beneficiaries and Pension Relief Act of 2010 was signed into law, which permits employers to choose between two alternative funding options for defined benefit pension plans for any two plan years between 2008 and 2011, either (i) amortizing the funding shortfall for the applicable years over 15 years or (ii) paying interest only on the applicable plan years’ funding shortfall for two plan years followed by amortization of the actual shortfall for 7 years. Idaho Power is currently evaluating the new legislation and its potential impacts, but no decision has been made in regard to this act. If an alternate funding option is elected, it would reduce near-term required contributions to the plan by spreading them over a longer time period. Unless Idaho Power elects to utilize an alternative amortization schedule under the new legislation, minimum required contributions to the pension plan is $6 million in the third quarter of 2010, and are estimated to be $44 million, $47 million, $39 million, and $40 million in 2011, 2012, 2013, and 2014, respectively. Idaho Power may elect to make contributions earlier than the required dates.

The legislation does not eliminate Idaho Power’s obligation to fully fund the pension plan. In addition, the legislation outlines penalties in the form of increased pension contributions from an employer that elects one of the funding relief options at the same time that employer (or entities within its ERISA-controlled group) awards “excess employee compensation” (generally compensation over $1 million per year paid to an employee), grants “excessive” dividends, or effects specified stock redemptions. Idaho Power will evaluate the legislation and its alternatives further prior to electing an alternative, if any. See Note 3 - “Regulatory Matters” for a discussion of Idaho Power’s recovery of pension plan contributions through the ratemaking process.

11. INVESTMENTS IN DEBT AND EQUITY SECURITIES:

Investments in debt and equity securities classified as available-for-sale securities are reported at fair value, using either specific identification or average cost to determine the cost for computing gains or losses. Any unrealized gains or losses on available-for-sale securities are included in other comprehensive income.

Investments classified as held-to-maturity securities are reported at amortized cost. Held-to-maturity securities are investments in debt securities for which the companies have the positive intent and ability to hold the securities until maturity.

The following table summarizes investments in debt and equity securities of IDACORP and Idaho Power as of June 30, 2010 and December 31, 2009 (in thousands of dollars):

June 30, 2010

December 31, 2009

Gross

Unrealized

Fair

Unrealized

Fair

Gain

Loss

Value

Gain

Loss

Value

Available-for-sale securities

1,731

16,281

2,989

18,842

At the end of each reporting period, IDACORP and Idaho Power analyze securities in loss positions to determine whether they have experienced a decline in market value that is considered other-than-temporary. At June 30, 2010 and December 31, 2009, no securities were in an unrealized loss position.

The following table summarizes sales of available-for-sale securities for the three and six months ended June 30, 2010 and 2009 (in thousands of dollars):

	Three months ended				Six months ended
	June 30,				June 30,
	2010		2009		2010		2009

Proceeds from sales	$	-	$	4,103	$	-	$	8,965
Gross realized gains from sales		-		-		-		11
Gross realized losses from sales		-		35		-		35

12. DERIVATIVE FINANCIAL INSTRUMENTS:

Commodity Price Risk

In connection with its ongoing business operations, Idaho Power is exposed to market risks relating to changes in electricity and natural gas commodity prices and certain other fuel prices, which are heavily influenced by supply and demand. Market risk may also be influenced by market participants’ nonperformance of their contractual obligations and commitments, which affects the supply of, or demand for, the commodity. Idaho Power utilizes derivative instruments, such as physical and financial forward contracts, for both electricity and fuel in order to manage the risks relating to these commodity price exposures. The objective of Idaho Power’s energy purchase and sale activity is to meet the demand of retail electric customers, maintain appropriate physical reserves to ensure reliability, and make economic use of temporary surpluses that may develop.

All derivative instruments are recognized as either assets or liabilities at fair value on the balance sheet. Idaho Power’s physical forward contracts, including renewable energy certificates, qualify for the normal purchases and normal sales exception to derivative accounting requirements with the exception of forward contracts for the purchase of natural gas for use at Idaho Power’s natural gas generation facilities. Because of Idaho Power’s power cost adjustment mechanisms, Idaho Power records the changes in fair value of derivative instruments related to power supply as regulatory assets or liabilities.

Idaho Power had the following volumes of derivative commodity forward contracts, entered into for the purpose of economically hedging forecasted purchases and sales, outstanding at June 30, 2010 and 2009:

		June 30,
Commodity	Units	2010	2009
Electricity purchases	MWh	875,650	564,800
Electricity sales	MWh	367,225	220,000
Natural gas purchases	MMBtu	1,898,750	2,797,750
Diesel purchases	Gallons	447,309	446,150

The following tables present the fair values and locations of derivatives not designated as hedging instruments recorded in the balance sheets at June 30, 2010 and December 31, 2009 (in thousands of dollars):

Commodity Derivatives			Asset Derivatives			Liability Derivatives
			Balance Sheet	Fair		Balance Sheet	Fair
June 30, 2010			Location	Value		Location	Value
Current:
	Financial swaps		Other current assets	$	17	Other current assets	$	-
	Financial swaps		Other current liabilities		-	Other current liabilities		3,889
	Forward contracts		Other current liabilities		-	Other current liabilities		384
Long-term:
	Financial swaps		Other assets		120	Other assets		-
	Financial swaps		Other liabilities		-	Other liabilities		2,387
		Total		$	137		$	6,660

December 31, 2009
Current:
	Financial swaps		Other current assets	$	2,931	Other current assets	$	2,087
	Financial swaps		Other current liabilities		9	Other current liabilities		610
	Forward contracts		Other current assets		354	Other current assets		-
Long-term:
	Financial swaps		Other assets		442	Other assets		229
		Total		$	3,736		$	2,926

The following table presents the effect on income of derivatives not designated as hedging instruments for the three and six months ended June 30, 2010 and 2009 (in thousands of dollars):

		Location of Gain/(Loss)	Amount of Gain/(Loss)
		Recognized in Income on	Recognized in Income on
Commodity Derivatives		Derivative	Derivative⁽¹⁾
Three months ended June 30, 2010:
	Financial swaps	Off-system sales	$	496
	Financial swaps	Purchased power		(2,223)
Three months ended June 30, 2009:
	Financial swaps	Off-system sales		2,287
	Financial swaps	Purchased power		(1,664)
Six months ended June 30, 2010:
	Financial swaps	Off-system sales	$	952
	Financial swaps	Purchased power		(2,385)
Six months ended June 30, 2009:
	Financial swaps	Off-system sales		2,287
	Financial swaps	Purchased power		(2,421)

(1) Excludes changes in fair value of derivatives, which are recorded on the balance sheet as regulatory assets or regulatory liabilities.

Settlement gains and losses on electricity swap contracts are recorded on the income statement in off-system sales or purchased power depending on the forecasted position being economically hedged by the derivative contract. Settlement gains and losses on both financial and physical contracts for natural gas are reflected in fuel expense. Settlement gains and losses on diesel derivatives, which are recorded in fuel stock on the balance sheet, were immaterial for the three and six months ended June 30, 2010. See Note 13 - “Fair Value Measurements” for additional information concerning the determination of fair value for Idaho Power’s assets and liabilities from price risk management activities.

Credit Risk

At June 30, 2010, Idaho Power does not have material credit exposure from financial instruments, including derivatives. Idaho Power monitors credit risk exposure through reviews of counterparty credit quality, corporate-wide counterparty credit exposure, and corporate-wide counterparty concentration levels. Idaho Power manages these risks by establishing appropriate credit and concentration limits on transactions with counterparties and requiring contractual guarantees, cash deposits, or letters of credit from counterparties or their affiliates, as deemed necessary. The majority of Idaho Power’s contracts are under the form of the Western Systems Power Pool agreement that provides for adequate assurances if a counterparty has debt that is downgraded to below investment grade by at least one rating agency. Idaho Power also requires North American Energy Standards Board contracts as necessary for physical gas transactions, and International Swaps and Derivatives Association, Inc. contracts as needed for financial transactions.

Credit-Contingent Features

Certain of Idaho Power’s derivative instruments contain provisions that require Idaho Power’s unsecured debt to maintain an investment grade credit rating from each of the major credit rating agencies. If Idaho Power’s unsecured debt were to fall below investment grade, it would be in violation of these provisions, and the counterparties to the derivative instruments could request immediate payment or demand immediate and ongoing full overnight collateralization on derivative instruments in net liability positions. The aggregate fair value of all derivative instruments with credit-risk-related contingent features that are in a liability position on June 30, 2010, was $10 million. Idaho Power had posted $7 million of collateral related to this amount. If the credit-risk-related contingent features underlying these agreements were triggered on June 30, 2010, Idaho Power would have been required to post $1 million of additional cash collateral to its counterparties.

13. FAIR VALUE MEASUREMENTS:

IDACORP and Idaho Power have categorized their financial instruments, based on the priority of the inputs to the valuation technique, into a three-level fair value hierarchy. The fair value hierarchy gives the highest priority to quoted prices in active markets for identical assets or liabilities (Level 1) and the lowest priority to unobservable inputs (Level 3). If the inputs used to measure the financial instruments fall within different levels of the hierarchy, the categorization is based on the lowest level input that is significant to the fair value measurement of the instrument.

Financial assets and liabilities recorded on the condensed consolidated balance sheets are categorized based on the inputs to the valuation techniques as follows:

• Level 1: Financial assets and liabilities whose values are based on unadjusted quoted prices for identical assets or liabilities in an active market that IDACORP and Idaho Power has the ability to access.

• Level 2: Financial assets and liabilities whose values are based on the following:

a) Quoted prices for similar assets or liabilities in active markets;

b) Quoted prices for identical or similar assets or liabilities in non-active markets;

c) Pricing models whose inputs are observable for substantially the full term of the asset or liability; and

d) Pricing models whose inputs are derived principally from or corroborated by observable market data through correlation or other means for substantially the full term of the asset or liability.

IDACORP and Idaho Power Level 2 inputs are based on quoted market prices adjusted for location using corroborated, observable market data.

• Level 3: Financial assets and liabilities whose values are based on prices or valuation techniques that require inputs that are both unobservable and significant to the overall fair value measurement. These inputs reflect management’s own assumptions about the assumptions a market participant would use in pricing the asset or liability.

Idaho Power’s derivatives are contracts entered into as part of its management of loads and resources. Electricity swaps are valued on the Intercontinental Exchange with quoted prices in an active market. Natural gas and diesel derivative valuations are performed using New York Mercantile Exchange (NYMEX) pricing, adjusted for basis location, which are also quoted under NYMEX. Trading securities consists of employee-directed investments held in a Rabbi Trust and are related to an executive deferred compensation plan. Available-for-sale securities are related to the SMSP and are held in a Rabbi Trust and are actively traded money market and equity funds with quoted prices in active markets.

The table below presents information about IDACORP’s and Idaho Power’s assets and liabilities measured at fair value on a recurring basis as of June 30, 2010, and December 31, 2009 (in thousands of dollars). IDACORP’s and Idaho Power’s assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy. There were no transfers between levels for the periods presented.

		Quoted Prices in		Significant		Significant
		Active Markets		Other		Unobservable
		for Identical		Observable		Inputs
		Assets (Level 1)		Inputs (Level 2)		(Level 3)		Total
June 30, 2010
IDACORP
Assets:
	Derivatives	$	137	$	-	$	-	$	137
	Money market funds		11,776		-		-		11,776
	Trading securities: Equity securities		4,599		-		-		4,599
	Available-for-sale securities: Equity securities		16,281		-		-		16,281
Liabilities:
	Derivatives	$	(2,810)	$	(384)	$	-	$	(3,194)
Idaho Power
Assets:
	Derivatives	$	137	$	-	$	-	$	137
	Money market funds		10,000		-		-		10,000
	Trading securities: Equity securities		4,089		-		-		4,089
	Available-for-sale securities: Equity securities		16,281		-		-		16,281
Liabilities:
	Derivatives	$	(2,810)	$	(384)	$	-	$	(3,194)

December 31, 2009
IDACORP
Assets:
	Derivatives	$	1,056	$	354	$	-	$	1,410
	Money market funds		38,221		-		-		38,221
	Trading securities: Equity securities		6,286		-		-		6,286
	Available-for-sale securities: Equity securities		18,842		-		-		18,842
Liabilities:
	Derivatives	$	(601)	$	-	$	-	$	(601)
Idaho Power
Assets:
	Derivatives	$	1,056	$	354	$	-	$	1,410
	Money market funds		19,364		-		-		19,364
	Trading securities: Equity securities		5,217		-		-		5,217
	Available-for-sale securities: Equity securities		18,842		-		-		18,842
Liabilities:
	Derivatives	$	(601)	$	-	$	-	$	(601)

The table below presents the carrying value and estimated fair value of financial instruments that are not reported at fair value, as of June 30, 2010 and December 31, 2009, using available market information and appropriate valuation methodologies. The use of different market assumptions and/or estimation methodologies may have a material effect on the estimated fair value amounts. Cash and cash equivalents, deposits, customer and other receivables, notes payable, accounts payable, interest accrued, and taxes accrued are reported at their carrying value as these are a reasonable estimate of their fair value. The estimated fair values for notes receivable and long-term debt are based upon quoted market prices of the same or similar issues or discounted cash flow analyses as appropriate.

		June 30, 2010				December 31, 2009
		Carrying		Estimated		Carrying		Estimated
		Amount		Fair Value		Amount		Fair Value
		(thousands of dollars)
IDACORP
Assets:
	Notes receivable	$	2,946	$	2,946	$	2,946	$	2,946
Liabilities:
	Long-term debt		1,421,526		1,490,961		1,422,130		1,406,815
Idaho Power
Liabilities:
	Long-term debt	$	1,412,791	$	1,482,307	$	1,413,854	$	1,398,681

14. SEGMENT INFORMATION:

IDACORP’s only reportable segment is utility operations. The utility operations segment’s primary source of revenue is the regulated operations of Idaho Power. Idaho Power’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 Idaho Power that is also subject to regulation and is a one-third owner of BCC, an unconsolidated joint venture.

IDACORP’s other operating segments are below the quantitative and qualitative thresholds for reportable segments and are included in the “All Other” category. This category is comprised of IFS’s investments in affordable housing developments and historic rehabilitation projects, 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 the total of all other segments, and reconciles this information to total enterprise amounts (in thousands of dollars):

		Utility		All				Consolidated
		Operations		Other		Eliminations		Total
Three months ended June 30, 2010:
	Revenues	$	240,790	$	963	$	-	$	241,753
	Income attributable to IDACORP, Inc.		38,828		381		-		39,209
Total assets at June 30, 2010		$	4,157,515	$	144,879	$	(21,607)	$	4,280,787
Three months ended June 30, 2009:
	Revenues	$	242,518	$	1,116	$	-	$	243,634
	Income attributable to IDACORP, Inc.		26,326		1,149		-		27,475
Six months ended June 30, 2010:
	Revenues	$	493,250	$	1,466	$	-	$	494,716
	Income (loss) attributable to IDACORP, Inc.		57,049		(1,777)		-		55,272
Six months ended June 30, 2009:
	Revenues	$	470,547	$	1,661	$	-	$	472,208
	Income attributable to IDACORP, Inc.		45,610		749		-		46,359

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, 2010, and the related condensed consolidated statements of income and comprehensive income for the three-month and six-month periods ended June 30, 2010 and 2009 and of equity and cash flows for the six-month periods ended June 30, 2010 and 2009. 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, 2009, and the related consolidated statements of income, comprehensive income, equity, and cash flows for the year then ended (not presented herein); and in our report dated February 23, 2010, we expressed an unqualified opinion on those consolidated financial statements, which included an explanatory paragraph related to the adoption of accounting guidance for noncontrolling interests in consolidated financial statements and guidance for accounting for uncertainty in income taxes. In our opinion, the information set forth in the accompanying condensed consolidated balance sheet as of December 31, 2009 is fairly stated, in all material respects, in relation to the consolidated balance sheet from which it has been derived.

/s/ DELOITTE & TOUCHE LLP

Boise, Idaho
August 5, 2010

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, 2010, and the related condensed consolidated statements of income and comprehensive income for the three-month and six-month periods ended June 30, 2010 and 2009, and of cash flows for the six-month periods ended June 30, 2010 and 2009. 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, 2009, 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 23, 2010, we expressed an unqualified opinion on those consolidated financial statements, which included an explanatory paragraph related to the adoption of guidance for accounting for uncertainty in income taxes. In our opinion, the information set forth in the accompanying condensed consolidated balance sheet and statement of capitalization as of December 31, 2009 is fairly stated, in all material respects, in relation to the consolidated balance sheet and statement of capitalization from which it has been derived.

/s/ DELOITTE & TOUCHE LLP

Boise, Idaho
August 5, 2010

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

(Megawatt-hours (MWh) and dollar amounts, other than earnings per share, 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, Idaho Power) are discussed.

Idaho Power is an electric utility with a service territory covering approximately 24,000 square miles in southern Idaho and eastern Oregon. Idaho Power provided electric service to 490,470 general business customers as of June 30, 2010. Idaho Power is regulated by the FERC and the state regulatory commissions of Idaho and Oregon. Idaho Power is the parent of Idaho Energy Resources Co. (IERCo), a joint venturer in Bridger Coal Company (BCC), which mines and supplies coal to the Jim Bridger generating plant owned in part by Idaho Power. Idaho Power generates revenues and cash flows primarily from the sale and distribution of electricity to customers in its Oregon and Idaho service territory, as well as from the wholesale sale and transmission of electricity. Idaho Power’s revenues and income from operations are subject to fluctuations during the year due to the impacts of seasonal weather conditions on demand for electricity, price changes, customer usage patterns (which are affected in large part by the condition of the local economy), and the availability and price of purchased power and fuel. Idaho Power is a dual peaking utility that typically experiences its highest retail energy sales during the summer irrigation and cooling season, with a lower peak in the winter that generally results from heating demand. IDACORP’s and Idaho Power’s financial condition is also affected by regulatory decisions, through which Idaho Power seeks to recover its costs, including purchased power and fuel costs, on a timely basis, and to earn an authorized return on investment, and by the ability to obtain financing through the issuance of debt and/or equity securities.

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 (PURPA); and IDACORP Energy (IE), a marketer of energy commodities, which wound down operations in 2003.

While reading the MD&A, please refer to the accompanying condensed consolidated financial statements of IDACORP and Idaho Power. This discussion updates the MD&A included in the Annual Report on Form 10-K for the year ended December 31, 2009, and the Quarterly Report on Form 10-Q for the quarter ended March 31, 2010, and should be read in conjunction with the discussions in those reports.

