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Heating degree-days⁽¹⁾

Precipitation (inches)

⁽¹⁾ Heating and cooling degree-days are common measures used in the utility industry to analyze the demand for electricity and indicate when a customer would use electricity for heating and air conditioning. A degree-day measures how much the average daily temperature varies from 65 degrees. Each degree of temperature above 65 degrees is counted as one cooling degree-day, and each degree of temperature below 65 degrees is counted as one heating degree-day. There were no cooling degree days during the period.

10-Q 1 ida3311110q.htm WebFilings | EDGAR view

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.

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

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.

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	$	818	$	360	$	—	$	1,178
Money market funds	39,730		—		—		39,730
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

December 31, 2010
IDACORP
Assets:
Derivatives	$	573	$	—	$	—	$	573
Money market funds	151,975		—		—		151,975
Trading securities: Equity securities	5,361		—		—		5,361
Available-for-sale securities: Equity securities	24,561		—		—		24,561
Liabilities:
Derivatives	$	—	$	508	$	—	$	508
Idaho Power
Assets:
Derivatives	$	573	$	—	$	—	$	573
Money market funds	151,173		—		—		151,173
Trading securities: Equity securities	4,746		—		—		4,746
Available-for-sale securities: Equity securities	24,561		—		—		24,561
Liabilities:
Derivatives	$	—	$	508	$	—	$	508

The table below presents the carrying value and estimated fair value of financial instruments that are not reported at fair value, as of March 31, 2011 and December 31, 2010, using available market information and appropriate valuation methodologies. The use of different market assumptions and/or estimation methodologies may have a material effect on the estimated fair value amounts. Cash and cash equivalents, deposits, customer and other receivables, notes payable, accounts payable, interest accrued, and taxes accrued are reported at their carrying value as these are a reasonable estimate of their fair value. The estimated fair values for notes receivable and long-term debt are based upon quoted market prices of the same or similar issues or discounted cash flow analyses as appropriate.



	March 31, 2011				December 31, 2010
	Carrying		Estimated		Carrying		Estimated
	Amount		Fair Value		Amount		Fair Value
	(thousands of dollars)
IDACORP
Assets:
Notes receivable	$	2,946	$	2,946	$	2,946	$	2,946
Liabilities:
Long-term debt	1,492,330		1,485,482		1,614,299		1,622,924
Idaho Power
Liabilities:
Long-term debt	$	1,491,727	$	1,484,881	$	1,612,790	$	1,621,425

14. SEGMENT INFORMATION:

IDACORP’s only reportable segment is utility operations. The utility operations segment’s primary source of revenue is the regulated operations of Idaho Power. Idaho Power’s regulated operations include the generation, transmission, distribution, purchase, and sale of electricity. This segment also includes income from IERCo, a wholly-owned subsidiary of Idaho Power that is also subject to regulation and is a one-third owner of BCC, an unconsolidated joint venture.

IDACORP’s other operating segments are below the quantitative and qualitative thresholds for reportable segments and are included in the “All Other” category. This category is comprised of IFS’s investments in affordable housing developments and historic rehabilitation projects, Ida-West’s joint venture investments in small hydroelectric generation projects, the remaining activities of energy marketer IE, which wound down its operations in 2003, and IDACORP’s holding company expenses.

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



	Utility Operations		All Other			Eliminations			Consolidated Total
Three months ended March 31, 2011:
Revenues	$	251,062	$	432		$	—		$	251,494
Income attributable to IDACORP, Inc.	29,848		(108		)	—			29,740
Total assets at March 31, 2011	4,478,088		127,663			(15,503		)	4,590,248
Three months ended March 31, 2010:
Revenues	$	252,460	$	503		$	—		$	252,963
Income attributable to IDACORP, Inc.	18,221		(2,158		)	—			16,063

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

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

Boise, Idaho

We have reviewed the accompanying condensed consolidated balance sheet of IDACORP, Inc. and subsidiaries (the “Company”) as of March 31, 2011, and the related condensed consolidated statements of income, comprehensive income, equity, and cash flows for the three-month periods ended March 31, 2011 and 2010. These interim financial statements are the responsibility of the Company’s management.

