Edgar Filing: IDAHO POWER CO

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UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D. C. 20549

FORM 10-Q

(Mark One)



X	QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
	EXCHANGE ACT OF 1934
	For the quarterly period ended March 31, 2011
	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
		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 April 29, 2011:
IDACORP, Inc.:	49,560,876
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 report on Form 10-Q with the reduced disclosure format.



COMMONLY USED TERMS

The following select abbreviations or acronyms are commonly used in this report:

ADITC	-	Accumulated Deferred Investment Tax Credits
AFUDC	-	Allowance for Funds Used During Construction
AMI	-	Advanced Metering Infrastructure
APCU	-	Annual Power Cost Update
BCC	-	Bridger Coal Company, a joint venture of IERCo
BLM	-	United States Bureau of Land Management
CAA	-	Clean Air Act
Cal ISO	-	California Independent System Operator
CalPX	-	California Power Exchange
CAMP	-	Comprehensive Aquifer Management Plan
EPA	-	United States Environmental Protection Agency
EPS	-	Earnings per share
ESPA	-	Eastern Snake Plain Aquifer
FCA	-	Fixed Cost Adjustment mechanism
FERC	-	Federal Energy Regulatory Commission
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
IRS	-	Internal Revenue Service
kW	-	Kilowatt
LCAR	-	Load Change Adjustment Rate
MD&A	-	Management’s Discussion and Analysis of Financial Condition and Results of Operations
MW	-	Megawatt
MWh	-	Megawatt-hour
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
RES	-	Renewable Energy Standard
SEC	-	Securities and Exchange Commission
SO₂	-	Sulfur Dioxide
SRBA	-	Snake River Basin Adjudication
USBR	-	United States Bureau of Reclamation
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
			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
			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
		Reports of Independent Registered Public Accounting Firm		33

	Item 2. Management’s Discussion and Analysis of Financial Condition and Results of
			Operations	35

	Item 3. Quantitative and Qualitative Disclosures About Market Risk			60

	Item 4. Controls and Procedures			61

Part II. Other Information:

	Item 1. Legal Proceedings			61

	Item 1A. Risk Factors			61

	Item 2. Unregistered Sales of Equity Securities and Use of Proceeds			62

	Item 5. Other Information			62

	Item 6. Exhibits			64

Signatures				65

Exhibit Index				66

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 STATEMENTS,” and in IDACORP, Inc.'s and Idaho Power Company's Annual Report on Form 10-K for the year ended December 31, 2010, at Part I, Item 1A - “RISK FACTORS” and Part II, Item 7 - “MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS.” 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,” “targets,” “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 March 31,
	2011			2010
	(thousands of dollars except for per share amounts)
Operating Revenues:
Electric utility:
General business	$	203,272		$	203,745
Off-system sales	29,845			34,406
Other revenues	17,945			14,309
Total electric utility revenues	251,062			252,460
Other	432			503
Total operating revenues	251,494			252,963
Operating Expenses:
Electric utility:
Purchased power	25,094			21,174
Fuel expense	29,902			37,187
Power cost adjustment	31,306			48,324
Other operations and maintenance	70,661			72,094
Energy efficiency programs	6,711			5,034
Depreciation	29,464			28,583
Taxes other than income taxes	7,211			5,680
Total electric utility expenses	200,349			218,076
Other	1,054			840
Total operating expenses	201,403			218,916
Operating Income	50,091			34,047
Other Income, Net	4,538			4,481
Losses of Unconsolidated Equity-Method Investments	(1,294		)	(2,378		)
Interest Expense:
Interest on long-term debt	20,847			19,441
Other interest, net of AFUDC	(1,888		)	(453		)
Total interest expense, net	18,959			18,988
Income Before Income Taxes	34,376			17,162
Income Tax Expense	4,888			1,305
Net Income	29,488			15,857
Adjustment for loss attributable to noncontrolling interests	252			206
Net Income Attributable to IDACORP, Inc.	$	29,740		$	16,063
Weighted Average Common Shares Outstanding - Basic (000’s)	49,290			47,773
Weighted Average Common Shares Outstanding - Diluted (000’s)	49,356			47,885
Earnings Per Share of Common Stock:
Earnings Attributable to IDACORP, Inc. - Basic	$	0.60		$	0.34
Earnings Attributable to IDACORP, Inc. - Diluted	$	0.60		$	0.34
Dividends Declared Per Share of Common Stock	$	0.30		$	0.30

The accompanying notes are an integral part of these statements.

IDACORP, Inc.

Condensed Consolidated Balance Sheets

(unaudited)



	March 31, 2011			December 31, 2010
Assets	(thousands of dollars)
Current Assets:
Cash and cash equivalents	$	93,941		$	228,677
Receivables:
Customer (net of allowance of $1,463 and $1,499, respectively)	66,634			62,114
Other (net of allowance of $142 and $1,471, respectively)	13,426			10,157
Income taxes receivable	—			12,130
Accrued unbilled revenues	41,592			47,964
Materials and supplies (at average cost)	45,871			45,601
Fuel stock (at average cost)	33,595			27,547
Prepayments	9,197			11,063
Deferred income taxes	9,537			10,715
Current regulatory assets	21,726			6,216
Other	1,294			1,854
Total current assets	336,813			464,038
Investments	202,605			202,944
Property, Plant and Equipment:
Utility plant in service	4,354,554			4,332,054
Accumulated provision for depreciation	(1,633,509		)	(1,614,013		)
Utility plant in service - net	2,721,045			2,718,041
Construction work in progress	485,249			416,950
Utility plant held for future use	7,081			7,076
Other property, net of accumulated depreciation	19,209			19,315
Property, plant and equipment - net	3,232,584			3,161,382
Other Assets:
American Falls and Milner water rights	20,796			22,120
Company-owned life insurance	26,676			26,672
Regulatory assets	723,850			753,172
Long-term receivables (net of allowance of $3,227 and $1,861, respectively)	5,149			3,965
Other	41,775			41,762
Total other assets	818,246			847,691
Total	$	4,590,248		$	4,676,055

The accompanying notes are an integral part of these statements.

IDACORP, Inc.