FORWARD-LOOKING INFORMATION

In addition to the historical information contained in this report, this report includes forward-looking statements. In connection with the safe harbor provisions of the Private Securities Litigation Reform Act of 1995, IDACORP and Idaho Power are hereby filing cautionary statements identifying important factors that could cause actual results to differ materially from those projected in forward-looking statements, made by or on behalf of IDACORP or Idaho Power in this report, in presentations, in response to questions or otherwise. Any statements that express, or involve discussions as to expectations, beliefs, plans, objectives, assumptions or future events or performance, often, but not always, through the use of words or phrases such as "anticipates," "believes," "estimates," "expects," "intends," "plans," "predicts," "projects," "may result," "may continue," or similar expressions, are not statements of historical facts and may be forward-looking. Forward-looking statements are not guarantees of future performance and involve estimates, assumptions, risks, and uncertainties and are qualified in their entirety by reference to, and are

accompanied by, the following important factors that could cause actual results or outcomes to differ materially from those expressed. In addition to any assumptions and other factors and matters referred to specifically in connection with such forward-looking statements, factors that could cause actual results or outcomes to differ materially from those discussed in forward-looking statements include those factors discussed in IDACORP’s and Idaho Power’s 2009 Annual Report on Form 10-K, particularly Item 1A – “Risk Factors,” as updated by Part II, Item 1A of this Quarterly Report on Form 10-Q, and the following important factors:

The effect of regulatory decisions by the Idaho Public Utilities Commission, the Oregon Public Utility Commission, and the Federal Energy Regulatory Commission affecting Idaho Power’s ability to recover costs and/or earn a reasonable rate of return, including, but not limited to, the disallowance of costs that have been deferred, financings, allowed rates of return, electricity pricing and price structures, acquisition and disposal of assets and facilities, and current or prospective wholesale and retail competition;
Changes in and compliance with state and federal laws, policies, and regulations, including new interpretations by regulatory and oversight bodies, which include the Federal Energy Regulatory Commission, the North American Electric Reliability Corporation, the Western Electricity Coordinating Council, the Idaho Public Utilities Commission, the Oregon Public Utility Commission, and the Department of Energy of existing policies and regulations that affect the cost of compliance, investigations and audits, penalties, and costs of remediation that may or may not be recoverable through rates;
Changes in tax laws or related regulations or new interpretations of applicable law by the Internal Revenue Service or state and local taxing jurisdictions, and the availability and use by IDACORP or Idaho Power of any tax credits;
Litigation and regulatory proceedings, including those resulting from the energy situation in the western United States and the Snake River Basin water rights adjudication, and penalties, settlements, or awards that influence business and profitability;
Changes in and costs of compliance with laws, regulations, and policies relating to the environment, natural resources, and endangered species and the adoption of laws and regulations addressing greenhouse gas emissions, global climate change, and energy policies, particularly with respect to coal-fired generation facilities, intended to mitigate carbon dioxide, mercury, and other emissions;
Global climate change and regional weather variations affecting customer demand and hydroelectric generation;
Over-appropriation of surface and groundwater in the Snake River Basin, including proposals for use of water in the Snake River Basin for aquifer recharge, resulting in reduced generation at hydroelectric facilities;
Construction of power generation, transmission and distribution facilities, including an inability to obtain required governmental permits and approvals, rights-of-way and siting, and risks related to contracting, construction, and start-up;
Delays and cost increases in connection with the construction or modification of generating facilities and other capital projects, which could result in the disallowance of recovery of certain costs pursuant to the rate determination process;
Operation of power generating facilities, including performance below expected levels, breakdown or failure of equipment, forced outages, availability of electrical transmission capacity, and the availability of water, natural gas, coal, and diesel, wind conditions, and their associated delivery infrastructures;
Changes in operating expenses and capital expenditures, including costs and availability of materials, fuel, and commodities, and their impact on Idaho Power’s ability to meet required loads and on the wholesale energy market in the western United States;
Blackouts or other disruptions of Idaho Power’s transmission system or the western interconnected transmission system;
Population growth rates and changes in residential, commercial, and industrial growth and demographic patterns within the service area;
The continuing effects of weak economies in the states of Idaho and Oregon and in the United States, including decreased demand for electricity and reduced revenue from sales of excess energy during periods of low wholesale market prices, impaired financial soundness of vendors and service providers, and elevated levels of uncollectible customer accounts;
Market prices and demand for energy, including structural market changes;

Reductions in credit ratings, which could adversely impact access to capital markets and would require the posting of additional collateral to counterparties pursuant to existing power purchase and other arrangements;
Increases in uncollectible customer receivables, and the effectiveness of Idaho Power’s risk management policies concerning the creditworthiness of third parties;
Results of financing efforts, including the ability to obtain financing or refinance existing debt when necessary or on favorable terms, which can be affected by factors such as credit ratings, volatility in the financial markets, and other economic conditions;
Performance of the stock market, interest rates, credit spreads, inflation, and other financial market conditions, as well as changes in government regulations, which affect, among other things, the cost of capital and the ability to access the capital markets, indebtedness obligations, the amount and timing of required contributions to pension plans, and the reported costs of providing pension and other postretirement benefits;
Increases in health care costs and the resulting effect on medical benefits paid for employees;
Increasing costs of insurance, changes in coverage terms, and the ability to obtain insurance;
The occurrence of events that affect homeland security, and acts of war or terrorism;
Weather and other natural phenomena such as earthquakes, floods, droughts, lightning, wind and fire, which, in addition to affecting customer demand for power, could significantly affect the ability and cost to procure adequate supplies of fuel or power to serve customers, and could increase the costs to maintain generating facilities and transmission and distribution system;
Adoption of or changes in accounting policies, principles, or estimates;
Unionization, or the attempt to unionize, all or part of the companies’ workforce, and the resulting effects on production, profitability, and operations; and
New accounting or Securities and Exchange Commission or New York Stock Exchange requirements, or new interpretations or application of existing requirements.

Any forward-looking statement speaks only as of the date on which such statement is made. New factors emerge from time to time and it is not possible for management to predict all such factors, nor can it assess the impact of any such factor on the business or the extent to which any factor, or combination of factors, may cause results to differ materially from those contained in any forward-looking statement.

EXECUTIVE OVERVIEW

Second Quarter 2010 Financial Results

A summary of net income attributable to IDACORP, Inc. and earnings per diluted share for the three and six months ended June 30, 2010 and 2009 is as follows:

	Three months ended				Six months ended
	June 30,				June 30,
	2010		2009		2010		2009
Net income attributable to IDACORP, Inc.	$	39,209	$	27,475	$	55,272	$	46,359
Average outstanding shares – diluted (000’s)		48,048		46,977		47,966		46,927
Earnings per diluted share	$	0.82	$	0.58	$	1.15	$	0.99

The following table presents a reconciliation of net income attributable to IDACORP, Inc. for the period of three and six months ended June 30, 2009 to June 30, 2010 (items are in millions and are before tax unless otherwise noted):

			Three months				Six months
			ended				ended
Net income attributable to IDACORP, Inc. - June 30, 2009					$	27.5			$	46.4
Change in Idaho Power net income before taxes:
	Rate and other regulatory changes, including power cost and
		fixed cost adjustment mechanisms	$	(0.2)			$	8.8
	Reduced sales volumes			(5.6)				(12.4)
	Oregon 2007 excess power cost deferral recorded in 2009			(6.4)				(6.4)
	Increased depreciation expense			(1.9)				(4.5)
	Decreased life insurance gains			(0.5)				(3.8)
	Change in earnings at BCC			2.6				(0.3)
	Other			2.0				-
Additional accumulated deferred investment tax credit (ADITC)
	amortization			(4.5)				-
Decrease in income tax expense excluding additional ADITC
	amortization			27.0				30.0
Total increase in Idaho Power net income						12.5				11.4
Other net decreases, net of tax						(0.8)				(2.5)
	Net income attributable to IDACORP, Inc. - June 30, 2010				$	39.2			$	55.3

A decrease in the estimated annual effective tax rate, primarily resulting from a tax accounting method change for repair-related expenditures on utility assets for the 2009 tax year, significantly impacted IDACORP’s and Idaho Power’s results for the second quarter of 2010. For the quarter ended June 30, 2010, Idaho Power recorded an estimated net tax benefit of $25.2 million related to the cumulative effect of the method change (tax years 1999 through 2009) and has included an annual deduction estimate in its 2010 income tax provision, which resulted in a $3.6 million net tax benefit. Idaho Power also increased its current liability for uncertain tax positions by $10.9 million.

Based on its current estimates, Idaho Power believes its return on equity in the Idaho retail jurisdiction will exceed 9.5 percent on year-end equity and does not expect the need to amortize additional ADITC for 2010 as allowed under a provision of the 2009 settlement agreement with the IPUC. The agreement allows an additional amortization of up to $25 million of ADITC only if Idaho Power’s actual rate of return on year-end equity is below 9.5 percent. As a result, Idaho Power reversed the $4.5 million of ADITC amortization recorded in the first quarter of 2010. The reversal of ADITC in the second quarter of 2010 enables Idaho Power to carry over the credit to future periods, making them available to benefit customers or shareholders in the future.

Idaho Power’s operating income decreased $13 million for the quarter and $14 million for the year-to-date compared to the same periods of 2009, primarily due to reduced sales volumes. Sales volumes were down four percent for the quarter and five percent year-to-date due to mild, wet weather, economic factors, and energy conservation. Mild weather reduced electricity demand for heating and cooling, and wet weather decreased electricity demand for the operation of irrigation equipment, decreasing sales to irrigation customers 15 percent for the quarter and year-to-date. Economic conditions in Idaho Power’s service area remained weak and Idaho Power attributes a portion of the reduced sales volumes to these conditions. While there are some indicators of improvement, overall economic conditions in the service area have not recovered from the recession. For instance, unemployment rates are still high relative to historic unemployment levels and customer growth was modest during the second quarter of 2010. Volume decreases were partially offset by the fixed cost adjustment (FCA) mechanism and lower power supply costs.

Idaho Power's operating income also decreased due to a $6.4 million Oregon excess power cost recovery recorded in 2009 that did not recur in 2010. Depreciation expense increased primarily due to the conversion to Advanced Metering Infrastructure (AMI). Idaho Power has accelerated depreciation expense for non-AMI meters and is collecting an offsetting amount in revenues.

Other income was impacted by lower life insurance benefits as gains recorded in 2009 that did not recur in 2010. Earnings at BCC increased $3 million for the quarter and remained nearly the same year-to-date due to a change in coal pricing and an increase in coal deliveries.

Earnings at IDACORP’s non-regulated subsidiaries and the holding company declined $0.8 million for the quarter and $2.5 million year-to-date due to the effects of intra-period tax allocations. IDACORP estimates its consolidated group annual effective income tax rate at the holding company in accordance with interim reporting requirements. The estimated annual rate was used in determining income tax expense for the quarter and resulted in an intra-period allocation of expense.

Regulatory Matters

Idaho Power has a number of pending or recently completed regulatory filings and resulting orders, including the following:

Idaho Settlement Agreement: In January 2010, the IPUC approved a settlement agreement among Idaho Power, several of Idaho Power’s customers, the IPUC Staff, and others with respect to rates for 2009 through 2011. The agreement contains four important elements: (1) a general rate freeze until January 1, 2012, with some exceptions; (2) a specified distribution of the expected 2010 PCA decrease to directly reduce customer rates, providing some general rate relief to Idaho Power and resetting base level power supply costs for the PCA going forward; (3) use of investment tax credits to get to a 9.5 percent return on equity in the Idaho jurisdiction; and (4) an equal sharing of any Idaho earnings exceeding the authorized return on equity of 10.5 percent.

Idaho 2010 PCA Filing: On May 28, 2010, the IPUC issued an order approving a $146.9 million decrease in the 2010 PCA, along with a base rate increase of $88.7 million, both effective June 1, 2010. The net effect of these two rate adjustments is an overall decrease in customer rates of $58.2 million, or 6.49 percent.

Other Idaho 2010 Filings: On May 28, 2010, Idaho Power received the following rate orders from the IPUC, each with an effective date of June 1, 2010:

• Fixed Cost Adjustment: The IPUC approved Idaho Power's March 2010 request to implement an an estimated $3.6 million annual increase over current rates to residential and small general service customers for electric service from June 1, 2010 through May 31, 2011.

• Pension: The IPUC approved Idaho Power’s March 2010 request to increase rates by 0.77 percent, or $5.4 million, for recovery of Idaho Power’s pension plan contribution, and Idaho Power began amortizing the related costs in June 2010. In its order, the IPUC stated that the allowance of recovery of the 2009 pension plan contribution does not guarantee that the IPUC will similarly approve future recovery of pension contributions without further justification.

• Advanced Metering Infrastructure: The IPUC approved Idaho Power’s March 2010 application requesting authority to implement a 0.41 percent average increase (representing a 0.33 percent overall increase), or an increase of $2.4 million, in rates for identified customer classes to recover costs relating to the AMI project.

Oregon 2009 General Rate Case: On February 24, 2010, the OPUC approved a $5 million, or 15.4 percent, increase in base rates. The new rates were effective March 1, 2010, and are based on a return on equity of 10.175 percent and an overall rate of return of 8.061 percent.

Oregon Power Cost Recovery Mechanisms: On May 24, 2010, the OPUC approved the 2010 annual power cost update (APCU) rate adjustment for Oregon customers. The 2010 APCU resulted in a $2.2 million, or 5.53 percent, annual increase in Oregon rates, effective June 1, 2010.

Annual OATT Update: On June 1, 2010, Idaho Power posted its annual Draft Informational Filing (DIF) for its open access transmission tariff (OATT). The new draft rate is $19.60 per kW/yr, an increase of 23.8 percent over the present OATT rate of $15.83 per kW/yr.

For a more complete discussion of regulatory proceedings, refer to Note 3 -”Regulatory Matters” to the condensed consolidated financial statements included in this report and “REGULATORY MATTERS” below.

Liquidity

IDACORP and Idaho Power expect to continue financing capital requirements with a combination of internally generated funds and externally financed capital. In the second quarter of 2010, Idaho Power received approvals from its state regulatory commissions for the issuance of up to an aggregate of $500 million of additional first mortgage bonds and debt securities. On May 12, 2010, Idaho Power filed a shelf registration statement with the SEC for the sale of up to $500 million of first mortgage bonds and debt securities. The SEC declared the registration statement effective on May 25, 2010. To facilitate the issuance of the securities, on June 17, 2010, Idaho Power entered into a selling agency agreement in connection with the potential issuance and sale of up to $500 million aggregate principal amount of first mortgage bonds under Idaho Power’s Indenture of Mortgage and Deed of Trust, dated as of October 1, 1937, as amended and supplemented.

Capital Requirements: Idaho Power is in a period of significant infrastructure development and has several major projects in development. The most significant projects are summarized here and are discussed further in “LIQUIDITY AND CAPITAL RESOURCES – Capital Requirements.”

Langley Gulch Power Plant: Langley Gulch is a natural gas-fired combined cycle combustion turbine (CCCT) generating plant with a summer nameplate capacity of approximately 300 megawatts (MWs) and a winter capacity of approximately 330 MW. Construction of the plant is underway. The total cost estimate for the project including allowance for funds used during construction (AFUDC) is $427 million, $102 million of which Idaho Power has incurred through June 30, 2010.

Transmission Projects: Idaho Power and PacifiCorp are pursuing the joint development of the Boardman-Hemingway Line, a proposed 500-kiloVolt (kV) line between a station near Boardman, Oregon, and the Hemingway station, near Boise, Idaho. Idaho Power estimates total construction costs of $600 million and expects its share of the project to be between 30 and 50 percent. Idaho Power and PacifiCorp are also pursuing the joint development of Gateway West, a project to build transmission lines between Windstar, a station located near Douglas, Wyoming, and the Hemingway station. The current estimated cost for Idaho Power’s share of the project is between $300 million and $500 million.
Transmission Equipment Purchase and Sale and Joint Ownership and Operating Agreements: On April 30, 2010, Idaho Power entered into a Joint Purchase and Sale Agreement with PacifiCorp, pursuant to which Idaho Power agreed to sell to PacifiCorp a 59.0 percent interest in the 500-kV portions of transmission-related and interconnection equipment located at Idaho Power’s Hemingway station near Boise, Idaho; and PacifiCorp agreed to sell to Idaho Power a 20.8 percent interest in the 345-kV portions of transmission-related and interconnection equipment located at PacifiCorp’s Populus station. On May 3, 2010, the closing date of the purchase and sale, Idaho Power and PacifiCorp also entered into two Joint Ownership and Operating Agreements for the Hemingway and Populus stations, which set forth terms pertaining to the construction, joint ownership, and operation of transmission and interconnection facilities at those stations.
AMI / Smart Grid (American Recovery and Reinvestment Act of 2009 (ARRA)): Under the ARRA, in April 2010 Idaho Power finalized the grant of $47 million from the Department of Energy (DOE). This grant will match a $47 million investment by Idaho Power in smart grid AMI technology. Billings on this reimbursement contract began in May 2010 and are expected to occur monthly over the estimated three-year term of the grant.

Other Issues

Water Management Issues: Power generation at the Idaho Power hydroelectric power plants on the Snake River depends on the state water rights held by Idaho Power and the long-term sustainability of the Snake River, tributary spring flows, and the Eastern Snake Plain Aquifer (ESPA). Idaho Power continues to participate in water management issues in Idaho that may affect those water rights and resources. For a further discussion of water management issues see “LEGAL MATTERS – Snake River Basin Water Rights.”

Environmental Matters: Long-term climate change could significantly affect Idaho Power’s business, and climate change regulations are expected to have major implications for Idaho Power and the energy industry. Idaho Power has established guidelines with goals to reduce the carbon dioxide (CO₂) emission intensity of its utility operations, intended to further prepare Idaho Power for potential legislative and/or regulatory restrictions on greenhouse gas (GHG) emissions while minimizing the costs of complying with such restrictions on Idaho Power’s customers. Idaho Power’s thermal facilities are subject to federal and/or state-promulgated (1) ambient air quality standards, including those for ozone and fine particulate matter, (2) laws and regulations limiting mercury emissions, (3) regional haze – best available retrofit technology requirements, and (4) new source review and performance standards. Idaho Power’s environmental compliance costs will continue to be significant for the foreseeable future and could increase substantially, particularly in light of proposed additional regulation at the federal and state levels. These issues are discussed in more detail in “ENVIRONMENTAL ISSUES” below.

Boardman Coal Plant: On April 2, 2010, Portland General Electric Company (PGE) submitted a petition to the Oregon Environmental Quality Commission (OEQC) seeking rule revisions to allow the utility to meet new environmental standards by closing the Boardman power plant in 2020. This petition was rejected by the OEQC on June 17, 2010 at the recommendation of the Oregon Department of Environmental Quality (ODEQ). On June 28, 2010, the ODEQ proposed new Boardman early closure options to the OEQC. One of the options calls for the closure of the plant as early as 2015. Idaho Power is a ten percent owner of the Boardman plant, representing 64 MW of nameplate capacity. Idaho Power is evaluating the current proposals and discussing with PGE the options and the advisability of closing the Boardman plant. At June 30, 2010, Idaho Power’s net book value in the Boardman plant was approximately $20 million with annual depreciation of approximately $1.2 million.

Health Care Acts: The Patient Protection and Affordable Care Act and the related Health Care and Education Reconciliation Act were enacted in March 2010. The enactment of the legislation required Idaho Power to record a $0.9 million charge to income tax expense in the first quarter of 2010. Idaho Power is evaluating what other impacts, if any, the health care legislation may have on its and IDACORP’s future results of operations, cash flows, or financial positions, and if benefit plan structure changes may be necessary. For a more complete discussion of the health care legislation, refer to Note 10 - “Benefit Plans” to the condensed consolidated financial statements included in this report.

Pension Funding Legislation: In June 2010, the Preservation of Access to Care for Medicare Beneficiaries and Pension Relief Act of 2010 was signed into law. Under the Relief Act, Idaho Power could, for any two plan years between 2008 and 2011, elect to amortize certain pension funding shortfalls over a 15 year period or pay interest only on the applicable plan years’ funding shortfall for two plan years followed by amortization of the shortfall for seven years. Were Idaho Power to make one of these elections, it would reduce near-term required contributions to the plan by spreading them over a longer time period. Idaho Power continues to evaluate the new legislation and its potential impacts, but has not yet determined which, if any, of these options it will choose.

Key Operating and Financial Metrics

IDACORP’s and Idaho Power’s outlook for 2010 full year metrics is set forth below:

	2010 Estimates
	Current	Previous
Idaho Power Operation & Maintenance Expense (millions)	No change	$295-$305
Idaho Power Capital Expenditures (millions)⁽¹⁾	No change	$355-$365
Idaho Power Hydroelectric Generation (million MWh)⁽²⁾	7.0-8.0	6.5-8.5
Non-regulated subsidiary earnings and holding company expenses (millions)⁽³⁾	No change	$0-$3.0

⁽¹⁾The range for capital expenditures includes amounts for the Langley Gulch power plant, the Hemingway-Bowmont transmission line, the Hemingway station, and expenditures for the siting and permitting of major transmission expansions for the Boardman to Hemingway and Gateway West transmission projects. The range does not include $47 million awarded to Idaho Power from the Department of Energy through the American Recovery and Reinvestment Act of 2009.
⁽²⁾The range of estimated hydroelectric generation has been revised to reflect actual hydroelectric generation through June and estimated ranges of hydroelectric generation for the remainder of the year.
⁽³⁾For the six months ended June 30, 2010, non-regulated earnings and holding company expenses resulted in a net loss of $2.5 million, primarily due to the impact of intra-period tax allocation at the holding company. IDACORP expects that combined earnings and holding company expenses will be in the range of breakeven to a positive $3.0 million by year end.

RESULTS OF OPERATIONS

This section of the MD&A takes a closer look at the significant factors that affected IDACORP’s and Idaho Power’s earnings during the three and six months ended June 30, 2010. In this analysis, the results for 2010 are compared to the same periods in 2009.

The following table presents net income (losses) for IDACORP and its subsidiaries for the three and six months ended June 30, 2010 and 2009:

		Three months ended				Six months ended
		June 30,				June 30,
		2010		2009		2010		2009
Idaho Power – Utility operations		$	38,828	$	26,326	$	57,049	$	45,610
IDACORP Financial Services			102		188		63		329
Ida-West Energy			1,010		1,384		1,188		1,572
IDACORP Energy			(45)		(29)		152		(48)
Holding company			(686)		(394)		(3,180)		(1,104)
	Net income attributable to IDACORP, Inc.	$	39,209	$	27,475	$	55,272	$	46,359
Average common shares outstanding (diluted, in 000’s)			48,048		46,977		47,966		46,927
Earnings per diluted share		$	0.82	$	0.58	$	1.15	$	0.99

Utility Operations

The table below presents Idaho Power’s energy sales and supply (in thousands of MWhs) for the three and six months ended June 30, 2010 and 2009:

		Three months ended		Six months ended
		June 30,		June 30,
		2010	2009	2010	2009
General business sales		3,127	3,256	6,236	6,535
Off-system sales		601	1,095	1,367	1,672
	Total energy sales	3,728	4,351	7,603	8,207
Hydroelectric generation		2,298	2,976	4,200	4,561
Coal generation		1,154	1,108	3,027	3,065
Natural gas and other generation		18	13	21	22
	Total system generation	3,470	4,097	7,248	7,648
Purchased power		579	539	974	1,200
Line losses		(321)	(285)	(619)	(641)
	Total energy supply	3,728	4,351	7,603	8,207

Because of its reliance on hydroelectric generation, Idaho Power’s generation operations can be significantly affected by water conditions. The availability of hydroelectric power depends on the amount of snow pack in the mountains upstream of Idaho Power’s hydroelectric facilities, reservoir storage, springtime snow pack run-off, river base flows, spring flows, rainfall, amount and timing of water leases, and other weather and stream flow management considerations. During low water years, when stream flows into Idaho Power’s hydroelectric projects are reduced and reservoir storage is low, Idaho Power’s hydroelectric generation is generally reduced. This results in less generation from Idaho Power’s resource portfolio available for off-system sales and, generally, 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. While the cost of purchased power is typically higher than the cost of hydroelectric generation, the incremental cost is included in regulatory mechanisms that allow Idaho Power to recover most of these costs.