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

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

We have previously audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheet of IDACORP, Inc. and subsidiaries as of December 31, 2010, and the related consolidated statements of income, comprehensive income, equity, and cash flows for the year then ended (not presented herein); and in our report dated February 23, 2011, we expressed an unqualified opinion on those consolidated financial statements. In our opinion, the information set forth in the accompanying condensed consolidated balance sheet as of December 31, 2010 is fairly stated, in all material respects, in relation to the consolidated balance sheet from which it has been derived.

/s/ DELOITTE & TOUCHE LLP

Boise, Idaho

May 5, 2011

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Shareholder of Idaho Power Company

Boise, Idaho

We have reviewed the accompanying condensed consolidated balance sheet and statement of capitalization of Idaho Power Company and subsidiary (the “Company”) as of March 31, 2011, and the related condensed consolidated statements of income, comprehensive income, and cash flows for the three-month periods ended March 31, 2011 and 2010. These interim financial statements are the responsibility of the Company’s management.

We have previously audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheet and statement of capitalization of Idaho Power Company and subsidiary as of December 31, 2010, and the related consolidated statements of income, comprehensive income, retained earnings, and cash flows for the year then ended (not presented herein); and in our report dated February 23, 2011, we expressed an unqualified opinion on those consolidated financial statements. In our opinion, the information set forth in the accompanying condensed consolidated balance sheet and statement of capitalization as of December 31, 2010 is fairly stated, in all material respects, in relation to the consolidated balance sheet and statement of capitalization from which it has been derived.

/s/ DELOITTE & TOUCHE LLP

Boise, Idaho

May 5, 2011

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

(Megawatt-hours (MWh) and dollar amounts, other than earnings per share, are in thousands unless otherwise indicated.)

FORWARD-LOOKING STATEMENTS

In addition to the historical information contained in this report, this report contains (and oral communications made by IDACORP, Inc. and Idaho Power Company may contain) statements that relate to future events and expectations and, as such, constitute forward-looking statements within the meaning of the Private Securities Litigation Reform Act of 1995. Any statements that express, or involve discussions as to expectations, beliefs, plans, objectives, assumptions, or future events or performance, often, but not always, through the use of words or phrases such as "anticipates," "believes," "estimates," "expects," "intends," "plans," "predicts," "projects," "may result," "may continue," or similar expressions, are not statements of historical facts and may be forward-looking. Forward-looking statements are not guarantees of future performance and involve estimates, assumptions, risks, and uncertainties. Actual results, performance, or outcomes may differ materially from the results discussed in the statements. In addition to any assumptions and other factors and matters referred to specifically in connection with such forward-looking statements, factors that could cause actual results or outcomes to differ materially from those contained in forward-looking statements include those factors discussed in IDACORP's and Idaho Power's 2010 Annual Report on Form 10-K, particularly Item 1A - “Risk Factors”; Part II, Item 7 - “Management’s Discussion and Analysis of Financial Condition and Results of Operations”; and Notes 2, 11, and 15 to the consolidated financial statements included in the Annual Report on Form 10-K; subsequent reports filed by IDACORP and Idaho Power with the Securities and Exchange Commission; and the following important factors:

•

The effect of regulatory decisions by the Idaho Public Utilities Commission, the Oregon Public Utility Commission, the Federal Energy Regulatory Commission, and other regulators affecting Idaho Power's ability to recover costs and/or earn a reasonable rate of return, including, but not limited to, decisions relating to the disallowance of costs that have been deferred, financings, allowed rates of return, electricity pricing and price structures, acquisition and disposal of assets and facilities, relicensing of hydroelectric facilities and conditions on such relicensing, implementation of energy efficiency programs, and current or prospective wholesale and retail competition;