Condensed Consolidated Balance Sheets

(unaudited)



	March 31, 2011			December 31, 2010
Liabilities and Equity	(thousands of dollars)
Current Liabilities:
Current maturities of long-term debt	$	1,667		$	122,572
Notes payable	74,100			66,900
Accounts payable	64,569			103,100
Income taxes accrued	4,146			—
Interest accrued	23,812			23,937
Uncertain tax positions	73,700			74,436
Current regulatory liabilities	20,669			8,011
Other	68,679			50,103
Total current liabilities	331,342			449,059
Other Liabilities:
Deferred income taxes	577,591			566,473
Regulatory liabilities	296,768			298,094
Other	343,666			338,158
Total other liabilities	1,218,025			1,202,725
Long-Term Debt	1,487,305			1,488,287
Commitments and Contingencies
Equity:
IDACORP, Inc. shareholders’ equity:
Common stock, no par value (shares authorized 120,000,000; 49,555,756 and 49,419,452 shares issued, respectively)	809,974			807,842
Retained earnings	748,764			733,879
Accumulated other comprehensive loss	(8,781		)	(9,568		)
Treasury stock (1,103 and 14,302 shares at cost, respectively)	—			(40		)
Total IDACORP, Inc. shareholders’ equity	1,549,957			1,532,113
Noncontrolling interest	3,619			3,871
Total equity	1,553,576			1,535,984
Total	$	4,590,248		$	4,676,055

The accompanying notes are an integral part of these statements.

IDACORP, Inc.

Condensed Consolidated Statements of Cash Flows

(unaudited)



	Three months ended March 31,
	2011			2010
Operating Activities:	(thousands of dollars)
Net income	$	29,488		$	15,857
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization	31,592			30,435
Deferred income taxes and investment tax credits	1,266			(23,118		)
Changes in regulatory assets and liabilities	35,850			52,036
Pension and postretirement benefit plan expense	4,553			2,796
Contributions to pension and postretirement benefit plans	(593		)	(1,561		)
Losses of unconsolidated equity-method investments	1,294			2,378
Allowance for other funds used during construction	(5,329		)	(3,659		)
Other non-cash adjustments to net income, net	724			471
Change in:
Accounts receivable and prepayments	(4,774		)	4,629
Accounts payable and other accrued liabilities	(26,910		)	(29,144		)
Taxes accrued/receivable	22,665			29,706
Other current assets	54			12,385
Other current liabilities	8,440			13,733
Other assets	(109		)	(1,782		)
Other liabilities	(4,992		)	(4,712		)
Net cash provided by operating activities	93,219			100,450
Investing Activities:
Additions to property, plant and equipment	(101,880		)	(69,029		)
Proceeds from the sale of emission allowances and RECs	2,055			666
Investments in affordable housing	(905		)	(2,480		)
Investments in unconsolidated affiliates	(300		)	(2,200		)
Other	1,026			2,265
Net cash used in investing activities	(100,004		)	(70,778		)
Financing Activities:
Retirement of long-term debt	(121,064		)	(1,064		)
Dividends on common stock	(15,147		)	(14,475		)
Net change in short-term borrowings	7,200			(27,650		)
Issuance of common stock	2,215			3,130
Acquisition of treasury stock	(1,904		)	(829		)
Other	749			(335		)
Net cash used in financing activities	(127,951		)	(41,223		)
Net decrease in cash and cash equivalents	(134,736		)	(11,551		)
Cash and cash equivalents at beginning of the period	228,677			52,987
Cash and cash equivalents at end of the period	$	93,941		$	41,436
Supplemental Disclosure of Cash Flow Information:
Cash paid (received) during the period for:
Income taxes	$	(12,700	)	$	(1,367	)
Interest (net of amount capitalized)	$	18,430		$	13,021
Non-cash investing activities:
Additions to property, plant and equipment in accounts payable	$	24,641		$	17,882
Investments in affordable housing	$	—		$	4,828

The accompanying notes are an integral part of these statements.

IDACORP, Inc.

Condensed Consolidated Statements of Comprehensive Income

(unaudited)



	Three months ended March 31,
	2011		2010
	(thousands of dollars)
Net Income	$	29,488	$	15,857
Other Comprehensive Income:
Net unrealized holding gains arising during the period, net of tax of $355 and $267	553		416
Unfunded pension liability adjustment, net of tax of $150 and $114	234		177
Total Comprehensive Income	30,275		16,450
Comprehensive loss attributable to noncontrolling interests	252		206
Comprehensive Income Attributable to IDACORP, Inc.	$	30,527	$	16,656

The accompanying notes are an integral part of these statements.

IDACORP, Inc.

Condensed Consolidated Statements of Equity

(unaudited)



	Three months ended March 31,
	2011			2010
	(thousands of dollars)
Common Stock
Balance at beginning of period	$	807,842		$	756,475
Issued	2,215			3,130
Other	(83		)	181
Balance at end of period	809,974			759,786
Retained Earnings
Balance at beginning of period	733,879			649,180
Net income attributable to IDACORP, Inc.	29,740			16,063
Common stock dividends ($0.30 per share)	(14,855		)	(14,409		)
Balance at end of period	748,764			650,834
Accumulated Other Comprehensive Income (Loss)
Balance at beginning of period	(9,568		)	(8,267		)
Unrealized gain on securities (net of tax)	553			416
Unfunded pension liability adjustment (net of tax)	234			177
Balance at end of period	(8,781		)	(7,674		)
Treasury Stock
Balance at beginning of period	(40		)	(53		)
Issued	1,944			882
Acquired	(1,904		)	(829		)
Balance at end of period	—			—
Total IDACORP, Inc. shareholders’ equity at end of period	1,549,957			1,402,946
Noncontrolling Interests
Balance at beginning of period	3,871			4,209
Net loss attributable to noncontrolling interest	(252		)	(206		)
Balance at end of period	3,619			4,003
Total equity at end of period	$	1,553,576		$	1,406,949

The accompanying notes are an integral part of these statements.

Idaho Power Company

Condensed Consolidated Statements of Income

(unaudited)



	Three months ended March 31,
	2011			2010
	(thousands of dollars)
Operating Revenues:
General business	$	203,272		$	203,745
Off-system sales	29,845			34,406
Other revenues	17,945			14,309
Total operating revenues	251,062			252,460
Operating Expenses:
Operation:
Purchased power	25,094			21,174
Fuel expense	29,902			37,187
Power cost adjustment	31,306			48,324
Other operations and maintenance	70,661			72,094
Energy efficiency programs	6,711			5,034
Depreciation	29,464			28,583
Taxes other than income taxes	7,211			5,680
Total operating expenses	200,349			218,076
Income from Operations	50,713			34,384
Other Income (Expense):
Allowance for equity funds used during construction	5,329			3,659
Earnings of unconsolidated equity-method investments	858			348
Other (expense) income, net	(1,013		)	239
Total other income	5,174			4,246
Interest Charges:
Interest on long-term debt	20,847			19,441
Other interest	1,213			854
Allowance for borrowed funds used during construction	(3,214		)	(2,192		)
Total interest charges	18,846			18,103
Income Before Income Taxes	37,041			20,527
Income Tax Expense	7,193			2,306
Net Income	$	29,848		$	18,221

The accompanying notes are an integral part of these statements.