For the three months ended June 30, 2010, hydroelectric generation comprised 66 percent of Idaho Power’s total system generation and 57 percent of its total energy supply. For the three months ended June 30, 2010, Idaho Power’s hydroelectric generation decreased 23 percent over the same period of 2009 due to a significantly lower than average snowpack and resulting spring runoff. Snowpack was 69 percent of average in 2010 compared to 94 percent of average in 2009. Based on current reservoir levels, forecasted stream flow, and other conditions relevant to its estimate of hydroelectric generation capacity, Idaho Power expects to generate between 7.0 and 8.0 million MWh from its hydroelectric facilities in 2010, compared to 8.1 million MWh in 2009. Idaho Power’s modeled median annual hydroelectric generation is 8.6 million MWh, based on hydrologic conditions for the period 1928 through 2009 and adjusted to reflect the current level of water resource development.

Idaho Power’s system is dual peaking, with the larger peak demand occurring in the summer. The highest summer peak demand of 3,214 MW was set on June 30, 2008, and the highest winter peak demand of 2,527 MW was set on December 10, 2009. During these and other similar heavy load periods Idaho Power’s system is fully committed to serve loads and meet required operating reserves.

General business revenue: The following tables present Idaho Power’s general business revenues, MWh sales, number of customers, and Boise, Idaho weather conditions for the three and six months ended June 30, 2010 and 2009:

			Three months ended				Six months ended
			June 30,				June 30,
			2010		2009		2010		2009
Revenue
	Residential		$	83,970	$	77,757	$	195,565	$	184,204
	Commercial			55,593		53,415		113,524		104,957
	Industrial			33,950		33,307		70,068		64,352
	Irrigation			33,111		36,106		33,787		36,676
	Deferred revenue related to Hells
		Canyon relicensing AFUDC		(2,347)		(2,370)		(4,922)		(4,047)
		Total	$	204,277	$	198,215	$	408,022	$	386,142
MWh
	Residential			1,043		1,048		2,442		2,582
	Commercial			879		894		1,811		1,851
	Industrial			729		755		1,500		1,536
	Irrigation			476		559		483		566
		Total		3,127		3,256		6,236		6,535
Customers (average)
	Residential			407,145		404,590		406,947		404,499
	Commercial			64,326		64,113		64,301		64,097
	Industrial			126		126		127		125
	Irrigation			18,637		18,800		18,619		18,666
		Total		490,234		487,629		489,994		487,387
Customers (period end)
	Residential							407,310		404,804
	Commercial							64,371		64,115
	Industrial							124		127
	Irrigation							18,665		18,859
		Total						490,470		487,905
Heating degree-days⁽¹⁾				885		641		3,041		3,173
Cooling degree-days⁽²⁾				107		208		107		208
Precipitation (inches)⁽³⁾				4.69		3.24		8.62		5.57
⁽¹⁾Heating and cooling degree-days are common measures used in the utility industry to analyze the demand for electricity. They indicate when a customer would likely use electricity for heating and air conditioning. A degree-day measures how much the average of the daily high and low 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. Normal heating degree-days for the quarter and year-date are 767 and 3,341 degree days, respectively.
⁽²⁾Normal cooling degree-days for the quarter and year-to-date are both 156.
⁽³⁾Normal precipitation for the quarter and year-to-date is 3.31 and 7.00 inches, respectively.

As part of its February 1, 2009 general rate case order, the IPUC allowed Idaho Power to recover AFUDC for the Hells Canyon Complex (HCC) relicensing asset even though the relicensing process is not yet complete and the relicensing asset has not been placed in service. Idaho Power expects to collect approximately $10.6 million annually, but will defer revenue recognition of the amounts collected until the license is issued and the relicensing asset is placed in service. This deferral offset revenues by approximately $2 million for the second quarter of 2010 and $5 million for the year-to-date.

General business revenue increased $6 million for the second quarter of 2010 and $22 million year-to-date compared to the same periods in 2009. This increase is primarily attributable to the effects of rate changes and was partially offset by a reduction in customer usage due largely to weather conditions that decreased power demand.

Rates: Rate changes positively impacted general business revenue by $14 million for the quarter and $41 million year-to-date. Base rates changes increased revenues $13 million for the quarter and $22 million year-to-date. PCA rates changes had a minimal effect on revenues for the quarter, but increased revenues $19 million for the year-to-date. The following table presents notable rate increases and decreases, shown on an annualized basis, that affected the periods:

		Percentage		Annualized
	Effective	Rate Increase		$ Impact
Description	Date	(Decrease)		(millions)
2008 Idaho general rate case	2/01/2009	3.10%	$	21
2008 Idaho general rate case	3/19/2009	0.90%		6
2009 Idaho PCA	6/01/2009	10.20%		84
2009 Idaho AMI	6/01/2009	1.80%		11
2009 Oregon general rate case settlement	3/01/2010	15.40%		5
2010 Idaho settlement	6/01/2010	9.89%		89
2010 Idaho PCA	6/01/2010	(16.35%)		(147)
2010 Idaho Pension Expense Recovery	6/01/2010	0.77%		5
2010 Idaho AMI	6/01/2010	0.41%		2
2010 Idaho FCA	6/01/2010	0.90%		4
2010 Oregon Power Cost Update	6/01/2010	5.53%		2

As many of the rate changes that positively impacted the results for the second quarter of 2010 were effective beginning in June, and thus were effective for only one month of the second quarter, Idaho Power expects the favorable rate changes to have a greater positive impact during subsequent periods.

Customers: Slow growth in customer count contributed to a minimal increase in general business revenue for the quarter and a $2 million increase year-to-date.
Usage: Changes in usage reduced general business revenue $8 million for the quarter and $21 million for the year-to-date due primarily to weather and, to a lesser extent, energy conservation and economic factors. Sales to irrigation customers declined 15 percent for the quarter and for the year-to-date due to increased precipitation and milder temperatures. Increased precipitation levels during the agricultural growing season, which includes the second quarter, reduce electricity sales to irrigators due to reduced use of electricity to operate irrigation pumps. Mild temperatures contributed to the decreased usage by residential, commercial, and industrial customers. Year-to-date, total MWh sales, excluding irrigation customers, declined by 216 thousand MWh, or four percent, relative to the same period in 2009. In addition, economic conditions in Idaho Power's service area remained weak, including a continued high unemployment rate in the area. Idaho Power believes the decline in total MWh sales is due in part to the continued weakness of the economy in its service area. A slow economic recovery could result in continued low demand.

Off-system sales: Off-system sales consist primarily of long-term sales contracts and opportunity sales of surplus system energy. The following table presents Idaho Power’s off-system sales for the three and six months ended June 30, 2010 and 2009:

	Three months ended				Six months ended
	June 30,				June 30,
	2010		2009		2010		2009
Revenue	$	17,769	$	26,667	$	52,175	$	55,198
MWh sold		601		1,095		1,367		1,672
Revenue per MWh	$	29.57	$	24.35	$	38.17	$	33.01

Off-system sales revenue decreased $9 million, or 33 percent, for the second quarter of 2010 and $3 million, or six percent, year-to-date compared to the same periods of 2009 due to less favorable hydroelectric generating conditions, which reduced surplus power available for sale.

Other revenues: The table below presents the components of other revenues for the three and six months ended June 30, 2010 and 2009:

		Three months ended				Six months ended
		June 30,				June 30,
		2010		2009		2010		2009
Transmission services and property rental		$	9,979	$	8,963	$	19,254	$	16,476
Energy efficiency			8,765		8,673		13,799		12,731
	Total	$	18,744	$	17,636	$	33,053	$	29,207

The increase in transmission services and property rental reflects new transmission rates implemented in October 2009.

Energy efficiency activities are funded through a rider mechanism on customer bills. Energy efficiency program expenditures are reported as an operating expense with an equal amount of revenues recorded in other revenues, resulting in no net impact on earnings. The cumulative variance between expenditures and amounts collected through the rider is recorded as a regulatory asset or liability pending future collection from or obligation to customers. A liability balance indicates that Idaho Power has collected more than it has spent and an asset balance indicates that Idaho Power has spent more than it has collected. For the year-to-date 2010, Idaho Power has increased its energy efficiency program expenses and matching revenues $1 million, and on June 30, 2010, Idaho Power’s rider balance was a regulatory asset of $9 million and is expected to grow to $17 million by year end due to continued planned expenditures on energy efficiency projects.

Purchased power: The following table presents Idaho Power’s purchased power expenses and volumes for the three and six months ended June 30, 2010 and 2009:

	Three months ended				Six months ended
	June 30,				June 30,
	2010		2009		2010		2009
Purchased power expense	$	30,349	$	26,867	$	51,523	$	60,568
MWh purchased		579		539		974		1,200
Cost per MWh purchased	$	52.42	$	49.85	$	52.90	$	50.47

Purchased power expense increased $3 million, or 13 percent, for the quarter due to less favorable hydroelectric generating conditions and decreased $9 million, or 15 percent, year-to-date compared to the same periods in 2009, due to lower system loads and greater reliance on financial hedges to mitigate potential changes in forecasted hydrologic conditions.

Fuel expense: The following table presents Idaho Power’s fuel expenses and generation at its thermal generating plants for the three and six months ended June 30, 2010 and 2009:

			Three months ended				Six months ended
			June 30,				June 30,
			2010		2009		2010		2009
Expense
	Coal		$	25,766	$	22,979	$	61,830	$	60,774
	Natural gas and other			1,792		1,496		2,914		2,834
		Total fuel expense	$	27,558	$	24,475	$	64,744	$	63,608
MWh generated
	Coal			1,154		1,108		3,027		3,065
	Natural gas and other			18		13		21		22
		Total MWh generated		1,172		1,121		3,048		3,087
Cost per MWh
	Coal		$	22.33	$	20.74	$	20.43	$	19.83
	Natural gas and other			99.56		115.08		138.76		128.82
	Weighted average, all sources			23.51		21.83		21.24		20.61

Fuel expense increased $3 million, or 13 percent, for the quarter and $1 million, or two percent year-to-date as compared to the same periods in 2009. The Bridger plant increased its generation due to a shorter planned maintenance outage and had fewer economic shutdowns during the second quarter of 2010 than in the same period in 2009 due to improved market prices. Partially offsetting this increase is a reduction in generation at the Valmy plant due to major planned maintenance in 2010 that did not occur in 2009.

PCA: PCA expense represents the effects of the Idaho and Oregon power supply cost adjustment mechanisms. The following table presents the components of the PCA for the three and six months ended June 30, 2010 and 2009:

		Three months ended				Six months ended
		June 30,				June 30,
		2010		2009		2010		2009
Idaho power supply cost accrued (deferred)		$	3,444	$	8,402	$	23,282	$	(2,005)
Oregon power supply cost accrued (deferred)			549		(6,358)		593		(6,358)
Amortization of prior year authorized balances			24,078		24,718		52,520		50,984
	Total power cost adjustment	$	28,071	$	26,762	$	76,395	$	42,621

In 2010 and in the second quarter of 2009, power supply costs were below the amounts estimated in the annual PCA forecasts, resulting in a charge to expense (accrual). For the first six months of 2009, power supply costs were above the PCA forecast, resulting in a credit to expense (deferral). In addition, in the second quarter of 2009, Idaho Power recorded the effect of an order from the OPUC that allows Idaho Power to defer for future recovery $6.4 million of costs incurred in prior years.

Other operations and maintenance expenses: Other operations and maintenance expense remained nearly the same for the quarter and increased $4 million year-to-date as compared to the same periods in 2009, primarily due to a $1.7 million increase in thermal O&M due to the timing and scope of maintenance outages and a $2 million increase in transmission O&M due to increased maintenance at stations.

Income Taxes

IDACORP’s and Idaho Power’s income tax expense for the three and six months ended June 30, 2010 decreased substantially relative to the same periods in 2010, primarily as a result of the tax accounting method change for repair-related expenditures on utility assets for the 2009 tax year. For information relating to IDACORP’s and

Idaho Power’s computation of the estimated annual effective tax rate, see Note 2 – “Income Taxes” to the condensed consolidated financial statements included in this report.

An analysis of income tax expense for the three and six months ended June 30, 2010 and 2009 is as follows:

		IDACORP				Idaho Power
		2010		2009		2010		2009
Three months ended June 30,
Income tax provision		$	4,046	$	5,175	$	5,859	$	7,675
ADITC amortization reversal			4,512		-		4,512		-
Accounting method change			(25,187)		-		(25,187)		-
	Income tax (benefit) expense	$	(16,629)	$	5,175	$	(14,816)	$	7,675

Effective tax rate			(73.6)%		15.8%		(61.7)%		22.6%

Six months ended June 30,
Income tax provision		$	8,960	$	11,970	$	11,774	$	17,447
Accounting method change			(25,187)		-		(25,187)		-
Medicare Part D subsidy			903		-		903		-
	Income tax (benefit) expense	$	(15,324)	$	11,970	$	(12,510)	$	17,447

Effective tax rate			(38.4)%		20.5%		(28.1)%		27.7%

The decrease in the 2010 estimated annual effective tax rates from 2009 is primarily due to Idaho Power’s tax accounting method change for repair-related expenditures, and lower pre-tax earnings at IDACORP and Idaho Power, partially offset by a charge related to the federal health care legislation enacted in the first quarter of 2010. Regulatory flow-through tax adjustments at Idaho Power and tax credits at IFS for the six months ended June 30, 2010 were comparable to the same period in 2009.

Based on Idaho Power’s current estimate of 2010 return on equity, Idaho Power does not expect to need to amortize additional ADITC for 2010. Accordingly, the $4.5 million of additional ADITC amortization recorded in the first quarter of 2010 was reversed in the second quarter of 2010. For further information regarding ADITC amortization, see “Idaho Settlement Agreement” in Note 3 – “Regulatory Matters” to the condensed consolidated financial statements included in this report.

Tax Accounting Method Change: In June 2010, Idaho Power completed its evaluation of a tax accounting method change for its 2009 tax year that would allow a current income tax deduction for repair-related expenditures on its utility assets that are currently capitalized for financial reporting and tax purposes. Idaho Power intends to make this method change following the automatic consent procedures with the filing of IDACORP’s 2009 consolidated federal income tax return in September 2010. For the quarter ended June 30, 2010, Idaho Power recorded an estimated net tax benefit of $25.2 million related to the cumulative method change adjustment (tax years 1999 through 2009) and has included an annual deduction estimate in its 2010 income tax provision, which resulted in a $3.6 million net tax benefit. Idaho Power’s prescribed regulatory accounting treatment requires immediate income recognition for temporary tax differences of this type. A regulatory asset is established to reflect Idaho Power’s ability to recover increased income tax expense when such temporary differences reverse. Idaho Power expects to recognize cash tax benefits associated with the method change by the end of 2010 through offsets to current estimated tax payments and direct tax refunds.

In conjunction with recording the estimated tax benefit for the method change, Idaho Power also increased its current liability for uncertain tax positions by $10.9 million. If recognized, the $10.9 million balance of unrecognized tax benefits would affect the effective tax rate. The tax method is currently being audited under IDACORP’s 2009 Compliance Assurance Process (CAP) examination (discussed below) and, on a national level, aspects of the method related to electric utility transmission and distribution property are the subject of an Internal Revenue Service (IRS) Industry Issue Resolution program.

Status of Audit Proceedings: In May 2009, IDACORP formally entered the IRS CAP program for its 2009 tax year. The CAP program provides for IRS examination throughout the year. The 2009 examination is expected to be completed in 2010. In January 2010, IDACORP was accepted into CAP for its 2010 tax year. IDACORP and Idaho Power are unable to predict the outcome of these examinations.

Specifically within the 2009 CAP examination, the IRS began its audit of Idaho Power’s current method of uniform capitalization. In September 2009, the IRS issued Industry Director Directive #5, which discusses the IRS’s compliance priorities and audit techniques related to the allocation of mixed service costs in the uniform capitalization methods of electric utilities. Initial estimates indicate the potential income and cash benefits associated with settlement of this matter to be in excess of the repairs method change recorded in the second quarter. Idaho Power expects that the examination of this method will be completed during the third quarter of 2010; however, the timing of final settlement with the IRS, and thereby the recognition of the income and cash impacts, has yet to be determined. Resolution of this matter would also result in a $1.1 million decrease to Idaho Power’s unrecognized tax benefits for its 2009 uniform capitalization deduction.

Benefit Plan Related Legislation

Health Care Acts: The Patient Protection and Affordable Care Act and the Health Care and Education Reconciliation Act were enacted in March 2010. As a result, Idaho Power incurred a charge of $0.9 million in the first quarter of 2010 and is evaluating what other impacts, if any, the health care legislation may have on its and IDACORP’s future results of operations, cash flows, or financial positions, and if benefit plan structure changes may be necessary. In particular, Idaho Power is monitoring available guidance regarding a tax to be imposed on certain plans beginning in 2018, whereby premiums paid over a prescribed threshold will incur a non-deductible 40 percent excise tax. See Note 10 - “Benefit Plans” to the condensed consolidated financial statements included in this report for additional information relating to Idaho Power’s health and welfare plans and post-retirement benefit obligations, and Note 2 - “Income Taxes” to the condensed consolidated financial statements included in this report for a discussion of the tax impacts of the health care acts.

LIQUIDITY AND CAPITAL RESOURCES:

Overall Liquidity

IDACORP’s and Idaho Power’s access to long-term and short-term debt markets, including their respective credit facilities, helps provide necessary liquidity to support Idaho Power’s operating activities. Significant uses of cash flows from Idaho Power’s utility operations include the purchase of electricity, the purchase of fuel for power generation, and payment of other operating expenses, taxes, and interest, with any excess amount being available for other corporate uses such as capital expenditures and the payment of dividends.

Idaho Power utilizes operating and capital budgets to control operating costs and optimize capital expenditures. Idaho Power seeks to recover its operating costs and earn a return on its capital expenditures through rates. Idaho Power has continuing significant commitments for capital expenditures for construction, improvement, and maintenance of utility facilities. Currently, Idaho Power is experiencing a cycle of heavy infrastructure investment, adding capacity to its baseload generation, transmission system, and distribution facilities in an effort to ensure an adequate supply of electricity, to provide service to new customers, and to maintain system reliability. See “Capital Requirements” below for a discussion of certain of those projects. As Idaho Power’s operating cash flows usually do not fully support the amount required for utility capital expenditures, particularly during periods of heavy infrastructure development as is presently occurring, Idaho Power from time to time needs to access capital markets in order to fund these needs as well as to fund maturing debt.

Operating Cash Flows

IDACORP’s operating cash flows are driven principally by Idaho Power. General business revenues and the costs to supply power to general business customers have the greatest impact on Idaho Power’s operating cash flows, and are subject to risks and uncertainties relating to weather and water conditions, fuel costs and purchased power prices, the ability to collect from customers, and Idaho Power’s ability to obtain rate relief to cover its operating costs and provide a return on investment.

IDACORP’s and Idaho Power’s operating cash inflows for the six months ended June 30, 2010, were $187 million and $167 million, respectively. These amounts were increases of $77 million and $52 million, respectively, compared to the six months ended June 30, 2009. The following are significant items that affected operating cash flows in the first six months of 2010:

An increase of $34 million from reductions in the PCA and the Oregon power cost adjustment mechanism (PCAM) regulatory assets, as Idaho Power deferred $32 million less of excess net power supply costs and collected an additional $2 million of previously deferred costs as compared with the first six months of 2009.
An increase of $22 million from the collection in 2010 of higher 2009 year end customer accounts receivable and unbilled revenue balances, primarily as a result of colder temperatures increasing sales in December 2009 as compared with the prior year.
An increase of $16 million related to payments in 2009 for power purchased in 2008.
An increase of $13 million due to refunds in the first quarter of 2009 made to Idaho Power’s transmission customers upon a final order from the FERC on Idaho Power’s OATT.
Net income for IDACORP and Idaho Power increased by $9 million and $11 million, respectively.
A partially offsetting decrease in cash flows from income taxes, as tax refunds received by IDACORP decreased $8 million and income tax payments made by Idaho Power to its parent in 2010 and refunds received from its parent in 2009 combined for a $34 million decrease for the six months ended June 30, 2010, as compared with the same period last year.