Idaho Power Company

Condensed Consolidated Balance Sheets

(unaudited)



	March 31, 2011			December 31, 2010
Assets	(thousands of dollars)
Electric Plant:
In service (at original cost)	$	4,354,554		$	4,332,054
Accumulated provision for depreciation	(1,633,509		)	(1,614,013		)
In service - net	2,721,045			2,718,041
Construction work in progress	485,249			416,950
Held for future use	7,081			7,076
Electric plant - net	3,213,375			3,142,067
Investments and Other Property	122,459			120,641
Current Assets:
Cash and cash equivalents	91,018			224,233
Receivables:
Customer (net of allowance of $1,463 and $1,499, respectively)	66,634			62,114
Other (net of allowance of $142 and $142, respectively)	13,305			8,835
Income taxes receivable	—			21,063
Accrued unbilled revenues	41,592			47,964
Materials and supplies (at average cost)	45,871			45,601
Fuel stock (at average cost)	33,595			27,547
Prepayments	8,948			10,910
Deferred income taxes	6,156			7,334
Current regulatory assets	21,726			6,216
Other	1,294			1,238
Total current assets	330,139			463,055
Deferred Debits:
American Falls and Milner water rights	20,796			22,120
Company-owned life insurance	26,676			26,672
Regulatory assets	723,850			753,172
Other	40,793			40,666
Total deferred debits	812,115			842,630
Total	$	4,478,088		$	4,568,393

The accompanying notes are an integral part of these statements.

Idaho Power Company

Condensed Consolidated Balance Sheets

(unaudited)



	March 31, 2011			December 31, 2010
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	688,758			688,758
Capital stock expense	(2,097		)	(2,097		)
Retained earnings	645,154			630,259
Accumulated other comprehensive loss	(8,781		)	(9,568		)
Total common stock equity	1,420,911			1,405,229
Long-term debt	1,487,305			1,488,287
Total capitalization	2,908,216			2,893,516
Current Liabilities:
Long-term debt due within one year	1,064			121,064
Accounts payable	64,154			102,474
Accounts payable to related parties	435			1,110
Income taxes accrued	6,190			—
Interest accrued	23,812			23,930
Uncertain tax positions	73,700			74,436
Current regulatory liabilities	20,669			8,011
Other	68,217			48,733
Total current liabilities	258,241			379,758
Deferred Credits:
Deferred income taxes	673,275			661,165
Regulatory liabilities	296,768			298,094
Other	341,588			335,860
Total deferred credits	1,311,631			1,295,119

Commitments and Contingencies

Total	$	4,478,088		$	4,568,393

The accompanying notes are an integral part of these statements.

Idaho Power Company

Condensed Consolidated Statements of Capitalization

(unaudited)



	March 31, 2011			December 31, 2010
	(thousands of dollars)
Common Stock Equity:
Common stock	$	97,877		$	97,877
Premium on capital stock	688,758			688,758
Capital stock expense	(2,097		)	(2,097		)
Retained earnings	645,154			630,259
Accumulated other comprehensive loss	(8,781		)	(9,568		)
Total common stock equity	1,420,911			1,405,229
Long-Term Debt:
First mortgage bonds:
6.60% Series due 2011	—			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
3.40% Series Due 2020	100,000			100,000
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
4.85% Series due 2040	100,000			100,000
Total first mortgage bonds	1,295,000			1,415,000
Amount due within one year	—			(120,000		)
Net first mortgage bonds	1,295,000			1,295,000
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	6,382			7,446
Note guarantee due within one year	(1,064		)	(1,064		)
Unamortized premium/discount - net	(3,358		)	(3,440		)
Total long-term debt	1,487,305			1,488,287
Total Capitalization	$	2,908,216		$	2,893,516

The accompanying notes are an integral part of these statements.

Idaho Power Company

Condensed Consolidated Statements of Cash Flows

(unaudited)



	Three months ended March 31,
	2011			2010
	(thousands of dollars)
Operating Activities:
Net income	$	29,848		$	18,221
Adjustments to reconcile net income to net cash provided by
operating activities:
Depreciation and amortization	31,435			30,278
Deferred income taxes and investment tax credits	2,259			(22,207		)
Changes in regulatory assets and liabilities	35,850			52,036
Pension and postretirement benefit plan expense	4,553			2,796
Contributions to pension and postretirement benefit plans	(593		)	(1,561		)
Earnings of unconsolidated equity-method investments	(858		)	(348		)
Allowance for other funds used during construction	(5,329		)	(3,659		)
Other non-cash adjustments to net income	303			(1,090		)
Change in:
Accounts receivables and prepayments	(6,107		)	3,549
Accounts payable	(26,700		)	(28,851		)
Taxes accrued/receivable	33,601			31,368
Other current assets	54			12,385
Other current liabilities	8,443			13,732
Other assets	(109		)	(1,782		)
Other liabilities	(4,151		)	(4,067		)
Net cash provided by operating activities	102,499			100,800
Investing Activities:
Additions to utility plant	(101,880		)	(69,029		)
Proceeds from the sale of emission allowances and RECs	2,055			666
Investments in unconsolidated affiliates	(300		)	(2,200		)
Other	405			1,736
Net cash used in investing activities	(99,720		)	(68,827		)
Financing Activities:
Retirement of long-term debt	(121,064		)	(1,064		)
Dividends on common stock	(14,922		)	(14,377		)
Other	(8		)	(102		)
Net cash used in financing activities	(135,994		)	(15,543		)
Net (decrease) increase in cash and cash equivalents	(133,215		)	16,430
Cash and cash equivalents at beginning of the period	224,233			21,625
Cash and cash equivalents at end of the period	$	91,018		$	38,055
Supplemental Disclosure of Cash Flow Information:
Cash paid (received) during the period for:
Income taxes	$	(22,323	)	$	(2,934	)
Interest (net of amount capitalized)	$	18,310		$	12,136
Non-cash investing activities:
Additions to property, plant and equipment in accounts payable	$	24,641		$	17,882

The accompanying notes are an integral part of these statements.

Idaho Power Company

Condensed Consolidated Statements of Comprehensive Income

(unaudited)



	Three months ended March 31,
	2011		2010
	(thousands of dollars)
Net Income	$	29,848	$	18,221
Other Comprehensive Income:
Net unrealized holding gains arising during the period, net of tax of $355 and $267	553		416
Unfunded pension liability adjustment, net of tax of $150 and $114	234		177
Total Comprehensive Income	$	30,635	$	18,814

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, these Notes to 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. Idaho Power is an electric utility with a service territory covering approximately 24,000 square miles in southern Idaho and eastern Oregon. Idaho Power is regulated by the Federal Energy Regulatory Commission (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.