Pension Funding: For at least the period 2011 to 2014, Idaho Power expects to make significant cash contributions to its pension plan and has significant obligations under other postretirement benefit plans. The funded status of the pension and other post-retirement benefit obligations refers to the difference between plan assets and estimated obligation of the plan. The calculation of funding requirements for pension plans requires election of a methodology to determine the actuarial value of assets and the interest rate used to measure the pension liabilities. IDACORP and Idaho Power continuously monitor available and proposed pension funding guidance, and evaluate the potential impact on funding requirements and strategies.

In June 2010, the Preservation of Access to Care for Medicare Beneficiaries and Pension Relief Act of 2010 (Relief Act) was signed into law, which permits employers to choose between two alternative funding options for defined benefit pension plans for any two plan years between 2008 and 2011, either (i) amortizing the funding shortfall over 15 years or (ii) paying interest only on the applicable plan years’ funding shortfall for two plan years followed by amortization of the shortfall for seven years. The legislation does not eliminate Idaho Power’s obligation to fully fund the pension plan. The legislation also outlines penalties in the form of increased pension contributions from an employer that elects one of the funding relief options at the same time the employer (or entities within its ERISA controlled group) awards “excess employee compensation” (generally compensation over $1 million per year paid to an employee), grants “excessive” dividends, or effects specified stock redemptions. Idaho Power continues to evaluate the new legislation and its potential impacts. If one of these alternate funding options is elected, it would reduce near-term required contributions to the plan by spreading them over a longer time period. See Note 10 - “Benefit Plans” to the condensed consolidated financial statements included in this report for additional information relating to Idaho Power’s pension plan funding and post-retirement benefit obligations, and Note 3 - “Regulatory Matters” to the condensed consolidated financial statements included in this report for a discussion of Idaho Power’s recovery of pension plan contributions through the ratemaking process.

Investing Cash Flows

Cash flows from investing activities consist primarily of capital expenditures related to new construction and improvements to Idaho Power’s distribution, transmission, and generation facilities. IDACORP’s and Idaho Power’s investing cash outflows were $149 million and $143 million, respectively, for the six months ended June 30, 2010. These amounts were an increase in outflows of $52 million and $44 million, respectively, compared to the six months ended June 30, 2009. Investing cash outflows for 2010 were primarily for construction of utility infrastructure needed to address Idaho Power’s customer growth, peak demand growth, and aging plant and equipment. Construction expenditures were partially offset by proceeds from the sale of $19 million of transmission-related assets to PacifiCorp.

Financing Cash Flows

Financing activities provide supplemental cash for both day-to-day operations and capital requirements as needed. Idaho Power funds liquidity needs for capital investment, working capital, energy and price hedging, and other financial commitments through cash flows from continuing operations, public debt offerings, commercial paper markets, and credit facilities.

IDACORP’s and Idaho Power’s financing cash outflows for the six months ended June 30, 2010, were $62 million and $20 million, respectively. These amounts were an increase in outflows of $55 million and $13 million, respectively, compared to the six months ended June 30, 2009. The financing cash outflows for 2010 were primarily for dividends paid by IDACORP and Idaho Power of $29 million and for the net repayment by IDACORP of $36 million of commercial paper. In addition, Idaho Power received a capital contribution of $10 million from IDACORP.

Idaho Power has $120 million of first mortgage bonds that mature in the first quarter of 2011. Idaho Power is evaluating various financing alternatives for the repayment of this debt.

Shelf Registrations: IDACORP has approximately $574 million remaining on its shelf registration statement that can be used for the issuance of debt securities and common stock. IDACORP has a sales agency agreement with BNY Mellon Capital Markets, LLC pursuant to which it may sell common stock from time to time in at-the-market offerings. As of June 30, 2010, there were 2.1 million shares remaining available to be sold under the sales agency agreement.

In the second quarter of 2010, Idaho Power received approval from the IPUC, the OPUC, and the Public Service Commission of Wyoming for the issuance of up to $500 million in aggregate principal amount of one or more series of first mortgage bonds and unsecured debt securities. The order from the IPUC approved the issuance of the securities over a two-year period, beginning on April 19, 2010, subject to extension upon request to the IPUC. On May 12, 2010, Idaho Power filed a shelf registration statement with the SEC for the sale of up to $500 million of first mortgage bonds and debt securities. The SEC declared the registration statement effective on May 25, 2010. To facilitate the issuance of the debt, on June 17, 2010, Idaho Power entered into a Selling Agency Agreement with Banc of America Securities LLC; BNY Mellon Capital Markets, LLC; J.P. Morgan Securities Inc.; KeyBanc Capital Markets Inc.; Merrill Lynch, Pierce, Fenner & Smith Incorporated; Mitsubishi UFJ Securities (USA), Inc.; RBC Capital Markets Corporation; SunTrust Robinson Humphrey, Inc.; U.S. Bancorp Investments, Inc.; and Wells Fargo Securities, LLC in connection with the potential issuance and sale from time to time of up to $500 million aggregate principal amount of first mortgage bonds, secured medium-term notes, Series I, under Idaho Power’s Indenture of Mortgage and Deed of Trust, dated as of October 1, 1937, as amended and supplemented. As of August 5, 2010, Idaho Power has not sold any first mortgage bonds or debt securities under the May 2010 shelf registration statement.

The issuance of first mortgage bonds requires that Idaho Power meet interest coverage and security provisions set forth in the Indenture of Mortgage and Deed of Trust securing the bonds. Future issuance of first mortgage bonds are subject to satisfaction of covenants and security provisions set forth in the Indenture of Mortgage and Deed of Trust securing the bonds, market conditions, regulatory authorizations, or by covenants and tests contained in other financing agreements. As a result of certain restrictions in the Indenture of Mortgage and Deed of Trust, as of June 30, 2010, Idaho Power could issue under the Indenture of Mortgage and Deed of Trust approximately $503 million of additional first mortgage bonds based on total unfunded property additions of approximately $839 million. Idaho Power could issue an additional $612 million of first mortgage bonds based on retired first mortgage bonds.

Credit Facilities: IDACORP and Idaho Power each have a five-year credit agreement that terminates on April 25, 2012, subject to one year extensions, to be used for general corporate purposes and commercial paper back-up, and that provide for the issuance of loans and standby letters of credit. Each facility contains a covenant requiring 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, 2010, the leverage ratios for IDACORP and Idaho Power were 50 percent and 52 percent, respectively. IDACORP’s and Idaho Power's ability to utilize the credit facilities is subject to continued compliance with the leverage ratio covenants included in the credit facilities, which could limit the ability

of the companies to issue first mortgage bonds and debt securities pursuant to current and future shelf registration statements. At June 30, 2010, IDACORP and Idaho Power were in compliance with all facility covenants.

The following table outlines available liquidity as of the dates specified:

		June 30, 2010				December 31, 2009
				Idaho				Idaho
		IDACORP⁽²⁾		Power		IDACORP⁽²⁾		Power

Revolving credit facility		$	100,000	$	300,000	$	100,000	$	300,000
Commercial paper outstanding			(17,500)		-		(53,750)		-
Identified for other use ⁽¹⁾			-		(24,245)		-		(24,245)
	Net balance available	$	82,500	$	275,755	$	46,250	$	275,755

⁽¹⁾ Port of Morrow and American Falls bonds that holders may put to Idaho Power.
⁽²⁾ Holding company only.

At July 31, 2010, IDACORP had no loans under its credit facility and $15 million of commercial paper outstanding, and Idaho Power had no loans under its credit facility and no commercial paper outstanding.

Impact of Credit Ratings on Liquidity

IDACORP’s and Idaho Power’s access to capital markets, including the commercial paper market, and their respective financing costs in those markets, may depend on the credit ratings of the entity that is accessing the capital markets. The following table outlines the current ratings of Idaho Power’s and IDACORP’s securities, and the ratings outlook, by Standard & Poor’s Ratings Services, Moody’s Investors Service, and Fitch Ratings:

	S&P		Moody’s		Fitch
	Idaho		Idaho		Idaho
	Power	IDACORP	Power	IDACORP	Power	IDACORP
Corporate Credit Rating ⁽¹⁾	BBB	BBB	Baa 1	Baa 2	BBB	BBB
Senior Secured Debt	A-	None	A2	None	A-	None
Senior Unsecured Debt	BBB	None	Baa 1	Baa 2	BBB+	None
Short-Term Tax-Exempt Debt	BBB/A-2	None	Baa 1/ VMIG-2	None	None	None
Commercial Paper	A-2	A-2	P-2	P-2	F2	F2
Credit Facility	None	None	Baa 1	Baa 2	None	None
Rating Outlook	Stable	Stable	Stable	Stable	Stable	Stable
⁽¹⁾ Fitch refers to its comparable rating as the “Long-term Issuer Default Rating.”

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

IDACORP and Idaho Power’s credit facilities are affected by the companies’ credit ratings. A ratings downgrade would result in an increase in the cost of borrowing but would not result in a default or acceleration of the debt under the facilities. If Idaho Power’s ratings are downgraded below investment grade, Idaho Power must extend or renew its authority for borrowings under its IPUC and OPUC regulatory orders. The IPUC order provides that Idaho Power’s authority will continue for 364 days from such downgrade, if Idaho Power promptly notifies the IPUC and files to continue its original authority to borrow. The Oregon statutes permit the issuance of short-term debt without approval of the OPUC.

Idaho Power maintains margin agreements relating to its wholesale commodity contracts that allow performance assurance collateral to be requested of and/or posted with certain counterparties. As of June 30, 2010, Idaho Power had posted approximately $7 million of assurance collateral. Should Idaho Power experience a reduction in its credit rating on Idaho Power's unsecured debt to below investment grade Idaho Power could be subject to additional

requests by its wholesale counterparties to post additional performance assurance collateral. Counterparties to derivative instruments and other forward contracts could request immediate payment or demand immediate ongoing full daily collateralization on derivative instruments and contracts in net liability positions. Based upon Idaho Power’s current energy and fuel portfolio and market conditions as of June 30, 2010, the approximate amount of additional collateral that could be requested upon a downgrade to below investment grade is approximately $23 million. Idaho Power actively monitors the portfolio exposure and the potential exposure to additional requests for performance assurance collateral calls, through sensitivity analysis, to minimize capital requirements.

Capital Requirements

Idaho Power expects that total capital expenditures will be at or slightly above $1 billion from 2010 through 2012. Internal cash generation after dividends is expected to provide less than the full amount of total capital requirements during that period. IDACORP and Idaho Power expect minimal need for external financing in 2010, except for issuances under the dividend reinvestment and employee-related plans. However, IDACORP or Idaho Power may engage in external financing activities during 2010 to pre-fund 2011 debt maturities and/or to take advantage of favorable market conditions should they exist. Beyond 2010, IDACORP and Idaho Power expect to continue financing capital requirements with a combination of internally generated funds and externally financed capital.

The table below presents Idaho Power’s estimated cash requirements for construction, excluding AFUDC, for 2010 through 2012 (in millions of dollars). The table also includes the net cash proceeds and disbursements relating to the Hemingway and Populus Joint Purchase and Sale Agreement between Idaho Power and PacifiCorp discussed below.

		2010		2011-2012
Ongoing capital expenditures		$	155-160	$	352-380
AMI			23-25		23-25
Langley Gulch Power Plant (detailed below)			138-140		175-180
Other major projects			39-40		90-95
	Total	$	355-365	$	640-680

Langley Gulch Power Plant: The Langley Gulch Power Plant is a natural gas-fired CCCT generating plant with a summer nameplate capacity of approximately 300 MWs and a winter capacity of approximately 330 MWs. Construction of the plant is underway. The plant is being constructed near New Plymouth, Idaho and is contracted to achieve commercial operation by November 1, 2012. Incentives are anticipated to advance the commercial operation date to July 1, 2012. The total cost estimate for the project including AFUDC is $427 million, $102 million of which Idaho Power has incurred through June 30, 2010. During the first quarter of 2010, the water treatment and disposal plan was modified to an evaporative pond design. The plan change is not expected to increase the total project cost because it is expected to be offset by reductions in other costs. During the second quarter of 2010, project permitting activities continued and contractor milestones were met. On June 25, 2010, Idaho Power received the air quality permit to construct from the Idaho Department of Environmental Quality. The contracts for the gas pipeline, tap, and meter were executed during this period.

Other Major Projects:

Hydroelectric Projects: In the table above, Idaho Power has included estimated costs relating to the relicensing of hydroelectric facilities and complying with the renewed licenses. These costs total approximately $25 million for the three-year period. An additional estimated amount of $12 million relating to future hydroelectric projects is also included in the table.

Hemingway Station: Idaho Power recently completed construction of its new 500-kV Hemingway station, located near Boise, Idaho. This station was constructed to relieve capacity and operating constraints to enhance reliable service to Idaho Power’s network and native load customers and was placed in service in July 2010 at a total cost of approximately $57 million. The 2010 cost estimate for the project, including station interconnections, is $20 million and is included in the above table.

Hemingway-Bowmont Transmission Line: The Hemingway-Bowmont transmission line consists of 12 miles of new 230-kV double circuit transmission line that will provide power to the Treasure Valley in southwest Idaho. The project was placed in service in 2010 at a total cost of approximately $16 million. The 2010 cost estimate for the project was $6.5 million and is included in the above table.

Boardman-Hemingway Line: The Boardman-Hemingway Line is a proposed 299-mile, 500-kV transmission project between a station near Boardman, Oregon and the Hemingway station. This line will provide transmission service to meet needs identified in the 2009 Integrated Resources Plan (IRP) and other requests pursuant to Idaho Power’s OATT. On April 19, 2010, Idaho Power submitted the eastern line route alternative as its proposed route in its revised right-of-way application to the U.S. Bureau of Land Management (BLM), which restarts the National Environmental Policy Act process. On July 6, 2010, Idaho Power filed a Notice of Intent to Submit an Application for Site Certification with the Oregon Department of Energy. The cost of the initial phase of the project is estimated at $50 million and the 2010 to 2012 cost estimate is included in the table above. Total cost estimates for the project are approximately $600 million. Idaho Power expects its share of the project to be between 30 and 50 percent. Construction costs beyond the initial phase are not included in the table above. This project is expected to be completed in 2015, subject to siting, permitting, and regulatory approvals. On July 6, 2010, the Oregon Department of Fish and Wildlife released for public review and comment a draft update to the conservation plan for the greater sage grouse which, if adopted, may require re-routing of the currently proposed line route. Environmental issues, including proposed legislation relating to the sage grouse in Oregon, could delay the project, alter the proposed siting, and result in significantly higher project costs.

Gateway West Project: Idaho Power and PacifiCorp are pursuing the joint development of the Gateway West project to build transmission lines between Windstar, a station located near Douglas, Wyoming, and the Hemingway station. Idaho Power and PacifiCorp have a cost sharing agreement for expenses incurred for analysis work of the initial phases. Idaho Power’s share of the initial phase, consisting of engineering, environmental review, permitting and rights-of-way, is approximately $40 million, and cost estimates for the 2010 to 2012 timeframe are included in the above table. Initial phases of the project could be completed by 2014; however, timing of the project’s segments may be deferred and constructed as demand requires. Idaho Power’s share will vary by segment across the project and the current estimated cost for its share is between $300 million and $500 million. Construction costs are not included in table above. Idaho Power anticipates receiving a draft environmental impact statement (EIS) from the BLM in late 2010.

AMI / Smart Grid (American Recovery and Reinvestment Act of 2009 (ARRA)): The AMI project provides the means to automatically retrieve energy consumption information, eliminating manual meter reading expense. Idaho Power intends to install this technology for approximately 99 percent of its customers and is on pace to complete the installations by the end of 2011. As of June 30, 2010, Idaho Power had installed approximately 278,000 AMI meters. On May 28, 2010, the IPUC approved Idaho Power’s request to include the 2010 AMI investment in its rate base. The requested increase to rates of approximately $2.4 million was effective June 1, 2010. The total cost estimates for the project are approximately $74 million. The 2010 and 2011 costs are included in the table above.

Under the ARRA, Idaho Power was awarded a grant of $47 million from the Department of Energy (DOE). This grant matches a $47 million investment by Idaho Power in Smart Grid AMI technology. The grant was signed by the DOE on April 2, 2010. Billings began in May 2010 and are expected to occur monthly over the term of the three-year contract. The grant amount is not included in the table above.

Memorandum of Understanding and Related Transactions with PacifiCorp:
Memorandum of Understanding: On March 5, 2010, Idaho Power and PacifiCorp entered into a Memorandum of Understanding (MOU) under which Idaho Power and PacifiCorp agreed to negotiate in good faith to reach arrangements pertaining to the sale by the parties to one another of an undivided ownership interest in certain transmission facilities, and joint development and construction of three transmission projects. The parties also agreed to negotiate in good faith to reach arrangements pertaining to interconnection of their respective systems; joint ownership, operation, and maintenance of the systems; cost-sharing; capital improvements; and each party’s rights to a specified transmission capacity on applicable transmission lines. On July 29, 2010, Idaho Power and PacifiCorp mutually agreed to extend the final date to execute and deliver definitive agreements under the MOU from September 1, 2010 to November 5, 2010. The MOU may be terminated by either party at any time.

Joint Purchase and Sale Agreement and Joint Operating Agreements: In connection with the MOU, on April 30, 2010, Idaho Power entered into a Joint Purchase and Sale Agreement with PacifiCorp, pursuant to which Idaho Power agreed to sell to PacifiCorp a 59.0 percent interest in certain high-voltage transmission-related and interconnection equipment located at the Hemingway station south of Boise, Idaho, and PacifiCorp agreed to sell to Idaho Power a 20.8 percent interest in certain high-voltage transmission-related and interconnection equipment located at PacifiCorp’s Populus station in southeast Idaho. Closing of the purchase and sale occurred on May 3, 2010. The net purchase price on the closing date was $3.7 million paid by PacifiCorp to Idaho Power, $1.7 million of which was subsequently refunded by Idaho Power as a result of a cost true-up to reflect actual construction costs through the closing date. Upon completion of construction of the stations as currently planned, Idaho Power expects that it will have paid an aggregate purchase price of $14.1 million to PacifiCorp for Idaho Power’s interest in the Populus station, and that PacifiCorp will have paid an aggregate purchase price of $12.9 million to Idaho Power for PacifiCorp’s interest in the Hemingway station.

The Hemingway and Populus stations are owned and operated in accordance with separate Joint Ownership and Operating Agreements (Operating Agreements), each dated May 3, 2010. The Operating Agreements include terms relating to the obligations of Idaho Power and PacifiCorp as the operators of the Hemingway and Populus stations, respectively, including, among other items, construction of additional transmission and interconnection equipment at the stations, cost sharing, operation and maintenance, and interconnection and energizing of the transmission systems.

On May 10, 2010, Idaho Power and PacifiCorp filed the Operating Agreements with the FERC, requesting that the FERC determine that the rates that Idaho Power and PacifiCorp were imposing on one another pursuant to the Operating Agreements were just and reasonable. On June 1, 2010, the Bonneville Power Administration (BPA) filed with the FERC an intervention and protest, requesting that the FERC defer acceptance of the Operating Agreements. In its intervention, the BPA stated that it believed the Operating Agreements were only a small part of a much larger transaction between PacifiCorp and Idaho Power involving the purchase and sale of significant portions of transmission lines and other facilities, and that this larger transaction may have significant reliability and operational impacts on the BPA’s system and its customers. On July 9, 2010, the FERC issued an order finding that the terms, conditions, and rates in the Operating Agreements were just and reasonable, and accepted the Operating Agreements for filing effective July 10, 2010.

Existing Transmission Capacity Rights Agreements with PacifiCorp: Idaho Power and PacifiCorp are parties to existing transmission capacity rights agreements that grant to PacifiCorp prescribed transmission capacity rights over portions of Idaho Power’s existing transmission system. The agreements also include a memorandum of understanding and a permitting cost-sharing agreement for the Gateway West transmission line National Environmental Policy Act process. The MOU provides that Idaho Power and PacifiCorp will negotiate in good faith to attempt to reach an agreement to terminate those agreements and replace the transmission arrangements with new agreements, which include the Operating Agreements. Discussions regarding the potential arrangements are ongoing. See “REGULATORY MATTERS – FERC ITSA” for a discussion of the other recent transmission arrangements with PacifiCorp.