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 significant 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.

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 $19 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. The carrying value of BCC is $92 million at March 31, 2011, and the 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 affordable housing developments and other real estate investments in which IFS holds limited partnership interests ranging from 5 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 $71 million at March 31, 2011.

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 March 31, 2011, consolidated

results of operations for the three months ended March 31, 2011 and 2010, and consolidated cash flows for the three months ended March 31, 2011 and 2010. 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, 2010. 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, including amounts related to regulatory assets and liabilities in the condensed consolidated balance sheets. Net income, cash flows, and shareholders' equity were not affected by these reclassifications.

New Accounting Pronouncements

There are no new accounting pronouncements issued but not yet adopted that are expected to have a material impact on the financial statements of IDACORP and Idaho Power.

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 determine 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.

Income Tax Expense

An analysis of income tax expense for the three months ended March 31 is as follows (in thousands of dollars):



	IDACORP						Idaho Power
	2011			2010			2011			2010
Income tax at statutory rates (federal and state)	$	13,540		$	6,790		$	14,483		$	8,026
Additional ADITC amortization	(3,855		)	(4,512		)	(3,855		)	(4,512		)
Other	(4,797		)	(973		)	(3,435		)	(1,208		)
Income tax expense	$	4,888		$	1,305		$	7,193		$	2,306
Effective tax rate	14.1		%	7.5		%	19.4		%	11.2		%

The increase in 2011 income tax expense as compared to 2010 was primarily due to greater pre-tax earnings at IDACORP and Idaho Power. Net regulatory flow-through tax adjustments at Idaho Power and tax credits at IFS for the three months ended March 31, 2011 were comparable to the same period in 2010.

Idaho Power's January 2010 settlement agreement with the Idaho Public Utilities Commission (IPUC) and other parties provided for additional amortization of accumulated deferred investment tax credits (ADITC) if Idaho Power's actual return on year-end equity in its Idaho jurisdiction is below 9.5 percent in any calendar year from 2009 to 2011. Idaho Power has available $25 million of additional ADITC amortization for use in 2011, in accordance with the settlement agreement. Idaho

Power recorded $3.9 million of ADITC amortization in the first quarter of 2011 based on its estimate of 2011 Idaho jurisdictional return on year-end equity.

Status of Audit Proceedings and Tax Method Changes

In September 2010, Idaho Power adopted a tax accounting method change for repair-related expenditures on utility assets concurrent with the filing of IDACORP's 2009 consolidated federal income tax return. Also in 2010, Idaho Power reached an agreement with the Internal Revenue Service (IRS), subject to subsequent review by the U.S. Congress Joint Committee on Taxation (Joint Committee), regarding the allocation of mixed service costs in its method of uniform capitalization. Both methods were subject to audit under IDACORP's 2009 IRS examination.

On April 22, 2011, IDACORP and the IRS reached an agreement on Idaho Power's tax accounting method change for capitalized repairs. Accordingly, the IRS finalized the 2009 examination and submitted its report on the 2009 tax year to the Joint Committee for review. Idaho Power considers the capitalized repairs method effectively settled and believes that no material income tax uncertainties remain for the method. As such, Idaho Power expects to recognize approximately $3 million of its previously unrecognized tax benefits for this method in the second quarter of 2011. IDACORP and Idaho Power will pay previously accrued income tax liabilities of approximately $4 million and $7 million, respectively, as a result of this settlement. The difference in liabilities is due to IDACORP's utilization of previously deferred federal general business tax credits and Idaho investment tax credits.

With IDACORP's 2009 tax year now submitted to the Joint Committee, Idaho Power's uniform capitalization method agreement with the IRS will be reviewed. If the Joint Committee approves the agreement, Idaho Power would consider the method effectively settled and will recognize approximately $60 million of its previously unrecognized tax benefits for this method in the quarter in which such approval occurs. Additionally, approval would allow Idaho Power to increase the uniform capitalization tax deduction estimate included in its current year tax provision.

3. REGULATORY MATTERS:

Recent and Pending Idaho Regulatory Matters

Power Cost Adjustment Application Filing

In both its Idaho and Oregon jurisdictions, Idaho Power has power cost adjustment, or PCA, mechanisms that address the volatility of power supply costs and provide for annual adjustments to the rates charged to its retail customers. The PCA mechanisms track Idaho Power's actual net power supply costs (primarily fuel and purchased power less off-system sales) and compare these amounts to net power supply costs currently being recovered in retail rates. In its Idaho jurisdiction, the annual PCA rate adjustments are based on two components:


•	a forecast component, based on a forecast of net power supply costs in the coming year as compared to current net power supply costs included in base rates; and


•	a true-up component, based on the difference between the previous year's actual net power supply costs and the previous year's forecast. This component also includes a balancing mechanism so that, over time, the actual collection or refund of authorized true-up dollars matches the amounts authorized. The true-up component is calculated monthly, and interest is applied to the balance.

On May 28, 2010, the IPUC issued an order approving a $146.9 million decrease in Idaho PCA rates, effective June 1, 2010. On April 15, 2011, Idaho Power made its annual PCA filing with the IPUC. In its application, Idaho Power requested a $40.4 million reduction to current Idaho PCA rates, effective for the period from June 1, 2011 to May 31, 2012. The requested reduction reflects lower forecasted power supply costs than last year and includes a $14.5 million refund to customers of the March 31, 2011 true-up balance. The requested reduction to current Idaho PCA rates was net of Idaho Power’s additional request in the application to recover in Idaho PCA rates $10.0 million of Idaho Power’s energy efficiency rider deferral balance that the IPUC had previously authorized for recovery in Idaho Power’s Idaho PCA rates.

Load Change (Formerly "Load Growth") Adjustment Rate Order

The load change adjustment rate (LCAR), (formerly referred to as the “load growth adjustment rate”) is an element of the Idaho PCA formula that is intended to minimize the impact of fluctuations in power supply expenses associated with load changes resulting from changing weather conditions, customer base, or customer use patterns. The LCAR recognizes that the power supply expenses recovered through Idaho Power's base rates change as loads increase or decrease. The LCAR adjusts, upwards

or downwards, power supply costs Idaho Power recovers through its Idaho PCA for differences between actual load and the load used in calculating base rates. On January 14, 2011, Idaho Power submitted comments to the IPUC in support of a revised methodology submitted by another utility for deriving the LCAR rate. Idaho Power's filing with the IPUC requested a new LCAR rate of $19.36 per MWh, in accordance with the proposed methodology, effective April 1, 2011, representing a 27 percent decrease relative to the then-current LCAR rate.

On March 15, 2011, the IPUC issued an order requiring Idaho Power and the two other utilities involved in the proceeding to modify their LCAR such that it is computed based on the most recent IPUC-approved cost of service results, effective for Idaho PCA calculations beginning on April 1, 2011. Idaho Power began applying the new LCAR rate of $19.36 per MWh on that date.

Fixed Cost Adjustment Mechanism

In March 2007, the IPUC approved the implementation of a fixed cost adjustment (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 initial 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, through December 31, 2011.

On March 15, 2011, Idaho Power filed an application with the IPUC requesting authorization to implement revised FCA rates for electric service from June 1, 2011 through May 31, 2012. Idaho Power's application requested an aggregate increase of $3.0 million in FCA rates for the residential and small general service customer classes in its Idaho jurisdiction. As of the date of this report, a determination and order from the IPUC is pending.

Recovery of Contribution to Defined Benefit Pension Plan

In May 2010, the IPUC approved Idaho Power's request to increase rates to allow recovery of a $5.4 million planned cash contribution to its defined benefit pension plan for the 2009 plan year. In September 2010, Idaho Power elected to make a $60 million contribution to its defined benefit pension plan, rather than the minimum required funding amount, to bring the defined benefit pension plan to a more funded position, reduce future required contributions, and reduce Pension Benefit Guaranty Corporation premiums.

On March 15, 2011, Idaho Power filed an application with the IPUC requesting an increase in the amount included in base rates for recovery of the Idaho-allocated portion of Idaho Power's cash contributions to its defined benefit pension plan from the current amount of $5.4 million to approximately $17.1 million annually. Idaho Power's application requested that the revised rates become effective on June 1, 2011. The IPUC has approved processing of the application under modified procedure, which may allow for issuance of an order on or before June 1, 2011.

On October 1, 2010, Idaho Power filed an application with the IPUC requesting an order accepting Idaho Power's 2011 retirement benefits package, but not requesting recovery through rates of additional pension plan contributions. On April 28, 2011, the IPUC issued an order accepting Idaho Power's 2011 retirement benefits package.

Energy Efficiency and Demand Response Programs

Idaho Power has implemented and/or manages a wide range of opportunities for its customers to participate in energy efficiency and demand response programs. On March 15, 2011, Idaho Power filed an application with the IPUC requesting that the IPUC issue an order designating Idaho Power's 2010 Idaho energy efficiency rider expenditures of $42.5 million as prudently incurred expenses. As of the date of this report, a determination and order from the IPUC is pending.

On October 22, 2010, Idaho Power filed an application with the IPUC requesting acceptance of the company's demand-side resources (DSR) business model, which included a request for authorization to (a) move demand response incentive payments out of the energy efficiency rider and into the Idaho PCA on a prospective basis beginning on June 1, 2011, and thus subject to a true-up under the PCA mechanism; (b) establish a regulatory asset for the direct incentive payments associated with Idaho Power's energy efficiency program for large commercial and industrial customers, beginning January 1, 2011, so that Idaho Power may capitalize the direct incentive payments associated with the program, include the costs associated with the program incentive payments in its rate base, and thus earn a rate of return on a portion of its DSR activities; and (c) change the carrying

charge on the existing energy efficiency rider balancing account (from the current interest rate of 1.0 percent to Idaho Power's authorized rate of return). On April 1, 2011, the IPUC issued an order stating that certain issues raised in the application are more properly considered in a general rate case proceeding. However, the IPUC noted in its order that Idaho Power's energy efficiency rider balance includes approximately $10 million in expenditures that have been previously approved by the IPUC for recovery, and thus authorized recovery of $10 million of the rider balance in Idaho Power's Idaho PCA rates, beginning June 1, 2011.

Transmission Rate Refunds and Shortfall Filing

In its last two Idaho general rate cases, Idaho Power included an estimate of open access transmission tariff (OATT) revenues from third parties based on a forecasted OATT rate. However, on January 15, 2009, the FERC issued an order that required Idaho Power to reduce its transmission service rates to FERC jurisdictional customers and refund to transmission customers $13.3 million of transmission revenues that Idaho Power had received starting in 2006. This refund resulted in an overstatement of the revenue credits in the Idaho jurisdictional revenue requirement in Idaho Power's general rate cases. On October 30, 2009, the IPUC approved Idaho Power's request for authorization to defer the difference between the revenue credits in the last two general rate cases and the amount of OATT revenues Idaho Power had received since March 2008 and expected to receive through May 2010. Based on actual and projected transmission revenues from March 2008 through May 2010, Idaho Power recorded a $4.7 million regulatory asset in 2009 for future recovery.

On October 13, 2010, Idaho Power refreshed its filing with the IPUC for its deferral related to unrecovered transmission revenues. Termination of a transmission arrangement with PacifiCorp and adjustments to other transmission arrangements allowed Idaho Power to reduce its prior deferral amount to $2.1 million. On February 9, 2011, the IPUC issued an order reducing the deferral amount to $2.1 million, as requested by Idaho Power, but denied Idaho Power's request to begin amortization on January 1, 2012. Idaho Power's January 2010 settlement agreement would not permit potential inclusion of the deferral amount in rates until after January 1, 2012. The IPUC ordered that Idaho Power advise the IPUC when the FERC has issued its order on rehearing, following which Idaho Power may request a commencement date for the amortization period.

Recent and Pending Oregon Regulatory Matters

Oregon Power Cost Adjustment Mechanism Filings

Idaho Power's Oregon PCA mechanism has two components: the annual power cost update (APCU) and the power cost adjustment mechanism (PCAM).

The APCU allows Idaho Power to reestablish its Oregon base net power supply costs annually, separate from a general rate case, and to forecast net power supply costs for the upcoming water year. The APCU has two components: the “October Update,” Idaho Power's calculation of estimated normalized net power supply expenses for the following April through March test period, and the “March Forecast,” Idaho Power's forecast of expected net power supply expenses for the same test period, updated for a number of variables including the most recent stream flow data and future wholesale electric prices. On March 23, 2011, Idaho Power filed the March Forecast of the APCU with the Oregon Public Utility Commission (OPUC). If approved as filed, the APCU would result in an approximately $0.9 million annual decrease in amounts collected through Oregon jurisdiction customer rates.