Environmental Regulation Costs

Idaho Power’s activities are subject to a broad range of federal, state, regional, and local laws and regulations designed to protect, restore, and enhance the quality of the environment including air, water, and solid waste. Idaho Power estimates its environmental capital expenditures excluding AFUDC, based upon present environmental laws and regulations, will be approximately $18 million during 2010 and $62 million from 2011 through 2012. These amounts are included in the table above as “Ongoing Capital Expenditures” and “Other Major Projects.” The estimated expenditures do not include costs related to possible changes in the environmental laws or regulations and enforcement policies that may be enacted in response to issues such as climate change and other pollutant emissions from coal-fired generation plants and endangered species.

Other Capital Requirements

IDACORP’s non-regulated capital expenditures primarily relate to IFS’s tax-structured investments. IDACORP invested $7 million in tax-structured investments in the first quarter of 2010. Currently there are no additional expenditures anticipated for 2010, $10 million is anticipated in 2011, and none are anticipated in 2012.

Contractual Obligations

The following items are the only material changes to contractual obligations made outside of the ordinary course of business during the six months ended June 30, 2010:

• Idaho Power entered into a power purchase agreement with USG Oregon, LLC for the purchase of energy from the Neal Hot Springs Unit #1 geothermal electric generation facility. The project will be located near Vale, Oregon and the expected output will be approximately 22 MWs, with an estimated on-line date of late 2012. Idaho Power’s purchases under the contract are expected to total $569 million from 2012 to 2037. On May 20, 2010, the IPUC issued an order approving the purchase of energy under the agreement, and stated that the purchases of energy would be allowed as prudently incurred expenses for ratemaking purposes.

• In the second quarter, Idaho Power entered into several power purchase agreements with wind and other alternate energy developers. Payments pursuant to these agreements are expected to total approximately $109 million from 2011 to 2031.

• In April 2010, Idaho Power entered into multiple service agreements with Northwest Pipeline for rate schedule TF-1, Firm Transportation. Idaho Power estimates it will spend approximately $32 million on the firm transportation service agreements. The service agreements start in 2011 with varying end dates ranging through 2042.

Dividends

The amount and timing of dividends paid on IDACORP’s common stock are within the sole discretion of IDACORP’s Board of Directors. The IDACORP Board of Directors reviews the dividend rate quarterly to determine its appropriateness in light of IDACORP’s current and long-term financial position and results of operations, capital requirements, rating agency requirements, legislative and regulatory developments affecting the electric utility industry in general and Idaho Power in particular, competitive conditions, and any other factors the Board of Directors deem relevant. The ability of IDACORP to pay dividends on its common stock is dependent upon dividends paid to it by its subsidiaries, primarily Idaho Power.

For additional information relating to IDACORP and Idaho Power dividends, including restrictions on IDACORP’s and Idaho Power’s payment of dividends, see Note 6 – “Common Stock” to the condensed consolidated financial statements included in this report.

REGULATORY MATTERS:

Overview

As a regulated utility, Idaho Power is under the retail jurisdiction (as to rates, service, accounting, and other general matters of utility operation) of the IPUC and the OPUC, which determine the rates that Idaho Power charges to its general business customers. Idaho Power is also under the regulatory jurisdiction of the IPUC, the OPUC, and the Public Service Commission of Wyoming as to the issuance of debt and equity securities. Idaho Power uses general rate cases, power cost adjustment mechanisms, a fixed cost adjustment mechanism, and subject-specific filings to recover its costs of providing service and to potentially earn a return on investment. The disallowance by the IPUC or the OPUC of Idaho Power’s recovery of its costs would adversely impact Idaho Power’s ability to earn its authorized rate of return on equity. Also, as a public utility under the Federal Power Act, Idaho Power has authority to charge market-based rates for wholesale energy sales under its FERC tariff and to provide transmission services under its OATT.

Idaho Power monitors legislative and regulatory developments at all levels of government, particularly those with the potential to alter the operation and productivity of its generating plants and other assets. Rate changes and regulatory decisions have a significant impact on results of operations and cash flows. Idaho Power has continued to focus on timely recovery of its costs through filings with the IPUC and OPUC. Discussed below are filings and important regulatory determinations that have been recently made. Regulatory matters and the financial impact of rate decisions are also discussed in Note 3 - “Regulatory Matters” to the condensed consolidated financial statements included in this report.

Oregon and Idaho Deferred Net Power Supply Costs

Idaho Power’s power supply costs can vary significantly from year to year, primarily because of weather, loads, and commodity markets. The primary financial impact of power supply cost variations is that monthly cash recovered from customers does not match monthly costs incurred to serve customers, resulting in fluctuations in operating cash flows from year to year. Idaho Power’s PCA mechanisms allow it to defer a majority of the difference between costs and revenues to later be recovered from or refunded to customers. A summary of the changes in deferred power supply costs during the six months ended June 30, 2010 is set forth in Note 3 - “Regulatory Matters” to the condensed consolidated financial statements.

The net change of $78 million in Idaho Power’s balance of deferred power supply costs from December 31, 2009, to June 30, 2010, is primarily a result of power supply costs that were $24 million less than the forecast amount during that period and the recovery of $53 million through rates.

Idaho Regulatory Matters in 2010

Idaho Settlement Agreement: On January 13, 2010, the IPUC approved a settlement agreement among Idaho Power, several of Idaho Power’s customers, the IPUC Staff, and other parties. Significant elements of the settlement agreement included:

A general rate moratorium in effect until January 1, 2012. The moratorium does not apply to other specified revenue requirement proceedings, such as the PCA, the FCA, pension funding, AMI, energy efficiency rider, and government imposed fees.
A specified distribution of the expected reduction in 2010 PCA rates that would reduce customer rates, provide some general rate relief to Idaho Power, and reset base power supply costs for the PCA. This provision anticipated a significant reduction in PCA rates for the 2010-2011 PCA year.
A provision to share with Idaho customers 50 percent of any Idaho-jurisdiction earnings in excess of a 10.5 percent return on equity in any calendar year from 2009 to 2011.
A provision to allow additional amortization of ADITC if Idaho Power’s actual return on equity in its Idaho jurisdiction is below 9.5 percent in any calendar year from 2009 to 2011. Idaho Power is permitted to amortize additional ADITC in an amount up to $45 million over the three-year period, but could use no more that $15 million in any one year unless there is a carryover. Carryover amounts are added to the $15 million annual allowance up to a maximum amortization of $25 million in any one year.

Because Idaho Power’s 2009 Idaho-jurisdiction return on equity was between 9.5 and 10.5 percent, the sharing and additional amortization provisions were not triggered in 2009, and the ADITC available for accelerated additional amortization in 2010 is $25 million. Idaho Power recorded additional ADITC amortization of $4.5 million in the first quarter of 2010, but reversed the entire $4.5 million in the second quarter based on updated estimates of annual 2010 return on equity.

The settlement agreement included a provision to reestablish the base level for net power supply costs effective with the June 1, 2010 PCA rate change. On January 19, 2010, Idaho Power filed with the IPUC a request to reestablish base net power supply costs with an increase of $74.8 million in the Idaho jurisdiction. On April 13, 2010, the IPUC found that adjustments for PURPA contracts ($7.1 million) and the Hoku contract ($4.0 million) as proposed by the IPUC Staff were reasonable reductions to Idaho Power’s proposed base net power supply expenses. The remaining amount of $63.7 million was approved as a working number for Idaho Power’s 2010 PCA filing, but the IPUC deferred final calculation of authorized base net power supply expenses to the 2010 PCA case. Remaining at issue

in the settlement was a $24.9 million increase in coal costs at the Bridger plant, which was first raised as an area for review by the OPUC Staff, which review has concluded. In May 2010, the IPUC issued an order approving the $63.7 million increase in base net power supply expenses and cost recovery in full in the Idaho jurisdiction in connection with Idaho Power’s 2010 PCA filing and order, discussed below.

2010 PCA Filing and Order: On April 15, 2010, Idaho Power filed its annual application with the IPUC to implement new PCA rates to be effective June 1, 2010 through May 31, 2011, and to change base rates, pursuant to the terms of the Idaho settlement agreement. Idaho Power’s application stated that the proposed PCA computations result from the stipulation approved by the IPUC in its order issued in January 2010, which provides for a sharing between customers and Idaho Power shareholders of any PCA rate reduction that results from the 2010 PCA. The January 2010 stipulation provides that PCA rates will be reduced by the full calculated amount and that base rates will be increased in an amount that partially offsets the PCA decrease. On May 28, 2010, the IPUC issued its order approving a $146.9 million decrease in the PCA, along with a base rate increase of $88.7 million. The net effect of these two rate adjustments is an overall decrease in customer rates of $58.2 million, or 6.49 percent, effective June 1, 2010. Idaho Power’s PCA application was approved as filed with the IPUC, with the exception of a $215,000 interest expense adjustment relating to base power supply costs.

The IPUC’s order identified the following two specific items of contention raised by certain industrial customers of Idaho Power: (1) the prudency of Idaho Power’s determination of coal costs for the Jim Bridger plant, and (2) the use of the load growth adjustment rate (LGAR) in times of load decline. The LGAR is an element of the PCA formula that is intended to eliminate recovery of power supply expenses associated with load growth resulting from changing weather conditions, a growing customer base, or changing customer use patterns. The IPUC approved the full Jim Bridger coal costs included in the base level power supply costs and the amount included in Idaho Power’s PCA forecast, finding that Idaho Power had met its burden of proof to establish the reasonableness of the coal costs to be included in the base level power supply costs. With regard to the LGAR, Idaho Power’s true-up calculation for the PCA included an increase of $21.3 million for the decline in load growth for the Idaho jurisdiction. The intervening parties asserted that use of the LGAR in times of load decline is inappropriate in that it results in potential double recovery. However, the IPUC Staff recommended no change to the load growth adjustment amounts or methodology, and the IPUC did not remove the LGAR adjustment to the PCA component. The IPUC’s order stated, however, that it expects the IPUC Staff, Idaho Power, and interested parties to meet to address an appropriate change to the load growth adjustment mechanism to eliminate a potential double recovery when loads decline.

Other 2010 IPUC Filings and Orders:

FCA, Pension Expense, and AMI: In March 2010, Idaho Power made three rate filings with the IPUC, each with a requested effective date of June 1, 2010, and in May 2010 the IPUC issued orders on those three rate filings, as follows:

• Fixed Cost Adjustment: In March 2007, the IPUC approved the implementation of a FCA pilot program for Idaho Power’s residential and small general service customers. The FCA is a rate mechanism designed to remove Idaho Power’s disincentive to invest in energy efficiency programs by separating (or decoupling) the recovery of fixed costs from the variable kilowatt-hour charge and linking it instead to a set amount per customer. The FCA allows Idaho Power to recover the difference between certain fixed costs recovered in rates and the fixed costs authorized for recovery in Idaho Power’s most recent rate case. The pilot program began on January 1, 2007 and ended on December 31, 2009. On April 29, 2010, the IPUC approved a two-year extension of the FCA pilot program, effective retroactively to January 1, 2010. For the three and six months ended June 30, 2010, Idaho Power accrued revenues of $1.6 million and $3.4 million, respectively, under the FCA.

On March 15, 2010, Idaho Power filed an application with the IPUC requesting authorization to implement FCA rates for electric service from June 1, 2010 through May 31, 2011. On May 28, 2010, the IPUC issued an order approving Idaho Power’s request. The rate adjustments are expected to result in collection of an additional $3.6 million over currently billed amounts during the period from June 1, 2010 to May 31, 2011. In its order, the IPUC reiterated a statement in its prior order that making the FCA permanent is

premature, and that during the two year extension of the FCA program it expects additional data to develop, giving interested parties and customers time to evaluate the FCA and address issues of concern.

• Pension Expense Recovery: The IPUC approved Idaho Power’s request to increase rates to allow recovery of Idaho Power’s 2009 cash contribution to its defined benefit pension plan, which contribution is required to be made by September 15, 2010. Idaho Power’s application sought approval of $5.4 million in pension cost recovery over a one-year period to allow recovery contemporaneous with Idaho Power’s cash contributions to the defined benefit pension plan.

The IPUC’s order provided that the allowance of recovery of the 2009 pension plan contribution does not guarantee that the IPUC will similarly approve recovery of future pension contributions, without evidence that Idaho Power has evaluated alternatives to reduce the burden placed on customers. The IPUC stated in its order that “Idaho Power is advised that, previous orders notwithstanding, approval of Idaho Power’s pension contributions in this case does not guarantee Commission approval of future pension plan contributions. Authority for the balancing account and regulatory account remain in place. However, further justification is required before additional rate recovery for future contributions will be authorized.” Idaho Power is currently undertaking the analysis directed by the IPUC, is considering and evaluating alternatives, and intends to provide the IPUC with the results of its evaluation and recommendations in the summer or early fall of 2010. Idaho Power currently records its deferred pension expense as a regulatory asset, but if the IPUC were to determine that future pension contributions were not reasonable and prudently incurred, Idaho Power would be required to write off some or all of the balance of its deferred pension expense for its Idaho jurisdiction. In addition to the $5.4 million of regulatory assets approved for recovery discussed above, as of June 30, 2010, Idaho Power had Idaho jurisdiction regulatory assets associated with deferred pension expenses of $46.6 million which have not yet been approved by the IPUC for recovery. Idaho Power has determined, based on its evaluation, that these Idaho jurisdiction regulatory assets are probable of recovery.

In June 2010, the Relief Act was signed into law. The Relief Act would, if Idaho Power elects, allow Idaho Power to reduce near-term required contributions to the pension plan by spreading them over a longer time period. See “LIQUIDITY AND CAPITAL RESOURCES – Operating Cash Flows” above for further information relating to the Relief Act and its potential impact on Idaho Power.

• Advanced Metering Infrastructure: Idaho Power’s AMI project provides the means to automatically retrieve energy consumption information, eliminating manual meter reading expense. On March 15, 2010, Idaho Power filed an application with the IPUC requesting authority to implement a 0.41 percent average increase (representing a 0.33 percent overall increase) in rates for identified customer classes to recover costs relating to the AMI project. Idaho Power’s AMI investment during the 2010 test year indicated a revenue deficiency of $2.4 million for the Idaho jurisdiction, which resulted from Idaho Power’s increase in rate base from the AMI deployment, the accelerated depreciation of existing metering equipment, and the inclusion of net operating and maintenance expense related to the AMI deployment. On May 28, 2010, the IPUC approved Idaho Power’s application as submitted, authorizing the rate increase effective June 1, 2010.

Idaho Energy Efficiency Programs:

Idaho Power’s energy efficiency rider is the funding mechanism for Idaho Power’s investment in energy efficiency, conservation, and demand response programs. On April 14, 2010, the IPUC completed its review of energy efficiency rider expenditures that Idaho Power made from 2002 to 2007. All rider expenditures during that time period were found to be prudently incurred and approved for ratemaking purposes.

On March 15, 2010, Idaho Power filed an application with the IPUC requesting an order designating energy efficiency expenditures of $50.7 million incurred in 2008 and 2009 as prudently incurred expenses. An order from the IPUC is pending.

On May 12, 2010, the IPUC approved Idaho Power’s continued participation in the Northwest Energy Efficiency Alliance for the period 2010-2014, with funding through the energy efficiency rider. Idaho Power first began participating in the NEEA in 1997, and the IPUC has historically allowed it to recover its costs in its rates. Idaho Power’s share of expenses is 8.62 percent of the NEEA’s $191.7 million 2010-2014 budget.

Integrated Resource Plan (IRP): Idaho Power filed its 2009 IRP with the IPUC and OPUC in December 2009. The IRP addresses available supply-side and demand-side resource options, planning period load forecasts, potential resource portfolios, a risk analysis, and near-term and long-term action plans. On July 9, 2010, the OPUC issued a proposed order that, if issued as a final order, would conditionally acknowledge the IRP. On August 3, 2010, the IPUC issued an order accepting the IRP for filing.

Oregon Regulatory Matters in 2010

Oregon 2009 General Rate Case Settlement: On February 24, 2010, the OPUC approved a $5 million, or 15.4 percent, increase in base rates in the Oregon jurisdiction. The new rates were effective March 1, 2010, and are based on a return on equity of 10.175 percent and an overall rate of return of 8.061 percent. Idaho Power’s previously authorized rate of return in Oregon was 7.83 percent, and its requested rate of return in its general rate case filing was 8.68 percent.

Oregon Power Cost Recovery Mechanisms: Idaho Power’s power cost recovery mechanism in Oregon went into effect in 2008. It has two components: the PCAM and the APCU. The combination of the PCAM and the APCU allows Idaho Power to recover excess net power supply costs in a more timely fashion than through the previously existing deferral process.

PCAM: The PCAM consists of an annual power supply expense true-up, which uses an asymmetrical dead band (the range of deviations within which Idaho Power absorbs cost increases or decreases) to calculate the net power supply deviations used in the true-up calculations. On February 26, 2010, Idaho Power filed its PCAM application for the 2009 year with the OPUC. The filing stated that actual net power supply costs were within the deadband, resulting in no request for a deferral. In an April 15, 2010 stipulation, which was approved in an order issued by the OPUC on May 24, 2010, Idaho Power agreed to a one-time modification to the deadband used to calculate the net power supply deviations in the 2010 PCAM. The deadband was increased by $0.2 million, to $2.4 million, before any excess power costs are subject to collection pursuant to the terms of the PCAM, and the deadband was reduced by $0.2 million, to $(1.0) million, before any power costs are subject to return pursuant to the terms of the PCAM.
APCU: Idaho Power annually updates its net power supply expense included in its Oregon rates through the APCU. The APCU is comprised of two primary components: an October power cost update and a March power cost forecast. The October update contains Idaho Power’s forecasted net power supply expense reflected on a normalized and unit basis for an April through March test period. The March forecast contains Idaho Power’s net power supply expense based upon updated actual forecasted conditions. The rates from the October update and March forecast are combined, and that combined rate is then included in rates effective on June 1 of each year. On March 23, 2010, Idaho Power filed its March forecast for the 2010 APCU rate adjustment with the OPUC. A stipulation among various parties combining the March forecast and 2009 October update was filed with the OPUC on April 15, 2010. The stipulation was approved on May 24, 2010, and resulted in an overall increase of 5.53 percent in Oregon rates. The rate adjustments are expected to result in collection of an additional $2.2 million over currently billed amounts over the 12-month APCU adjustment period beginning June 1, 2010.

Oregon Solar Photovoltaic Energy Pilot Program: During and subsequent to the second quarter of 2010, the OPUC adopted rules implementing a solar photovoltaic capacity standard (SPCS) and solar photovoltaic pilot program (SPPP) applicable to companies providing electric service to Oregon customers. The OPUC orders and related Idaho Power compliance filings established the rules, processes, and procedures to implement the Oregon Legislature’s mandate for all Oregon electric companies to implement and make solar photovoltaic energy programs available to their respective Oregon customers. Pursuant to the SPCS and SPPP, Idaho Power is required to (1) either build or purchase an aggregate of 500kW of energy from one or more solar facilities by the year 2020; and (2) purchase energy from qualified solar photovoltaic systems at a financial incentive rate of 55 cents per kWh to promote the development of 10-kW and smaller solar projects over the next two years. The program is to be rolled

out over a two year period for a total nameplate capacity of 400 kW. The first year's program allotment of 200 kW was made available to Oregon customers on July 1, 2010, and is fully subscribed. The legislative mandate and the OPUC orders specify that the cost of these programs be paid by Oregon customers.

Federal Regulatory Matters in 2010

FERC ITSA: In June 2009, Idaho Power filed with the FERC a request for authority to increase rates to PacifiCorp under the existing Agreement for Interconnection and Transmission Services (ITSA) between Idaho Power and PacifiCorp to the OATT level. In August 2009, the FERC accepted the rates subject to refund. On May 24, 2010, Idaho Power and PacifiCorp entered into and filed an offer of settlement with the FERC, which settlement affirms those rates. On July 23, 2010, the FERC issued an order approving the ITSA settlement. Under the settlement, PacifiCorp will take and pay for 250 MW of long-term firm point-to-point transmission service, pursuant to the ITSA, the rates, terms, and conditions of which will be equivalent to Idaho Power’s OATT.

Annual OATT Update: On June 1, 2010, Idaho Power posted its DIF for its OATT on its OASIS Internet platform. The DIF is the draft computation of Idaho Power’s transmission rate for service under its OATT, which is updated annually. Under the tariff, the new rates are effective on October 1 of each year. The new draft rate submitted by Idaho Power is $19.60 per kW/yr, an increase of 23.8 percent over the present OATT rate of $15.83 per kW/yr. Several parties have submitted data requests in connection with Idaho Power’s DIF, and Idaho Power is currently responding to those data requests.

FERC Compliance Program: The FERC has approved an extensive number of reliability standards developed by the North American Electric Reliability Corporation (NERC) and the Western Electricity Coordinating Council (WECC), including critical infrastructure protection (CIP) standards and regional standard variations. As part of its compliance program, Idaho Power periodically reviews its operations for compliance with FERC rules, orders, and standards and self-reports compliance issues to the FERC and the WECC. To date, reports Idaho Power has submitted to the FERC have focused on Standards of Conduct, Idaho Power’s OATT, and compliance with FERC requirements to post available capacity on Idaho Power’s website and with the Western Systems Power Pool. Idaho Power has self-reported matters relating to CIP and other reliability standards to the WECC.

During the first quarter of 2010, Idaho Power self-reported to both the FERC and the WECC, and Idaho Power received notification that the FERC intends to take no further action regarding several issues previously reported by Idaho Power. During the first quarter of 2010, Idaho Power also received notices of alleged violations from the WECC relating to reliability and CIP matters. During the second quarter of 2010, Idaho Power submitted self-reports to both the FERC and the WECC, received notification that the FERC intends to take no further action regarding several issues previously self-reported by Idaho Power, and received a notice of confirmed violation from the WECC relating to a reporting deadline.

Certain matters reported to the FERC and the WECC remain unresolved, and Idaho Power is unable to predict what action, if any, the WECC or the FERC will take on those unresolved matters, but Idaho Power does not expect any material adverse effect on its financial position, results of operations, or cash flows. Idaho Power plans to continue its policy of reducing potential violations through its compliance program and self-reporting compliance issues to the FERC and the WECC.

Relicensing of Hydroelectric Projects:

Idaho Power, like other utilities that operate nonfederal hydroelectric projects on qualified waterways, obtains licenses for its hydroelectric projects from the FERC, and these licenses last for 30 to 50 years. Idaho Power is actively pursuing relicensing of the HCC and Swan Falls hydroelectric projects. In addition, Idaho Power recently received a license amendment to expand the Shoshone Falls hydroelectric project and to potentially extend the term of the license beyond its 2034 expiration date.

HCC: Idaho Power’s most significant relicensing effort is the HCC, which provides approximately 68 percent of Idaho Power’s hydroelectric generating nameplate capacity and 36 percent of its total generating nameplate capacity. In 2007, the FERC Staff issued a final EIS for the HCC, which the FERC will use to determine whether, and under what conditions, to issue a new license for the project. Idaho Power has reviewed the final EIS and is

developing comments for filing with the FERC. However, certain portions of the final EIS involve issues that may be influenced by water quality certifications for the project under section 401 of the Clean Water Act and formal consultations under the Endangered Species Act (ESA), which remain unresolved. Idaho Power anticipates filing comments to the final EIS as the section 401 and ESA processes progress and the manner in which they may affect pending issues becomes more certain. In that regard, Idaho Power continues to cooperate with the U.S. Fish and Wildlife Service, the National Marine Fisheries Service, and the FERC in an effort to address ESA concerns and to work with Idaho and Oregon to take measures to ensure that any discharges from the HCC will comply with the temperature and other applicable necessary state water quality standards so that appropriate water quality certifications can be issued for the project. The FERC is expected to issue a license order for the HCC once the ESA consultation and the state water quality certification processes are completed. Idaho Power is currently operating under an annual license issued by the FERC and expects to continue operating under annual licenses until a new multi-year license is issued.

Swan Falls: Idaho Power is currently operating the Swan Falls hydroelectric project under an annual license while its application for a multi-year license is pending before the FERC. The FERC has issued a draft EIS for the Swan Falls project and Idaho Power anticipates that the FERC will complete and issue a final EIS in 2010.

Shoshone Falls: On July 1, 2010, the FERC issued an amended license for the Shoshone Falls project to expand its generating capacity to 60.875 MW. The amended license has an expiration date of 2034, but provides that the license will be extended to 2044 following completion of the proposed generation capacity expansion project. Idaho Power is currently evaluating and reviewing the license requirements and related operating issues of the proposed generation capacity expansion project.

Relicensing costs are recorded in construction work in progress until new multi-year licenses are issued by the FERC, at which time the charges will be transferred to electric plant in service. Relicensing costs and costs related to new licenses will be submitted to regulators for recovery through the ratemaking process. Relicensing costs of $123 million and $5 million for HCC and Swan Falls, respectively, were included in construction work in progress at June 30, 2010. The IPUC authorizes Idaho Power to include in rates approximately $6.8 million annually ($10.6 million grossed up for income taxes) of AFUDC relating to the HCC relicensing project, and collecting these amounts will reduce the relicensing amount submitted to regulators for recovery through the ratemaking process.

LEGAL MATTERS:

Western Energy Proceedings at the FERC: Idaho Power and IE are parties to proceedings at the FERC arising from the “western energy situation” – the California energy crisis and the energy shortages, high prices, and blackouts in the western United States during 2000 and 2001 that caused numerous purchasers of electricity in those markets to initiate proceedings seeking refunds or other forms of relief and the FERC to initiate its own investigations. The three major sets of cases arising out of the western energy situation relate to (1) pricing of sales in the California Independent System Operator (Cal ISO) and California Power Exchange (CalPX) markets (the California refund proceeding); (2) claims of market manipulation and tariff violations in those markets, some of which have been the subject of FERC show cause orders (the market manipulation cases); and (3) pricing of sales in the spot power markets in the Pacific Northwest (the Pacific Northwest refund proceeding).

Proceedings in all three sets of cases remain pending before the FERC. In addition, there are more than 200 petitions pending in the United States Court of Appeals for the Ninth Circuit (Ninth Circuit) for review of numerous FERC orders regarding the western energy situation, including the California refund proceeding and the market manipulation cases. Decisions in these appeals may have implications with respect to other pending cases, including those to which Idaho Power and IE are parties.

Idaho Power and IE have reached settlements with the principal parties to the California refund proceeding and the market manipulation cases, but there remain claims by parties that have not settled that represent a small minority of potential refunds in those proceedings. Idaho Power and IE are unable to predict the outcome of these matters, but believe that the settlement releases they have obtained will restrict potential claims that might result from the disposition of these two sets of proceedings and that these matters will not have a material adverse effect on their consolidated financial positions, results of operations, or cash flows.

In the Pacific Northwest refund proceeding, after reviewing the FERC’s 2003 decision declining to order refunds, the Ninth Circuit remanded the case to the FERC, officially returning the case to the FERC on April 16, 2009, to consider whether evidence of market manipulation would have altered the agency’s conclusions about refunds and to include sales originating in the Pacific Northwest to the California Department of Water Resources (CDWR) in the proceedings. In separate filings the California Parties (consisting of Pacific Gas & Electric Company, San Diego Gas & Electric Company, Southern California Edison Company, the California Public Utilities Commission, the California Department of Water Resources and the California Attorney General), City of Tacoma (Tacoma), and the Port of Seattle, Washington (Port of Seattle) asked the FERC to reorganize and restructure the Pacific Northwest case to enable them to pursue claims that all spot market sales in the Cal ISO and CalPX markets and in the Pacific Northwest from January 1, 2000 through June 20, 2001 should be subject to refund and repriced because market manipulation and tariff violations affected spot market prices. Their requests would expand the scope of the refund period in the Pacific Northwest proceeding from the December 25, 2000 through June 20, 2001 period previously considered by the FERC. In May 2009, the California Parties requested that the FERC sever sales to CDWR from the Pacific Northwest proceeding and consolidate their claims regarding these sales with ongoing proceedings in cases that Idaho Power and IE have settled, as well as with a new complaint filed on May 22, 2009 by the California Attorney General against some sellers, but not Idaho Power and IE. Idaho Power and IE, along with a number of other parties, filed their opposition to the requests of the California Parties. In April 2010, the California Parties filed a motion with the FERC renewing their May 2009 requests. In August 2009, Tacoma and Port of Seattle jointly requested the FERC to require refunds from sellers in the Pacific Northwest spot markets for the expanded period (January 1, 2000-June 20, 2001). Idaho Power and IE joined with a number of other sellers in the Pacific Northwest markets during 2000 and 2001 in opposing the motion of Tacoma and Port of Seattle. On July 21, 2010, the Port of Seattle and Tacoma once again filed a motion requesting that the FERC either summarily dispose of the case or set it for hearing, and the California Parties, answering a pleading in the Brown Complaint, renewed their request for consolidation. The FERC has not yet acted on the remand from the Ninth Circuit or on these filings and requests from the California Parties, Tacoma, and Port of Seattle. Idaho Power and IE are unable to predict the outcome of these matters or estimate the impact they may have on their consolidated financial positions, results of operations, or cash flows.

Sierra Club Lawsuits at the Bridger and Boardman Coal-Fired Plants: In February 2007, the Sierra Club and the Wyoming Outdoor Council filed a complaint against PacifiCorp in the U.S. District Court in Cheyenne, Wyoming, alleging that PacifiCorp had violated air quality opacity standards at the Jim Bridger coal-fired plant in Sweetwater County, Wyoming. On April 15, 2010, the parties jointly filed a proposed consent decree resolving the pending litigation. The consent decree was approved and entered by the court on June 8, 2010. Idaho Power is fully reserved for the contingency and approval of the consent decree will not have a material adverse effect on Idaho Power’s consolidated financial position, results of operations, or cash flows.

In September 2008, the Sierra Club and four other non-profit corporations filed a complaint against PGE in the U.S. District Court for the District of Oregon alleging opacity permit limit violations at the Boardman coal-fired plant located in Morrow County, Oregon. The complaint also alleged violations of the Clean Air Act (CAA), related federal regulations and the Oregon State Implementation Plan relating to PGE’s construction and operation of the plant. The complaint sought a declaration that PGE had violated opacity limits, a permanent injunction ordering PGE to comply with such limits, injunctive relief requiring PGE to remediate alleged environmental damage and ongoing impacts, civil penalties of up to $32,500 per day per violation, and reimbursement of plaintiffs’ costs of litigation, including reasonable attorneys’ fees. Idaho Power is not a party to this proceeding but has a 10 percent ownership interest in the Boardman plant. PGE owns 65 percent and is the operator of the plant. PGE has stated that it cannot determine with certainty the total amount of monetary penalties and damages asserted, but based solely on the complaint the estimated amount is $60 million. Idaho Power is unable to predict the outcome of this matter or estimate the impact it may have on its consolidated financial position, results of operations, or cash flows.

Snake River Basin Water Rights: Idaho Power is engaged in the Snake River Basin Adjudication (SRBA), which commenced in 1987, to define the nature and extent of water rights in the Snake River Basin in Idaho, including the water rights of Idaho Power. On March 25, 2009, Idaho Power and the State of Idaho entered into a settlement agreement with respect to the 1984 Swan Falls Agreement and Idaho Power’s water rights under the Swan Falls Agreement, which settlement agreement is subject to certain conditions discussed below. The settlement agreement will also resolve litigation between Idaho Power and the State of Idaho relating to the Swan Falls Agreement that was filed by Idaho Power on May 10, 2007 with the Idaho District Court for the Fifth Judicial Circuit, which has jurisdiction over SRBA matters, including the Swan Falls case.

The settlement agreement resolves the pending litigation by clarifying that Idaho Power’s water rights in excess of minimum flows at its hydroelectric facilities between Milner Dam and Swan Falls Dam are subordinate to future upstream beneficial uses, including aquifer recharge. The agreement commits the State of Idaho and Idaho Power to further discussions on important water management issues concerning the Swan Falls Agreement and the management of water in the Snake River Basin. It also recognizes that water management measures that enhance aquifer levels, springs and river flows, such as aquifer recharge projects, benefit both agricultural development and hydropower generation and deserve study to determine their economic potential, their impact on the environment and their impact on hydropower generation. These will be a part of the Comprehensive Aquifer Management Plan (CAMP), approved by the Idaho Water Resource Board (IWRB) for the ESPA, which includes limits on the amount of aquifer recharge. Idaho Power is a member of the ESPA CAMP advisory committee and implementation committee.

On April 24, 2009, the Governor of Idaho signed into law legislation approving provisions contained in the settlement agreement. On May 6, 2009, as part of the settlement, Idaho Power, the Governor of Idaho and the IWRB executed a memorandum of agreement relating to future aquifer recharge efforts and further assurances as to limitations on the amount of aquifer recharge. Idaho Power and the State of Idaho also filed a joint motion to the SRBA court to dismiss the Swan Falls case and enter the stipulated water right decrees set forth in the settlement agreement. Parties representing groundwater users in the ESPA objected to some of the language proposed by Idaho Power and the State of Idaho relating to water rights in the decrees to be entered by the SRBA court as contemplated by the settlement agreement. Specifically, the concerns relate to the language describing the subordination of the rights and its interplay with the original Swan Falls settlement document and implementing legislation. On January 4, 2010, the court issued an order approving the overall settlement subject to certain modifications to the draft water right decrees proposed by Idaho Power and the State of Idaho. Idaho Power is working with the State of Idaho and the parties to reach an agreement consistent with the court’s order regarding the language of the decrees.

Idaho Power also filed an action in the U.S. District Court of Federal Claims in Washington, D.C. in October 2007, and an amended complaint on September 30, 2008, against the U.S. Bureau of Reclamation (USBR) relating to a 1923 contract right for delivery of water to its hydropower projects on the Snake River. The action seeks to recover damages from the USBR for the lost generation resulting from reduced flows and a prospective declaration of contractual rights and obligations of the parties. In recent months, Idaho Power has been working with the U.S. and Idaho interests (including the State of Idaho and upstream water users) in an effort to resolve certain state water right issues pending in the SRBA that are common to both the SRBA and the pending federal case. In an effort to promote efficiency, the parties have agreed to present certain legal issues associated with the 1923 contract to the court in the SRBA case that are expected to resolve issues in the pending federal case. The SRBA court has scheduled the presentation of these issues to the court by the fall of 2010. Idaho Power and the USBR have agreed to stay further proceedings in the federal case pending the resolution of these issues in the SRBA case.

Idaho Power is unable to predict the outcomes of these matters or estimate the impact they may have on its consolidated financial position, results of operations or cash flows.

For further information regarding legal proceedings, see Note 9 – “Contingencies” to the condensed consolidated financial statements included in this report.

ENVIRONMENTAL ISSUES:

Idaho Power is subject to regulations by federal, state, and local authorities governing the protection of the environment, including the Clean Air Act; the Clean Water Act; the Comprehensive Environmental Response, Compensation and Liability Act; the Emergency Planning and Community Right-to-Know Act; the Endangered Species Act; the Federal Land Policy and Management Act; the National Environmental Policy Act; the Resource Conservation and Recovery Act; and related state laws. These laws and regulations are continually changing and are generally becoming more restrictive. Idaho Power monitors legislative and regulatory developments at all levels of government for environmental issues, particularly those with the potential to alter the operation and productivity of power generating plants and other assets. Environmental laws and regulations may, among other things, increase the cost of operating power generation plants and constructing new facilities; require that Idaho Power install additional pollution control devices at existing generating plants; or require that Idaho Power shut down certain power generation plants. Compliance with environmental laws and regulations could result in increases to capital

expenditures and operating expenses. While there can be no assurance of recovery, Idaho Power intends to seek recovery of any such costs through the ratemaking process.

Global Climate Change: There is concern nationally and internationally about global climate change and the possible contribution of GHG emissions to climate change. Long-term climate change could significantly affect Idaho Power’s business in a variety of ways, including the following: (i) changes in temperature and precipitation could affect customer demand; (ii) extreme weather events could increase service interruptions, outages, maintenance costs, and the need for additional systems backup, and can affect the supply of and demand for electricity and natural gas, which may impact the price of energy commodities; (iii) changes in the amount and timing of snowpack and stream flows could adversely affect hydroelectric generation; (iv) legislative and/or regulatory developments related to climate change could affect plans and operations, including placing restrictions on the construction of new generation resources, the expansion of existing resources, or the operation of generation resources in general; and (v) consumer preference for, and resource planning decisions requiring, renewable or low GHG-emitting sources of energy could impact demand from existing sources and require significant investment in new generation and transmission resources. Idaho Power does not currently operate in coastal areas and, while there may be secondary impacts such as increased supply chain costs, it is not directly exposed to the effects of potential sea level rises.

Greenhouse Gas Emission Reduction Goals: Despite the current absence of a national mandatory GHG reduction program, Idaho Power is actively engaged in voluntary GHG reduction efforts. In September 2009, IDACORP’s and Idaho Power’s boards of directors approved guidelines that established a goal to reduce the CO₂ emission intensity of Idaho Power’s utility operations. Idaho Power’s goal is to reduce its resource portfolio’s average CO₂ emission intensity for the 2010 through 2013 time period to a level of 10 to 15 percent below Idaho Power’s 2005 CO₂ emission intensity of 1,194 lbs CO₂/MWh. The guidelines are intended to reduce Idaho Power’s average CO₂emission intensity in a manner that minimizes the costs of those reductions to Idaho Power’s customers.

In 2008, Idaho Power and Ida-West together ranked as the 32^nd lowest emitter of CO₂/MWh produced among the nation’s 100 largest electricity producers, according to a June 2010 collaborative report from Ceres, the Natural Resources Defense Council, Public Service Enterprise Group, Constellation Energy, and Entergy using publicly reported 2008 generation and emissions data. According to the report, out of the 100 companies named, Idaho Power and Ida-West together ranked as the 55^th largest power producer based on fossil fuel, nuclear, and renewable energy facility total electricity generation, and the 31^st lowest emitter of CO₂ by tons of emissions.

In May 2010, Idaho Power submitted information to the Carbon Disclosure Project (CDP), an independent, not-for-profit organization that claims the largest database of corporate climate change information in the world. Idaho Power’s estimated CO₂ emission intensity (Lbs/MWh) from its generation facilities as submitted to the CDP was 1,150, 1,097, and 1,004 Lbs/MWh for 2007, 2008, and 2009, respectively. Idaho Power estimates that its CO₂ emission intensity from Idaho Power-owned generation facilities for the six months ended June 30, 2010 was 905 Lbs CO₂/MWh.

Regulation of Greenhouse Gas Emissions: The American Clean Energy and Security Act of 2009, H.R. 2454, regarding GHG emissions, renewable energy, energy efficiency, carbon capture and sequestration, and other matters, passed the U.S. House of Representatives on June 26, 2009. The Senate introduced similar legislation in September 2009. In May 2010, a discussion draft of an energy and climate change bill was released in the Senate that outlined a cap-and-trade program. Proposed and draft legislation also contains provisions relating to the reinvigoration of the nuclear power industry, energy efficiency incentives, deployment of carbon capture and sequestration, and offshore oil and gas drilling. Debate on GHG legislation continues in Congress; however, given the complexity of the legislation and other competing legislative priorities, the timing and elements of any future legislation addressing GHG emission reduction requirements are uncertain. There are also state and regional 68 initiatives (including the Western Regional Climate Action Initiative) considering market-based mechanisms to reduce GHG emissions.

In support of international efforts to reduce GHG emissions, in January 2010 President Obama pledged to cut GHG emissions in the United States from 2005 levels by 17 percent by 2020 and 80 percent by 2050. Any international treaty creating mandatory GHG emission reduction requirements in the United States would need to be ratified by the U.S. Senate and implemented through legislation adopted by the U.S. Congress.

In September 2009, the EPA (Environmental Protection Agency) issued a final rule that requires monitoring and reporting of GHG emissions by a number of entities beginning on January 1, 2010. Most facilities are required to report annually. Electric generation facilities (including Idaho Power’s facilities) already reporting CO₂emissions under the CAA Acid Rain Program must report CO₂, nitrous oxide (NO_x), and methane emissions to the EPA on a quarterly basis. In March 2010, the EPA proposed to expand the monitoring and reporting requirements to include emissions of fluorinated GHGs such as sulfur hexafluoride from electrical power transmission and distribution systems.

Also in September 2009, the EPA acknowledged that the CAA will require it to regulate GHG emissions from stationary sources (including Idaho Power’s thermal facilities) through both its preconstruction and operating permit programs when the national GHG emission standards for motor vehicles go into effect.

In December 2009, the EPA issued an “endangerment finding” for GHG emissions from motor vehicles. The “endangerment finding” is required for the EPA and the Department of Transportation National Highway Traffic Safety Administration to finalize their September 2009 proposal to adopt national GHG emission (i.e. tailpipe) standards for motor vehicles. On April 1, 2010, the EPA and the Department of Transportation issued a final rule establishing motor vehicle GHG emission standards. The “endangerment finding” and the GHG emission standards for motor vehicles have been appealed to the U.S. Court of Appeals for the District of Columbia Circuit.

In June 2010, the EPA issued a final rule regulating GHG emissions through its preconstruction and operating permit programs under the CAA. This rule is referred to as the “Tailoring Rule.” The first phase of the rule will take effect on January 2, 2011, and will require imposition of Best Available Control Technology (BACT) for GHG emissions if a new major source or modification of a source is projected to result in GHG emissions of at least 75,000 tons per year (CO₂equivalent). In addition, existing major sources will need to amend their operating permits to include applicable requirements relating to GHGs. The EPA has stated it will issue guidance later in 2010 on BACT for power plants, which may focus initially on energy efficiency requirements. These regulatory provisions may ultimately be nullified if Congress enacts GHG legislation that preempts regulations promulgated by the EPA. The EPAs effort to regulate GHG emissions through the CAA’s permitting programs has been appealed to the U.S. Court of Appeals for the District of Columbia Circuit.