The PCAM is a true-up filed annually in February. The filing calculates the deviation between actual net power supply expenses incurred for the preceding calendar year and the net power supply expenses recovered through the APCU for the same period. Under the PCAM, Idaho Power is subject to a portion of the business risk or benefit associated with this deviation through application of an asymmetrical deadband (or range of deviations) within which Idaho Power absorbs cost increases or decreases. For deviations in actual power supply costs outside of the deadband, the PCAM provides for 90%/10% sharing of costs and benefits between customers and Idaho Power. However, collection by Idaho Power will occur only to the extent that it results in Idaho Power's actual return on equity (ROE) for the year being no greater than 100 basis points below Idaho Power's last authorized ROE. A refund to customers will occur only to the extent that it results in Idaho Power's actual ROE for that year being no less than 100 basis points above Idaho Power's last authorized ROE. On February 28, 2011, Idaho Power submitted its 2010 PCAM true-up, stating that actual net power supply costs were within the deadband, resulting in no request for a deferral.

4. LONG-TERM DEBT:

As of March 31, 2011, IDACORP had approximately $539 million remaining on a shelf registration statement filed with the Securities and Exchange Commission (SEC) that can be used for the issuance of debt securities or common stock.

In May 2010, Idaho Power registered with the SEC up to $500 million of first mortgage bonds and debt securities. 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. As of March 31, 2011, $300 million remained on Idaho Power’s shelf registration for the issuance of first mortgage bonds and debt securities.

On March 2, 2011, Idaho Power repaid at maturity $120 million of first mortgage bonds using proceeds from first mortgage bonds issued in August 2010.

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. IDACORP and Idaho Power may issue commercial paper 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 the respective company's 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 March 31, 2011, no loans were outstanding under either IDACORP’s facility or Idaho Power’s facility. At March 31, 2011, 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 March 31, 2011 and December 31, 2010 (in thousands of dollars):



	March 31, 2011			December 31, 2010

Commercial paper outstanding	$	74,100		$	66,900
Weighted-average annual interest rate	0.40		%	0.43		%

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

6. COMMON STOCK:

IDACORP Common Stock

During the three months ended March 31, 2011, IDACORP issued an aggregate of 136,304 shares of common stock pursuant to its Dividend Reinvestment and Stock Purchase Plan, Employee Savings Plan, and IDACORP 2000 Long-Term Incentive and Compensation Plan.

IDACORP enters into sales agency agreements as a means of selling its common stock from time to time. IDACORP's current sales agency agreement, which expires in November 2011, is with BNY Mellon Capital Markets, LLC. As of March 31, 2011, there were approximately 1.2 million shares remaining available to be sold under the current sales agency agreement. No shares were issued under the sales agency agreement during the three months ended March 31, 2011.

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 in their respective credit facilities or Idaho Power’s Revised Code of Conduct. At March 31, 2011, the leverage ratios for IDACORP and Idaho Power were 50 percent and 51 percent, respectively. Based on these restrictions, IDACORP’s and Idaho Power’s dividends were limited to $708 million and $619 million, respectively, at March 31, 2011. There are additional facility covenants, subject to exceptions, that prohibit or restrict specified investments or acquisitions, mergers, or the sale or disposition of property without consent; the creation of specified forms of liens; and any agreements restricting dividend payments to the company from any material subsidiary. At March 31, 2011, IDACORP and Idaho Power were in compliance with all facility covenants.

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.

7. EARNINGS PER SHARE:

The following table presents the computation of IDACORP’s basic and diluted earnings per share (EPS) for the three months ended March 31, 2011 and 2010 (in thousands, except for per share amounts):



	Three months ended March 31,
	2011		2010
Numerator:
Net income attributable to IDACORP, Inc.	$	29,740	$	16,063
Denominator:
Weighted-average common shares outstanding - basic	49,290		47,773
Effect of dilutive securities:
Options	14		41
Restricted Stock	52		71
Weighted-average common shares outstanding - diluted	49,356		47,885
Basic and diluted earnings per share	$	0.60	$	0.34

The diluted EPS computation excludes 265,089 options for the three months ended March 31, 2011, because the options’ exercise prices were greater than the average market price of the common stock during that period. For the same period in 2010, the computation excludes 346,000 options for the same reason. In total, 321,785 options were outstanding at March 31, 2011, with expiration dates between 2011 and 2015.

8. COMMITMENTS:

Purchase Obligations

There were no material changes to purchase obligations, outside of the ordinary course of business, during the three months ended March 31, 2011.

Guarantees

Idaho Power has agreed to guarantee a portion of 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 March 31, 2011, representing IERCo's one-third share of the total reclamation obligation of $189 million. 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. Starting 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 various forms of 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 March 31, 2011, 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 indemnification obligations. Neither IDACORP nor Idaho Power has recorded any liability on their respective condensed consolidated balance sheets with respect to these indemnification obligations.

9. CONTINGENCIES:

IDACORP and Idaho Power 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 and Idaho Power 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” 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 the California refund proceeding and the balance in the escrow account is insufficient, after distribution to settling parties, to satisfy the claims of the litigants. 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 in the escrow and the amounts retained by the CalPX 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 21, 2001). Numerous parties, including IE and Idaho Power, filed motions to clarify the FERC's order and responses to these motions. In response to a solicitation from the FERC, on September 22, 2010 IE and Idaho Power, along with a number of other parties, submitted comments to the FERC regarding the scope of the proceedings. Although IE and Idaho Power are unable to predict when or how the FERC will rule on these motions and the later comments, 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. 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 May 18, 2010, in response to further pleadings by IE and Idaho Power, FERC reconsidered its earlier refusal to consider the request for rehearing but denied rehearing. 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. On June 25, 2010, IE and Idaho Power filed a petition for review of the pertinent FERC orders in the Ninth Circuit. Until the Cal ISO completes its refund calculations, it is uncertain whether there are any parties who are not bound by the California refund settlement that might be affected by the cost filing and the review of its rejection. IE and Idaho Power are unable to predict how or when the Cal ISO's refund calculations will be completed and how or when the Ninth Circuit might rule, but the direct effect of any such calculations and 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.

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 several 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 in different ways to enable them to pursue claims, as asserted by the California Parties, that all spot market

sales in the Cal ISO and CalPX markets and sales to CDWR made in the Pacific Northwest, and, as asserted by Tacoma and Port of Seattle, other sales 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. On March 25, 2011 the California Parties filed another motion requesting that the FERC take action on the Ninth Circuit remand of the Pacific Northwest Refund case, the Ninth Circuit remand described above under California Refund, the Brown Complaint, and the Lockyer remand, and repeating their earlier requests for summary FERC action or reorganization of the cases. On April 11, 2011, IE and Idaho Power joined with a number of other parties opposing the request for summary action and reorganization of the cases. As of the date of this report, 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 and EPA Notice of Violation - 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 and Clean Air Act (CAA) violations at the Boardman coal-fired plant located in Morrow County, Oregon. The complaint sought, in addition to injunctive remedies, civil penalties of up to $32,500 per day per violation, and reimbursement of plaintiffs' costs of litigation, including reasonable attorneys' fees. Trial for the matter is scheduled for December 2011. 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.

In September 2010, the U.S. Environmental Protection Agency (EPA) issued a Notice of Violation to PGE, alleging that PGE had violated the New Source Performance Standards (NSPS) and operating permit requirements under the CAA, as a result of modifications made to the plant in 1998 and 2004. The Notice of Violation states the maximum civil penalties the EPA is authorized to impose under the CAA for violations of the NSPS (which range from $25,000 to $37,500 per day), but does not impose any penalties or specify the amount of any proposed penalties with respect to the alleged violations.

Idaho Power continues to monitor the status of these matters but is unable to predict their outcome or what effect these matters may have on its consolidated financial position, results of operations, or cash flows.

Water Rights - Snake River Basin Adjudication

Idaho Power holds water rights, acquired under applicable state law, for its hydroelectric projects. In addition, Idaho Power holds water rights for domestic, irrigation, commercial, and other necessary purposes related to project lands and other holdings within the states of Idaho and Oregon. Idaho Power's water rights for power generation are, to varying degrees, subordinated to future upstream appropriations for irrigation and other authorized consumptive uses.

Over time increased irrigation development and other consumptive uses within the Snake River watershed led to a reduction in flows of the Snake River. In the late 1970's and early 1980's these reduced flows resulted in a conflict between the exercise of

Idaho Power's water rights at certain hydroelectric projects on the Snake River and upstream consumptive diversions. The Swan Falls Agreement, signed by Idaho Power and the State of Idaho on October 25, 1984, resolved the conflict and provided a level of protection for Idaho Power's hydropower water rights at specified projects on the Snake River through the establishment of minimum stream flows and an administrative process governing future development of water rights that may affect those minimum stream flows. In 1987, Congress enacted legislation directing the FERC to issue an order approving the Swan Falls settlement together with a finding that the agreement was neither inconsistent with the terms and conditions of Idaho Power's project licenses nor the Federal Power Act. The FERC entered an order implementing the legislation on March 25, 1988.

The Swan Falls Agreement provided that the resolution and recognition of Idaho Power's water rights together with the State Water Plan provided a sound comprehensive plan for management of the Snake River watershed. The Swan Falls Agreement also recognized, however, that in order to effectively manage the waters of the Snake River basin, a general adjudication to determine the nature, extent, and priority of the rights of all water uses in the basin was necessary. Consistent with that recognition, in 1987 the State of Idaho initiated the Snake River Basin Adjudication (SRBA), and pursuant to the commencement order issued by the SRBA court that same year, all claimants to water rights within the basin were required to file water right claims in the SRBA. Idaho Power has filed claims to its water rights and has been actively participating in the SRBA since its commencement. Questions concerning the effect of the Swan Falls Agreement on Idaho Power's water right claims, including the nature and extent of the subordination of Idaho Power's rights to upstream uses, resulted in the filing of litigation in the SRBA in 2007 between Idaho Power and the State of Idaho. This litigation was resolved by the Framework Reaffirming the Swan Falls Settlement (Framework) signed by Idaho Power and the State of Idaho on March 25, 2009. In that Framework, the parties acknowledged that the effective management of Idaho's water resources remains critical to the public interest of the State of Idaho by sustaining economic growth, maintaining reasonable electric rates, protecting and preserving existing water rights, and protecting water quality and environmental values. The Framework further provided that the State of Idaho and Idaho Power would cooperate in exploring approaches to resolve issues of mutual concern relating to the management of Idaho's water resources. Idaho Power continues to work with the State of Idaho and other interested parties on these issues.

One such issue involves the management of the Eastern Snake Plain Aquifer (ESPA), a large underground aquifer in southeastern Idaho that is hydrologically connected to the Snake River. House Concurrent Resolution No. 28, adopted by the Idaho Legislature in 2007, directed the Idaho Water Resource Board to pursue the development of a comprehensive management plan for the ESPA, to include measures that would enhance aquifer levels, springs, and river flows on the eastern Snake River plain to the benefit of both agricultural development and hydropower generation. In May of 2007, the Idaho Water Resource Board appointed an advisory committee, charged with the responsibility of developing a management plan for the ESPA. Idaho Power was a member of that committee. In January 2009, the Idaho Water Resource Board, based on the committee's recommendations, adopted a Comprehensive Aquifer Management Plan (CAMP) for the ESPA. The Idaho Legislature approved the CAMP that same year. Idaho Power is a member of the CAMP Implementation Committee, and is currently working with the Idaho Water Resource Board, other stakeholders, and the Idaho Legislature in implementing the provisions of the CAMP management plan.

Idaho Power also continues its active participation in the SRBA in seeking to ensure that its water rights are protected and that the operation of its hydroelectric projects is not adversely impacted. While Idaho Power cannot predict the outcome, Idaho Power does not currently anticipate any materially adverse modification of its water rights as a result of the SRBA process.

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 spaceholder contract right for storage and delivery of water to Idaho Power from American Falls Reservoir, a USBR storage reservoir on the Snake River. In the complaint, Idaho Power alleged that the USBR breached the contract by the failure to implement certain contract provisions relating to secondary storage capacity and claimed damages for the lost generation resulting from reduced flows downstream of the reservoir, and requested a prospective declaration of the rights and obligations of the parties under the 1923 contract. The USBR claimed that the referenced provisions of the 1923 contract were abrogated or amended by subsequent contracts associated with the 1976 rebuild of American Falls Reservoir and that the provisions of the 1923 contract no longer apply. The water rights for, and the operation of, American Falls Reservoir are also the subject of litigation in the SRBA, described above. During the pendency of the proceedings, Idaho Power worked with the USBR and Idaho interests (including the State of Idaho and upstream water users) in an effort to resolve the contested contract issues that are common to both the SRBA and the pending federal case with the USBR. These efforts were focused on a recognition in state policy and the Idaho State Water Plan that will promote more efficient operation of the upper Snake River reservoir system to optimize the use of Snake River flows for hydroelectric generation downstream while recognizing and protecting in-

reservoir spaceholder contract rights. These discussions resulted in a resolution passed by the Idaho Water Resource Board in March 2011 that established a standing committee, referred to as the Upper Snake River Advisory Committee (USRAC). The USRAC is comprised of a member of the Idaho Water Resource Board, representatives of Idaho Power, the USBR, and the Committee of Nine, a committee comprised of upstream water users that hold USBR contract rights to reservoir space that advises the State of Idaho and the USBR on reservoir operations. The USRAC is tasked with collaboratively working to identify and implement measures to optimize the operation and management of the reservoir system above Milner Dam to benefit existing and future beneficial uses, including hydropower below Milner Dam. This collaborative process will include a review of existing water bank and rental pool procedures to encourage and facilitate opportunities for the rental, acquisition and transfer of reservoir storage water and water rights for beneficial uses, including hydropower. The passage of the resolution and establishment of the USRAC has effectively resolved the critical issues outstanding in the pending litigation pertaining to the 1923 contract. While Idaho Power is unable to predict the ultimate impact of the collaborative process, it does not currently expect the outcome of the process will have a material adverse effect on its financial position, results of operations, or cash flows.