In August 2007, Oregon enacted legislation establishing goals for the reduction of GHG emissions, which seek to (i) by 2010, cease the growth of Oregon GHG emissions; (ii) by 2020, reduce GHG levels to 10 percent below 1990 levels; and (iii) by 2050, reduce GHG levels to at least 75 percent below 1990 levels. The legislation also calls for state government-developed policy recommendations in the future to assist in the monitoring and achievement of these goals.

Idaho Power will continue to monitor and evaluate proposed international, federal, state, and regional GHG legislation or initiatives as well as judicial decisions that could affect its generating facilities and operations. A significant portion of the current initiatives regarding GHG emissions contemplate market-based compliance programs. The regulation of GHG emissions under the CAA could result in GHG emission limits on stationary sources that do not provide market-based compliance options such as cap-and-trade programs or emission offsets. Such a program could raise uncertainty about the future viability of fossil fuels, specifically coal, as an economical energy source for new and existing electric generation facilities because new technologies for reducing CO₂ emissions from coal, including carbon capture storage, are still in the development stage and are not yet proven. Emission standards could require significant increases in capital expenditures and operating costs, which may accelerate the retirement of older, less-efficient coal-fired units.

There are financial, regulatory, and logistical uncertainties related to GHG reductions and the implementation of renewable energy mandates. These will need to be resolved before the impact of such requirements on Idaho Power can be meaningfully estimated. The impact on Idaho Power of currently proposed legislation relating to GHG emissions would depend on a variety of factors, including the specific GHG emissions limits or renewable energy requirements, the timing of implementation of these limits or requirements, the level of emissions allowances allocated and the level that must be purchased, the purchase price of emissions allowances, the development and commercial availability of technologies for renewable energy and for the reduction of emissions, the degree to which offsets may be used for compliance, provisions for cost containment (if any), the impact on coal and natural

gas prices, and cost recovery through rates. Accordingly, Idaho Power cannot meaningfully predict the effect on its results of operations, financial position, or cash flows of any GHG emission, renewable energy mandate, or other global climate change requirements that may be adopted, although the costs to implement and comply with any such requirements could be substantial. Idaho Power would seek to recover these costs and expenditures from customers as costs of doing business but is unable to predict whether it would be permitted to recover some or all of the increased costs and expenditures from customers through rates.

However, to the extent GHG emissions are regulated through a federal GHG emissions program, Idaho Power believes its business could also benefit. Idaho Power’s generation fleet has an overall CO₂ emission rate that is lower than the industry average with a substantial amount of the fleet’s output coming from hydroelectric plants, which generate significantly lower CO₂ emissions than fossil fuel plants. Such regulatory initiatives may also lead to increased opportunities associated with renewable generation and alternative fuels.

In the 2009 IRP, Idaho Power did not include any new conventional coal resources in the resource portfolio due to the uncertainty regarding future GHG regulations. IDACORP and Idaho Power’s boards of directors continue to review environmental issues on a regular basis and in connection with the review of the companies’ strategic plans. The boards of directors are also frequently informed of any new material environmental issues, including updates on any proposed legislation.

Renewable Standards: The American Clean Energy and Security Act of 2009, in the form passed in the U.S. House of Representatives on June 26, 2009, would require utilities to obtain 20 percent of their electricity from renewable sources by 2020, and reduce demand an additional five percent through conservation and increased energy efficiency. The Senate version, if enacted, would require electric utilities to meet 15 percent of their electricity sales through renewable sources of energy or energy efficiency by 2021. Resources eligible to meet these standards include wind, solar, geothermal, biomass, landfill gas, ocean, and incremental hydropower (efficiency improvements or new capacity). Both bills recognize the benefits of existing hydroelectric generation by allowing utilities to subtract generation from existing hydroelectric projects from their total sales base prior to calculating the percentage requirement. Idaho Power will be required to comply with a ten percent renewable portfolio standard (RPS) in Oregon beginning in 2025. Idaho Power expects to meet these requirements with the REC’s from the Elkhorn Valley wind project. No RPS requirement currently exists in Idaho. Idaho Power continues to monitor proposed federal renewable energy standard (RES) legislation, which if passed could increase Idaho Power’s capital expenditures and operating costs and reduce earnings and cash flows.

Idaho Power has contracts to purchase energy from seven wind projects that have already achieved commercial operations. The combined nameplate rating of these projects is 192 MW. Idaho Power also has an additional 275 MW of wind generation with signed and IPUC approved contracts that have not yet been constructed. Idaho Power is currently negotiating a power purchase agreement for additional wind generation with a capacity of approximately 160 MW, pursuant to which Idaho Power would receive the RECs. Idaho Power recently entered into an agreement with USG Oregon, LLC for the purchase of energy from a geothermal electric generation facility under development near Vale, Oregon, with an estimated 22 MW output and expected on-line date of late 2012. Idaho Power has contracted to receive the RECs from the project during the term of the agreement. On June 8, 2010, Idaho Power entered into a 20 year PURPA power purchase agreement with Grand View Solar PV One, LLC. The solar power generation facility, which has not yet been constructed, is expected to have a 20-MW nameplate capacity and will be located in Elmore County, Idaho. A decision from the IPUC regarding the prudency of power purchase costs included in the agreement is pending. Idaho Power does not receive the RECs associated with PURPA projects and is selling its near-term RECs and returning to customers their share of those proceeds through the PCA. Idaho Power filed a REC Management Plan with the IPUC in December 2009 to address its treatment of future RECs. Under Idaho Power’s REC Management Plan, Idaho Power would sell near-term RECs, while continuing to acquire and hold long-term contractual rights to own RECs for use in meeting a future federal RES. During the six months ended June 30, 2010, Idaho Power’s REC sales totaled $2.2 million. Idaho Power has sold all of its 2009 and earlier vintage RECs. Idaho Power has sold a portion of its 2010 RECs and intends to continue selling its 2010 RECs as they are generated and become available for sale.

Idaho Power continues to pursue additional geothermal, wind, and combined heat and power generation resource development opportunities. Other renewable generation resources anticipated from future cogeneration and small power production contracts include solar, biomass, and additional wind projects.

Air Quality: Idaho Power co-owns three coal-fired power plants and owns two natural gas combustion turbine power plants that are subject to air quality regulation. The coal-fired plants are: Jim Bridger (33 percent interest) located in Wyoming; Boardman (10 percent interest) located in Oregon; and Valmy (50 percent interest) located in Nevada. The natural gas-fired plants, Danskin and Bennett Mountain, are located in Idaho. The CAA establishes controls on the emissions from stationary sources like those owned by Idaho Power. The EPA adopts many of the standards and regulations under the CAA, while states have the primary responsibility for implementation and administration of these air quality programs. In February 2010, a bill was introduced in the Senate to impose limits on SO₂ and NO_x emissions from power plants starting in 2012 and to require at least a 90 percent reduction in mercury emissions from coal-fired generation. Idaho Power continues to actively monitor, evaluate, and work on air quality issues pertaining to federal and state mercury emission rules, possible legislative amendment of the CAA as discussed above, National Ambient Air Quality Standards (NAAQS), and Regional Haze – Best Available Retrofit Technology (RH BART) and NSR permitting.

Idaho Power is currently in the process of constructing a natural gas-fired CCCT generating plant with a summer nameplate capacity of 300 MW and a winter capacity of approximately 330 MW in Payette County, Idaho, referred to as the Langley Gulch power plant. The Langley Gulch power plant is currently estimated to be in service in July 2012. On June 25, 2010, the Idaho Department of Environmental Quality issued to Idaho Power an air quality permit to construct the Langley Gulch power plant which imposes on Idaho Power, among other things, design, emissions monitoring, performance testing, reporting, and operating requirements, conditions, and limitations.

Mercury Emissions: Mercury continuous emission monitoring systems have been installed on all of the coal-fired units at the Jim Bridger, Boardman, and Valmy plants and tests to confirm the accuracy of the data being collected are currently underway. The EPA has announced that it is developing maximum achievable control technology (MACT) standards to reduce mercury emissions from coal-fired power plants. Early indications are that these MACT standards will apply uniformly to all coal-fired power plants, unlike the cap-and-trade mercury standards of the Clean Air Mercury Rule. In 2008, the State of Oregon adopted a mercury rule requiring Boardman to reduce mercury emissions by 90 percent or meet an emission rate of 0.6 lbs/trillion BTU by July 2012. Idaho Power continues to monitor Wyoming and Nevada actions related to mercury emissions. Idaho Power is unable to predict at this time what actions the EPA or the other states may take to reduce mercury emissions from its coal-fired power plants. In April 2010, the U.S. District Court for the District of Columbia approved, by consent decree, a timetable that would require the EPA to propose a standard to control mercury emissions from coal-fired power plants by May 16, 2011, and to finalize it by November 2011.

National Ambient Air Quality Standards (NAAQS): In July 1997, the EPA adopted new NAAQS for ozone (8-hour ozone standard) and fine particulate matter of less than 2.5 micrometers in diameter (PM2.5 standard). Regulations promulgated by the EPA to implement these NAAQS have been challenged and portions have been remanded back to the EPA for reconsideration. The EPA and state efforts to implement the NAAQS adopted in 1997 are ongoing. All of the counties in Idaho, Oregon, Nevada, and Wyoming where Idaho Power’s power plants operate currently are designated as meeting attainment with the 8-hour ozone and PM2.5 standards adopted by the EPA in 1997.

In December 2006, the EPA revised the NAAQS for PM2.5. This new standard was challenged by a number of groups in the U.S. Court of Appeals for the District of Columbia Circuit and the court remanded the standard back to the EPA in February 2009. All of the counties in Idaho, Nevada, Oregon and Wyoming where Idaho Power’s power plants operate currently were designated as meeting attainment with the revised PM2.5 NAAQS. The impact of the new standard will not be known until the judicial appeals are completed and the associated regulatory programs are promulgated and implemented.

In March 2008, the EPA promulgated a final regulation which revised the 8-hour ozone NAAQS, and on January 19, 2010, the EPA proposed to adopt a more stringent 8-hour ozone NAAQS. Idaho Power is unable to predict what impact the adoption of this standard may have on its operations.

On January 22, 2010, the EPA adopted a new NAAQS for NO2 at a level of 100 parts per billion averaged over a 1-hour period. In addition, on June 22, 2010, the EPA adopted a new NAAQS for SO2 at a level of 75 parts per billion average over a one-hour period. The EPA has not yet designated areas as attaining or not attaining these new

NAAQS. Idaho Power is unable to predict what impact the adoption and implementation of these standards may have on its operations.

Regional Haze – Best Available Retrofit Technology: In accordance with federal regional haze rules, coal-fired utility boilers are subject to RH BART if they were built between 1962 and 1977 and affect any Class I areas. This includes all four units at the Jim Bridger plant and the Boardman plant. The two units at the Valmy plant were constructed after 1977 and are not subject to the federal regional haze rule. The Wyoming Department of Environmental Quality (WDEQ) and the ODEQ have conducted assessments of the Boardman and Bridger plants pursuant to an RH BART process. These states have also evaluated the need for additional controls at Boardman and Bridger to achieve reasonable progress toward a long term strategy beyond RH BART to reduce regional haze in Class I areas to natural conditions by the year 2064.

On December 31, 2009, the WDEQ issued a RH BART permit to PacifiCorp for the Jim Bridger plant. The WDEQ determined that low NOx burners with over-fire air is RH BART for NOx for all four Bridger units and that RH BART is not required for SO2 for the Bridger plant. As part of the WDEQ’s long term strategy for regional haze, the permit requires that PacifiCorp install selective catalytic reduction (SCR) for NOx control at Bridger Units 3 and 4 by December 31, 2015 and December 31, 2016, respectively, and submit an application by January 15, 2015 to install add-on NOx controls at Bridger Units 1 and 2 by December 31, 2023. PacifiCorp is already in the process of installing low NOx burners and SO2 scrubber upgrades at the Bridger plant. The SO2 scrubber upgrade project has been completed on Bridger Units 2 and 4 and is expected to be completed on the other two units by the end of 2011. Idaho Power expects to spend approximately $22 million between 2009 and 2012 to complete these projects. Idaho Power’s estimated share of the cost to install SCR on Bridger Units 3 and 4 is $120 million. Installation of SCR also could require extended maintenance outages. Design and cost estimates for add-on NOx controls at Bridger Units 1 and 2 are not yet available. On February 26, 2010, PacifiCorp filed an administrative appeal of the Bridger RH BART permit with the Wyoming Environmental Quality Council. PacifiCorp contends that WDEQ lacked the legal and technical basis to require the SCR and add-on NOx controls required by the permit. Idaho Power will continue to monitor this process. It is not possible for Idaho Power to predict the outcome of the administrative appeals process at this time.

On June 19, 2009, the Oregon Environmental Quality Commission adopted a rule that would require the installation of controls at Boardman in two phases. The first phase, which ODEQ determined is RH BART, would require the installation of low NOx burners and over-fire air by July 1, 2011, and the installation of semi-dry flue gas desulfurization and a bag house by July 1, 2014. The second phase, which is part of ODEQ’s long term strategy, would require the installation of SCR by July 1, 2017. Idaho Power’s estimated share of the cost of the pollution control requirements for RH BART and the long term strategy is between approximately $52 million and $56 million. Approximately three-quarters of the costs would be incurred by 2014 with the remainder incurred by 2017. Installation of this pollution control equipment also could require extended maintenance outages.

On April 2, 2010, PGE submitted a petition requesting that the OEQC amend the RH BART and long term strategy requirements for the Boardman plant to be the installation of low NO_x burners and over-fire air by July 1, 2011, the phased transition to reduced sulfur coal by December 31, 2011 and July 1, 2014, and the closure of Boardman plant coal-fired boiler by December 31, 2020. However, on June 17, 2010, the OEQC denied PGE’s 2020 closure proposal and directed the ODEQ to explore additional options for early closure and initiate a rulemaking procedure. On June 28, 2010, the ODEQ stated that it would begin a public discussion of three draft closure options for the Boardman plant, in advance of formal rulemaking. The ODEQ’s three proposals contemplate early closure of the plant by 2020, 2018, or 2015-2016. The ODEQ stated that the capital cost of installing pollution control equipment for each of the options would be $321 million, $103 million, and $36 million, respectively. Each of the proposals would still require the Boardman plant to meet the current 2012 deadline for installing controls to meet the ODEQ’s mercury emission rules. The ODEQ stated that its rules would be written such that PGE could choose any option, and that if no option is selected by PGE the existing rules adopted last year, which the ODEQ stated will involve a capital cost of $498 million, would apply. Public meetings will be scheduled in September 2010 to discuss the proposals, and a final ruling is expected to be submitted to the OEQC in December 2010. Idaho Power is a ten percent owner of the Boardman plant, representing 64 MW of nameplate capacity. Idaho Power is evaluating and discussing with PGE the various options for early closure of the Boardman plant, as well as alternatives. At June 30, 2010, Idaho Power’s net book value in the Boardman plant was approximately $20 million with annual depreciation of approximately $1.2 million.

While not required under RH BART, installation of low NO_x burners and over-fired upgrades has been completed at the Valmy plant.

New Source Review: Since 1999, the EPA and the U.S. Department of Justice have been pursuing a national enforcement initiative focused on the compliance status of coal-fired power plants with the NSR permitting requirements and New Source Performance Standards (NSPS) of the CAA. This initiative has resulted in both enforcement litigation and significant settlements with a large number of public utilities and other owners of coal-fired power plants across the country. The current administration has indicated an intention to continue this NSR enforcement initiative. The EPA sent information requests under section 114 of the CAA, requesting information relevant to NSR and NSPS compliance to the Jim Bridger plant in 2003, the Valmy plant in 2009, and the Boardman plant in 2008 with a follow up request for information in 2009. Idaho Power is a co-owner of these plants, but does not operate the plants. A number of utilities that have received section 114 information requests have engaged in negotiations with the EPA to address any allegations of non-compliance with NSR and NSPS requirements. In some cases, such negotiations have resulted in settlements requiring the payment of civil penalties, installation of additional pollution controls, the surrender of emission allowances, and the completion of supplemental environmental projects. Idaho Power cannot predict the outcome of these investigatory and enforcement matters at this time.

Coal Combustion Byproducts (CCBs): In December 2008, the breach of a dike at the Tennessee Valley Authority’s Kingston Station resulted in a spill of several million cubic yards of ash into a nearby river and onto private properties. In June 2010, the EPA proposed regulations pursuant to the Resource Conservation and Recovery Act governing the disposal and management of CCBs. The EPA requested comments on two options for regulating CCBs. The first would regulate CCBs as a new “special waste” subject to many of the requirements for hazardous waste, while the second would regulate CCBs in a manner similar to typical solid waste, subject to fewer and less stringent environmental requirements. Either of the EPA’s proposed options represents a shift toward more comprehensive and potentially more expensive requirements for CCBs disposal and management. If this or other new legislation or regulations increase the cost of managing and disposing of CCBs or create additional liability with respect to historic disposal practices, they could have an adverse impact on Idaho Power’s consolidated financial position, results of operations, or cash flows. However, the financial and operational consequences cannot be determined until final legislation is passed or regulations enacted.

PCBs: In April 2010, the EPA issued an advance notice of proposed rulemaking pursuant to the Toxic Substances Control Act regarding the use of polychlorinated biphenyls (PCBs). The EPA is considering revisiting the use authorization allowing the continued use of PCBs in equipment. If new regulations require the replacement of existing equipment, they could have an adverse effect on Idaho Power’s consolidated financial position, results of operations, or cash flows. However, the financial and operational consequences cannot be determined until final regulations are enacted. Idaho Power currently records asset retirement obligation liabilities and associated regulatory assets for the estimated retirement costs of equipment containing PCBs. Proposed regulations could accelerate Idaho Power’s estimated timing of the retirements of equipment with PCBs.

Endangered Species:

Slickspot Peppergrass: This southwestern Idaho plant species was listed as threatened by the U.S. Fish and Wildlife Service (USFWS) effective December 2009. While critical habitat for the plant was not designated at the time of listing, approximately 98 percent of the plant species is located on federal land owned by the BLM and the Department of Defense. Parts of the Gateway West and Boardman to Hemingway 500 kV transmission lines and the Langley Gulch transmission and water lines will cross BLM land. This listing will add an additional requirement and species for consideration in the ESA section 7 consultation. A section 7 consultation is a process used to determine a proposed action’s effects on any ESA-listed species that may be within the project area. This listing may increase the expense and delay the timing of permitting for these projects.

Sage Grouse: On March 5, 2010, the USFWS announced that listing of the greater sage grouse as threatened or endangered under the ESA is warranted, but precluded by higher priority listing actions. The sage grouse is now considered a “candidate species” under the ESA, which allows land management agencies to implement additional conservation measures in an effort to prevent a formal ESA listing. Due to the presence of sage grouse in the

vicinity, siting of Idaho Power’s Boardman to Hemingway and Gateway West 500-kV transmission lines has required more extensive, costly, and time consuming evaluation and engineering. Newly proposed legislation in the State of Oregon relating to sage grouse may also adversely impact the project. Any required additional conservation measures may increase the costs of existing operations and impact the cost and timing of siting and permitting of the Boardman to Hemingway and Gateway West transmission lines, the Langley Gulch project, and other construction and transmission projects. Listing of the greater sage grouse as threatened or endangered under the ESA would add an additional requirement and species for consideration in ESA section 7 consultations for those projects, and may increase the expense and adversely affect the cost and timing of those projects.

Hells Canyon Project: In 2007, the FERC requested initiation of formal consultation under the ESA with the National Marine Fisheries Service (NMFS) and the USFWS regarding potential effects of HCC relicensing on several listed aquatic and terrestrial species. Formal consultation has not yet been initiated and NMFS and USFWS continue to gather and consider information relative to the effects of relicensing on relevant species. Idaho Power continues to cooperate with the USFWS, the NMFS, and the FERC in an effort to address ESA concerns. Idaho Power may be required to modify operations pursuant to the biological opinion that will result from formal consultation. However, the issuance of a final biological opinion within the next 18 to 24 months is unlikely.

Bliss and Lower Salmon Falls Projects: Idaho Power is finalizing a snail protection plan in cooperation with the USFWS. If the plan is approved by the FERC, Idaho Power will file applications with the FERC to amend the licenses for the Bliss and Lower Salmon Falls projects that will maintain operating flexibility at both projects for the remainder of their licenses.

OTHER MATTERS:

Critical Accounting Policies and Estimates

IDACORP’s and Idaho Power’s discussion and analysis of their financial condition and results of operations are based upon their condensed consolidated financial statements, which have been prepared in accordance with generally accepted accounting principles. The preparation of these financial statements requires IDACORP and Idaho Power 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 Idaho Power 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 Idaho Power, based on their ongoing reviews, make adjustments when facts and circumstances dictate.