Other Legal Proceedings

IDACORP and Idaho Power 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. However, the companies currently believe that resolution of these matters will not have a material adverse effect on their 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 March 31 (in thousands of dollars):



	Pension Plan						Senior Management Security Plan				Postretirement Benefits
	2011			2010			2011		2010		2011			2010
Service cost	$	5,165		$	4,559		$	488	$	385	$	372		$	340
Interest cost	7,551			7,331			773		751		893			898
Expected return on plan assets	(7,951		)	(6,300		)	—		—		(667		)	(640		)
Amortization of transition obligation	—			—			—		—		510			510
Amortization of prior service cost	130			163			61		58		(99		)	(134		)
Amortization of net loss	2,094			1,925			323		233		171			143
Net periodic benefit cost	6,989			7,678			1,645		1,427		1,180			1,117
Costs not recognized due to the effects of regulation ⁽¹⁾	(5,260		)	(7,427		)	—		—		—			—
Net periodic benefit cost recognized for financial reporting⁽²⁾	$	1,729		$	251		$	1,645	$	1,427	$	1,180		$	1,117
⁽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 2011 pension rate filing.
⁽²⁾Net periodic benefit costs for the pension plan are recognized based upon the authorization of each regulatory jurisdiction Idaho Power operates within.

IDACORP and Idaho Power contributions to the defined benefit pension plan are expected to be $3 million during 2011. During the three months ended March 31, 2011, no contributions were made to the defined benefit pension plan.

11. INVESTMENTS IN DEBT AND EQUITY SECURITIES:

Investments in 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 March 31, 2011 and December 31, 2010 (in thousands of dollars):



	March 31, 2011						December 31, 2010
	Gross Unrealized Gain		Gross Unrealized Loss		Fair Value		Gross Unrealized Gain		Gross Unrealized Loss		Fair Value
Available-for-sale securities	$	5,784	$	—	$	26,355	$	4,876	$	—	$	24,561

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 March 31, 2011 and December 31, 2010, no securities were in an unrealized loss position.

There were no sales of available-for-sale securities during the three months ended March 31, 2011 or 2010.

12. DERIVATIVE FINANCIAL INSTRUMENTS:

Commodity Price Risk

Idaho Power is exposed to market risk relating to electricity, natural gas, and other fuel commodity prices, all of 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 uses derivative instruments, such as physical and financial forward contracts, for both electricity and fuel 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 commodity-related derivative instruments not meeting the normal purchases and normal sales exception to derivative accounting are recorded at fair value on the balance sheet. Because of Idaho Power's PCA mechanisms, unrealized gains and losses associated with the changes in fair value of these derivative instruments are recorded as regulatory assets or liabilities. With the exception of forward contracts for the purchase of natural gas for use at Idaho Power’s natural gas generation facilities, Idaho Power’s physical forward contracts, including renewable energy certificates, qualify for the normal purchases and normal sales exception.

Idaho Power had the following volumes of derivative commodity forward contracts and swaps, entered into for the purpose of economically hedging forecasted purchases and sales, outstanding at March 31, 2011 and 2010:



Derivative Commodity Contracts
		March 31,
Commodity	Units	2011	2010
Electricity purchases	MWh	486,000	746,650
Electricity sales	MWh	501,250	370,825
Natural gas purchases	MMBtu	1,867,316	1,898,750
Diesel purchases	Gallons	804,146	645,640

The following tables present the fair values and locations of derivative instruments recorded in the balance sheets at March 31, 2011 and December 31, 2010 (in thousands of dollars):

Asset Derivatives

Liability Derivatives

Balance Sheet

Fair

Balance Sheet

Fair

March 31, 2011

Location

Value

Location

Value

Current:

Financial swaps

Other current assets

1,257

Other current assets

451

Financial swaps

Other current liabilities

1,925

Other current liabilities

5,884

Forward contracts

Other current liabilities

482

Long-term:

Financial swaps

Other assets

Forward contracts

Other assets

298

Total

3,554

6,817

December 31, 2010

Current:

Financial swaps

Other current assets

930

Other current assets

356

Financial swaps

Other current liabilities

2,440

Other current liabilities

4,172

Forward contracts

Other current liabilities

508

Long-term:

Financial swaps

Other assets

100

Other assets

138

Total

3,470

5,174

The following table presents the gains and losses on derivatives for the three months ended March 31, 2011 and 2010 (in thousands of dollars):



	Location of Gain/(Loss)	Gain/(Loss)
	on Derivatives	on Derivatives
Commodity Derivatives	Recognized in Income	Recognized in Income (1)
Three months ended March 31, 2011:
Financial swaps	Off-system sales	$	6,721
Financial swaps	Purchased power	(167		)
Three months ended March 31, 2010:
Financial swaps	Off-system sales	$	456
Financial swaps	Purchased power	(162		)
(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 months ended March 31, 2011. 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 March 31, 2011, Idaho Power did 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. Idaho Power’s physical power contracts are under Western Systems Power Pool agreements, physical gas contracts are under North American Energy Standards Board contracts, and financial transactions are under International Swaps and Derivatives Association, Inc. contracts. These contracts all

contain adequate assurance clauses requiring collateralization if a counterparty has debt that is downgraded below investment grade by at least one rating agency.

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 Moody's Investors Service and Standard & Poor's Ratings Services. 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 were in a liability position at March 31, 2011, was $7.1 million. Idaho Power had posted $2.7 million of collateral related to this amount. If the credit-risk-related contingent features underlying these agreements were triggered on March 31, 2011, Idaho Power would have been required to post $1.8 million of additional cash collateral to its counterparties.

13. FAIR VALUE MEASUREMENTS:

IDACORP and Idaho Power have categorized their financial instruments into a three-level fair value hierarchy, based on the priority of the inputs to the valuation technique. 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 consist 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 March 31, 2011 and December 31, 2010 (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 Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)		Total
March 31, 2011
IDACORP
Assets:
Derivatives	$	818	$	360	$	—	$	1,178
Money market funds	40,382		—		—		40,382
Trading securities: Equity securities	3,660		—		—		3,660
Available-for-sale securities: Equity securities	26,355		—		—		26,355
Liabilities:
Derivatives	$	1,268	$	482	$	—	$	1,750
Idaho Power
Assets:
Derivatives