IDACORP’s and Idaho Power’s critical accounting policies are reviewed by the Audit Committee of the boards of directors. These policies are discussed in more detail under “Critical Accounting Policies and Estimates” in the Annual Report on Form 10-K for the year ended December 31, 2009, and have not changed materially from that discussion.

Recently Issued Accounting Pronouncements

See Note 1 – “Summary of Significant Accounting Policies” to the condensed consolidated financial statements included in this report for a discussion of recently issued accounting pronouncements.

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

IDACORP and Idaho Power 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, 2010:

Interest Rate Risk

IDACORP’s and Idaho Power’s interest rate risk has not changed materially from that reported in Item 7A of the Annual Report on Form 10-K for the year ended December 31, 2009.

Commodity Price Risk

IDACORP’s and Idaho Power’s commodity price risk has not changed materially from that reported in Item 7A of the Annual Report on Form 10-K for the year ended December 31, 2009. Information regarding Idaho Power’s use of derivative instruments to manage commodity price risk can be found in Note 12 – “Derivative Financial Instruments” to the condensed consolidated financial statements included in this report.

Credit Risk

Idaho Power is subject to credit risk based on its activity with market counterparties. Idaho Power is exposed to this risk to the extent that a counterparty may fail to fulfill a contractual obligation to provide energy, purchase energy, or complete financial settlement for market activities. Idaho Power mitigates this exposure by actively establishing credit limits, measuring, monitoring, and reporting credit risk using appropriate contractual arrangements, and transferring of credit risk through the use of financial guarantees, cash or letters of credit. Idaho Power maintains a current list of acceptable counterparties and credit limits.

The use of performance assurance collateral in the form of cash, letters of credit, or guarantees is common industry practice. Idaho Power maintains margin agreements that allow performance assurance collateral to be requested of and/or posted with certain counterparties. As of June 30, 2010, Idaho Power had posted approximately $7 million of assurance collateral. Should Idaho Power experience a reduction in its credit rating on Idaho Power’s unsecured debt to below investment grade, Idaho Power could be subject to additional requests by its wholesale counterparties to post additional performance assurance collateral. Counterparties to derivative instruments and other forward contracts could request immediate payment or demand immediate ongoing full daily collateralization on derivative instruments and contracts in net liability positions. Based upon Idaho Power’s current energy and fuel portfolio and current market conditions as of June 30, 2010, the approximate amount of additional collateral that could be requested upon a downgrade is approximately $23 million. Idaho Power actively monitors the portfolio exposure and the potential exposure to additional requests for performance assurance collateral calls, through sensitivity analysis, to minimize capital requirements.

Idaho Power’s credit risk related to uncollectible accounts has not changed materially from that reported in Item 7A of the Annual report on Form 10-K for the year ended December 31, 2009.

Equity Price Risk

IDACORP’s and Idaho Power’s equity price risk has not changed materially from that reported in Item 7A of the Annual Report on Form 10-K for the year ended December 31, 2009.

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, 2010, have concluded that IDACORP’s disclosure controls and procedures are effective as of that date.

Idaho Power: The Chief Executive Officer and the Chief Financial Officer of Idaho Power, based on their evaluation of Idaho Power’s disclosure controls and procedures (as defined in Exchange Act Rule 13a-15(e)) as of June 30, 2010, have concluded that Idaho Power’s disclosure controls and procedures are effective as of that date.

Changes in Internal Control Over Financial Reporting

There have been no changes in IDACORP’s or Idaho Power’s internal control over financial reporting during the quarter ended June 30, 2010, that have materially affected, or are reasonably likely to materially affect, IDACORP’s or Idaho Power’s internal control over financial reporting.

PART II – OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS

Please refer to Note 9 - “Contingencies” to the condensed consolidated financial statements included in this report.

ITEM 1A. RISK FACTORS

In addition to the other information set forth in this report, you should carefully consider the factors discussed in Part I - Item 1A - “Risk Factors” in IDACORP’s and Idaho Power Company’s Annual Report on Form 10-K for the year ended December 31, 2009, as supplemented by the discussion below, which could materially affect IDACORP’s and Idaho Power’s business, financial condition, or future results. The following are updates to the risk factors reported in the Annual Report on Form 10-K for the year ended December 31, 2009.

If the Idaho Public Utilities Commission, the Oregon Public Utility Commission or the Federal Energy Regulatory Commission grant less rate recovery in rate case filings than Idaho Power Company needs to cover its costs of providing services, earnings and cash flows may be reduced. The prices that the Idaho Public Utilities Commission and Oregon Public Utility Commission authorize Idaho Power Company to charge for its retail services and the tariff rate that the Federal Energy Regulatory Commission permits Idaho Power Company to charge for transmission, are major factors in determining IDACORP’s and Idaho Power Company’s operating income and financial position. The Idaho Public Utilities Commission and Oregon Public Utility Commission have the authority to disallow recovery of any costs that they consider unreasonable or imprudently incurred, and the Federal Energy Regulatory Commission formula rates may be insufficient for recovery of costs incurred. While the Idaho Public Utilities Commission and Oregon Public Utility Commission have established through the ratemaking process an authorized rate of return for Idaho Power Company, the regulatory process does not provide assurance that Idaho Power Company will be able to achieve the earnings level authorized. Further, while the Idaho Public Utilities Commission and Oregon Public Utility Commission are required to establish rates that are fair, just, and reasonable, they have significant discretion in determining the application of this standard.

In January 2010, the Idaho Public Utilities Commission approved a settlement agreement that imposed a general rate moratorium in effect until January 1, 2012. While the moratorium does not apply to other specified revenue requirement proceedings, such as the power cost adjustment, the fixed cost adjustment, pension funding, advanced metering infrastructure, energy efficiency rider, and government imposed fees, Idaho Power Company attempts to manage its costs consistent with the moratorium. However, if Idaho Power Company is unable to do so, or if such cost management results in increased operational risk, the moratorium could adversely affect Idaho Power Company’s operations or results of operations.

In its Oregon jurisdiction, Idaho Power Company utilizes a power cost adjustment mechanism by which it can adjust future prices to reflect a portion of the difference between each year’s forecasted and actual net variable power costs. Use of the approved cost sharing methodology requires that Idaho Power Company absorb certain power cost increases before it is allowed to recover any amount from customers, with the range of deviations in which Idaho Power Company absorbs the cost increases or decreases referred to as a “deadband.” Accordingly, the power cost adjustment mechanism only partially offsets the potentially adverse financial impacts of forced generating plant outages, severe weather, reduced hydro generating availability, and volatile wholesale energy prices.

If the Idaho Public Utilities Commission or Oregon Public Utility Commission grant less rate recovery in rate case filings than Idaho Power Company needs to cover its costs, or if the Federal Energy Regulatory Commission makes changes to the formula rates for transmission tariffs, it may reduce earnings and cash flows.

Conditions that may be imposed in connection with hydroelectric license renewals may require large capital expenditures, increase operating costs, reduce hydroelectric production, and reduce earnings and cash flows. Idaho Power Company is currently involved in renewing federal licenses for some of its hydroelectric projects, including its largest hydroelectric generation source, the Hells Canyon Complex. Relicensing includes an extensive public review process that involves numerous natural resource issues and environmental conditions. The listing of various species of salmon, wildlife, and plants as threatened or endangered has resulted in significant changes to federally-authorized activities, including those of hydroelectric projects. Salmon recovery plans could include further major operational changes to the region’s hydroelectric projects. In addition, new interpretations of existing laws and regulations could be adopted or become applicable to such facilities, which could further increase required expenditures for salmon recovery and endangered species protection and reduce the amount of hydroelectric generation available to meet Idaho Power Company’s energy requirements.

In 2007, the Federal Energy Regulatory Commission Staff issued a final environmental impact statement for the Hells Canyon Complex, which Idaho Power expects Federal Energy Regulatory Commission will use to determine whether, and under what conditions, to issue a new license for the Hells Canyon Complex. Certain portions of the final environmental impact statement involve issues that may be influenced by water quality certifications for the project under section 401 of the Clean Water Act and formal consultations under the Endangered Species Act, which remain unresolved. One significant issue involves water temperature gradients, and certain interested parties in the Hells Canyon Complex relicensing proceedings have proposed the installation of water temperature management apparatus which, if required to be installed, would likely require substantial capital expenditures to construct and maintain. There can be no assurance that recovery through rates would be authorized, particularly given the magnitude of any potential impact on customer rates, which at this time cannot be accurately predicted. Idaho Power Company cannot predict the requirements that might be imposed during the relicensing process, the economic impact of those requirements, or whether a new license will ultimately be issued. Imposition of onerous conditions in the relicensing process could have a material adverse effect on Idaho Power Company’s operations, require large capital expenditures, increase operating costs, reduce hydroelectric production, and reduce earnings and cash flows.

Idaho Power Company’s business is subject to substantial governmental regulation and may be adversely affected by increased costs resulting from, or liability under, existing or future regulations or requirements. Idaho Power Company is subject to extensive federal and state laws, policies, and regulations, as well as regulatory actions and regulatory audits, including those of the Federal Energy Regulatory Commission, the Environmental Protection Agency, the North American Electric Reliability Corporation, the Western Electricity Coordinating Council, and the public utility commissions in Idaho, Oregon, and Wyoming. Some of these regulations are changing or subject to interpretation, and failure to comply may result in penalties or other adverse consequences. Idaho Power Company has self-reported compliance issues to the Federal Energy Regulatory Commission and to the Western Electricity Coordinating Council, and the Western Electricity Coordinating Council has recently completed an audit of reliability standards. Several of the matters self-reported to the Federal Energy Regulatory Commission and the Western Electricity Coordinating Council remain outstanding. Compliance with these requirements directly influences Idaho Power’s operating environment and may significantly increase Idaho Power’s operating costs. Further, potential monetary and non-monetary penalties for violation of Federal Energy Regulatory Commission regulations may be substantial, and in some circumstances monetary penalties may be as high as $1 million per day per violation. The imposition of penalties on Idaho Power Company could have an adverse impact on Idaho Power Company’s and IDACORP’s results of operations, financial condition, and cash flows.

Recent negative publicity in the energy sector may result in public opposition to Idaho Power Company’s power generation and transmission projects and increased environmental and other regulations, which may adversely impact IDACORP’s and Idaho Power Company’s results of operations, financial condition, and cash flows. The energy sector in general has been the subject of negative publicity, most recently in the context of the dialogue regarding factors contributing to climate change and the sourcing of fuels. Idaho Power Company, in particular, has faced public opposition in connection with its transmission expansion initiatives and ordinary utility rate increases. Negative publicity and public opposition of this nature may make legislators, regulators, and courts, whether as a result of public opposition or otherwise, less likely to take a favorable view of energy companies in general or Idaho Power Company specifically, which could cause them to make decisions or take actions that are adverse to Idaho Power Company. In addition to the direct costs Idaho Power Company may incur as a result of any such new environmental laws and regulations, the increased costs incurred by other energy and natural resource companies as a result of complying with new environmental laws and regulations may increase the cost of purchasing power in the wholesale markets, which could adversely impact Idaho Power Company’s results of operations, financial condition, and cash flows.

Idaho Power Company’s ability to enter into over-the-counter derivatives and hedge commodity and interest rate risk may be adversely affected by recent federal legislation. In July 2010, Congress enacted, and President Obama signed, financial reform legislation known as the Dodd-Frank Wall Street Reform and Consumer Protection Act. Title VII of the legislation provides for the regulation of the over-the-counter derivatives market, and requires the posting of cash collateral for uncleared swaps. If the rules enacted under the legislation require that Idaho Power Company post cash collateral on its swap transactions, its liquidity may be adversely affected, and rules promulgated under the legislation may limit Idaho Power Company’s ability to enter into over-the-counter derivatives to hedge commodity and interest rate risks.

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

Restrictions on Dividends

A covenant under IDACORP’s credit facility and Idaho Power’s credit facility requires IDACORP and Idaho Power to maintain leverage ratios of consolidated indebtedness to consolidated total capitalization, as defined therein, of no more than 65 percent at the end of each fiscal quarter. Idaho Power’s Revised Code of Conduct approved by the IPUC on April 21, 2008, states that Idaho Power will not pay any dividends to IDACORP that will reduce Idaho Power’s common equity capital below 35 percent of its total adjusted capital without IPUC approval. Idaho Power’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 violate the covenants or Idaho Power’s Revised Code of Conduct.

Idaho Power’s articles of incorporation contain restrictions on the payment of dividends on its common stock if preferred stock dividends are in arrears. Idaho Power has no preferred stock outstanding. Further, Idaho Power must obtain approval of the OPUC before it could directly or indirectly loan funds or issue notes or give credit on its books to IDACORP.

See Note 6 - “Common Stock” to the condensed consolidated financial statements included in this report for a further discussion of restrictions on IDACORP’s and Idaho Power’s payment of dividends.

Idaho Power must obtain approval of the OPUC before it could directly or indirectly loan funds or issue notes or give credit on its books to IDACORP.

Issuer Purchases of Equity Securities

During the quarter ended June 30, 2010, IDACORP effected the following repurchases of its common stock:

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

April 1 – April 30, 2010		459	$	36.08	-	-
May 1 – May 31, 2010		-		-	-	-
June 1 – June 30, 2010		-		-	-	-
	Total	459	$	36.08	-	-

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

ITEM 6. EXHIBITS

Exhibit No.	Description

*4.11	Idaho Power Company Forty-sixth Supplemental Indenture to Mortgage and Deed of Trust, dated as of June 1, 2010. File number 1-3198, Form 8-K, filed on 6/18/2010 as Exhibit 4.
4.12	Idaho Power Company Instrument of Further Assurance relating to Mortgage and Deed of Trust, dated as of August 3, 2010.
*10.31¹	IDACORP, Inc. Executive Incentive Plan, as amended March 18, 2010 and approved May 20, 2010. File number 1-14465, 1-3198, Form 8-K, filed on 5/21/2010 as Exhibit 10.1.
10.66¹	IDACORP, Inc. and/or Idaho Power Company Executive Officers with Amended and Restated Change in Control Agreements Chart, as of June 30, 2010.
10.69	Joint Purchase and Sale Agreement, dated April 30, 2010, by and between Idaho Power Company and PacifiCorp.
10.70	Hemingway Joint Ownership and Operating Agreement, dated May 3, 2010, by and between Idaho Power Company and PacifiCorp.
10.71	Populus Joint Ownership and Operating Agreement, dated May 3, 2010, by and between Idaho Power Company and PacifiCorp.
12.1	IDACORP, Inc. Computation of Ratio of Earnings to Fixed Charges and Supplemental Ratio of Earnings to Fixed Charges.
12.2	Idaho Power Company Computation of Ratios of Earnings to Fixed Charges and Supplemental Ratio of Earnings to Fixed Charges.
15.1	Letter Re: Unaudited Interim Financial Information.
31.1	IDACORP, Inc. Rule 13a-14(a) CEO certification.
31.2	IDACORP, Inc. Rule 13a-14(a) CFO certification.
31.3	Idaho Power Rule 13a-14(a) CEO certification.
31.4	Idaho Power Rule 13a-14(a) CFO certification.
32.1	IDACORP, Inc. Section 1350 CEO certification.
32.2	IDACORP, Inc. Section 1350 CFO certification.
32.3	Idaho Power Section 1350 CEO certification.
32.4	Idaho Power Section 1350 CFO certification.
99.1	Earnings press release for the second quarter 2010.
101.INS²	XBRL Instance Document
101.SCH²	XBRL Taxonomy Extension Schema Document
101.CAL²	XBRL Taxonomy Extension Calculation Linkbase Document
101.DEF²	XBRL Taxonomy Extension Definition Linkbase Document
101.LAB²	XBRL Taxonomy Extension Label Linkbase Document
101.PRE²	XBRL Taxonomy Extension Presentation Linkbase Document

* Previously filed and incorporated herein by reference
¹ Management contract or compensatory plan or arrangement
²Includes data files for the following materials from the quarterly report on Form 10-Q of IDACORP, Inc. for the interim period ended June 30, 2010, formatted in Extensible Business Reporting Language (XBRL): (i) the Condensed Consolidated Statements of Income; (ii) the Condensed Consolidated Balance Sheets; (iii) the Condensed Consolidated Statements of Cash Flows; (iv) the Condensed Consolidated Statements of Comprehensive Income; (v) the Condensed Consolidated Statements of Equity; and (vi) the Notes to Condensed Consolidated Financial Statements tagged as blocks of text. Pursuant to Rule 406T of SEC Regulation S-T, these interactive data files are deemed not filed or part of a registration statement or prospectus for purposes of Sections 11 or 12 of the Securities Act of 1933, are deemed not filed for purposes of Section 18 of the Securities Exchange Act of 1934 and otherwise are not subject to liability under those sections. These files are being furnished only by IDACORP, Inc. and not by its subsidiary, Idaho Power Company.

SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrants have duly caused this report to be signed on their behalf by the undersigned thereunto duly authorized.

		IDACORP, INC.
		(Registrant)



Date:	August 5, 2010	By:	/s/ J. LaMont Keen
			J. LaMont Keen
			President and Chief Executive Officer

Date:	August 5, 2010	By:	/s/ Darrel T. Anderson
			Darrel T. Anderson
			Executive Vice President - Administrative
			Services and Chief Financial Officer





		IDAHO POWER COMPANY
		(Registrant)



Date:	August 5, 2010	By:	/s/ J. LaMont Keen
			J. LaMont Keen
			President and Chief Executive Officer

Date:	August 5, 2010	By:	/s/ Darrel T. Anderson
			Darrel T. Anderson
			Executive Vice President - Administrative
			Services and Chief Financial Officer

EXHIBIT INDEX

Exhibit No.	Description

4.12	Idaho Power Company Instrument of Further Assurance relating to Mortgage and Deed of Trust, dated as of August 3, 2010.
10.66¹	IDACORP, Inc. and/or Idaho Power Company Executive Officers with Amended and Restated Change in Control Agreements Chart, as of June 30, 2010.
10.69	Joint Purchase and Sale Agreement, dated April 30, 2010, by and between Idaho Power Company and PacifiCorp.
10.70	Hemingway Joint Ownership and Operating Agreement, dated May 3, 2010, by and between Idaho Power Company and PacifiCorp.
10.71	Populus Joint Ownership and Operating Agreement, dated May 3, 2010, by and between Idaho Power Company and PacifiCorp.
12.1	IDACORP, Inc. Computation of Ratio of Earnings to Fixed Charges and Supplemental Ratio of Earnings to Fixed Charges.
12.2	Idaho Power Company Computation of Ratios of Earnings to Fixed Charges and Supplemental Ratio of Earnings to Fixed Charges.
15.1	Letter Re: Unaudited Interim Financial Information.
31.1	IDACORP, Inc. Rule 13a-14(a) CEO certification.
31.2	IDACORP, Inc. Rule 13a-14(a) CFO certification.
31.3	Idaho Power Rule 13a-14(a) CEO certification.
31.4	Idaho Power Rule 13a-14(a) CFO certification.
32.1	IDACORP, Inc. Section 1350 CEO certification.
32.2	IDACORP, Inc. Section 1350 CFO certification.
32.3	Idaho Power Section 1350 CEO certification.
32.4	Idaho Power Section 1350 CFO certification.
99.1	Earnings press release for the second quarter 2010.
101.INS²	XBRL Instance Document.
101.SCH²	XBRL Taxonomy Extension Schema Document.
101.CAL²	XBRL Taxonomy Extension Calculation Linkbase Document.
101.DEF²	XBRL Taxonomy Extension Definition Linkbase Document.
101.LAB²	XBRL Taxonomy Extension Label Linkbase Document.
101.PRE²	XBRL Taxonomy Extension Presentation Linkbase Document.

¹ Management contract or compensatory plan or arrangement
²Includes data files for the following materials from the quarterly report on Form 10-Q of IDACORP, Inc. for the interim period ended June 30, 2010, formatted in Extensible Business Reporting Language (XBRL): (i) the Condensed Consolidated Statements of Income; (ii) the Condensed Consolidated Balance Sheets; (iii) the Condensed Consolidated Statements of Cash Flows; (iv) the Condensed Consolidated Statements of Comprehensive Income; (v) the Condensed Consolidated Statements of Equity; and (vi) the Notes to Condensed Consolidated Financial Statements tagged as blocks of text. Pursuant to Rule 406T of SEC Regulation S-T, these interactive data files are deemed not filed or part of a registration statement or prospectus for purposes of Sections 11 or 12 of the Securities Act of 1933, are deemed not filed for purposes of Section 18 of the Securities Exchange Act of 1934 and otherwise are not subject to liability under those sections. These files are being furnished only by IDACORP, Inc. and not by its subsidiary, Idaho Power Company.