•	Variable hydrological conditions, which can impact stream flows and the amount of generation from Idaho Power's hydroelectric facilities;


•	Over-appropriation of surface and groundwater in the Snake River basin, including the outcome of proposals for use of water in the Snake River basin for aquifer recharge, resulting in reduced generation at hydroelectric facilities;


•	Changes in the cost and availability of materials, fuel, and commodities, and their impact on Idaho Power's ability to meet required loads and their impact on the wholesale energy market in the western United States;


•	Costs and delays associated with construction and maintenance of power generation, transmission, and distribution facilities, including the inability to obtain required governmental permits and approvals, rights-of-way, and siting, and risks related to contracting, construction, and start-up;


•	Power generating facility performance below expected levels, breakdown or failure of equipment, and forced generation plant outages;


•	Disruptions or outages of Idaho Power's generation or transmission systems or the western interconnected transmission system, which can affect Idaho Power's ability to deliver power to its customers and generating facilities and require dispatching more expensive generation resources or purchasing power, and ultimately increase costs;


•	Increased costs and increases to customer rates associated with the legislatively mandated purchase of intermittent power, such as wind, at above-market rates, and the costs of integrating intermittent power sources into Idaho Power's power portfolio;


•	Population growth and changes in residential, commercial, and industrial growth and demographic patterns within Idaho Power's service area, the loss or change in the business of significant customers, and the associated impact on loads and load growth;


•	Changes in and costs of compliance with laws, regulations, and policies relating to the environment, natural resources, and endangered species and the adoption of laws and regulations addressing greenhouse gas emissions, global climate change, and energy policies, particularly with respect to coal-fired generation facilities, intended to mitigate carbon dioxide, mercury, and other emissions;


•	Global climate change and regional or national weather variations, which affect customer demand and hydroelectric generation and can impact the ability and cost to procure adequate supplies of natural gas, coal, or purchased power to serve customers;

•

Inclement weather and other natural phenomena such as earthquakes, floods, droughts, lightning, wind, and fire, which, in addition to affecting customer demand for power, could significantly affect the ability and cost to procure adequate supplies of fuel or power to serve customers, and could increase the costs to repair and maintain Idaho Power's generating facilities, transmission and distribution systems, and other infrastructure;


•	Transaction risks, including increases in costs, associated with Idaho Power's energy commodity and other derivative instruments, the failure of Idaho Power's energy risk management policies to work as intended, exposure to counterparty credit risk, and potential higher costs of hedging activities due to new regulations pertaining to derivatives;

•

Wholesale market disruption or volatility, which may result in a deterioration of market liquidity, increase the risk of counterparty default, affect the regulatory and legislative process in unpredictable ways, negatively affect wholesale energy prices, impede Idaho Power's ability to manage its energy portfolio risks and procure energy supply, affect the availability and access to capital and credit markets, and/or impact delivery of fuel and purchased power to Idaho Power from its suppliers;

•

Deteriorating values in the equity markets, changes in interest rates and credit spreads, inflation, and other financial market conditions, as well as changes in government regulations, which affect, among other things, the cost of capital and the ability to access the capital markets, indebtedness obligations, and the amount and timing of required contributions to pension and other postretirement benefit plans;

•

Failure of Idaho Power to comply with state and federal laws, policies, and regulations, including new interpretations and enforcement initiatives by regulatory and oversight bodies, including, but not limited to, the Federal Energy Regulatory Commission, the North American Electric Reliability Corporation, the Western Electricity Coordinating Council, the U.S. Environmental Protection Agency, and Idaho and Oregon state regulatory commissions, which may result in penalties and affect the cost of compliance, the nature and extent of investigations and audits, and costs of remediation;


•	The cost and outcome of litigation, dispute resolution, and regulatory proceedings, and penalties, settlements, or awards that influence the companies' business and operations;


•	Reductions in credit ratings, which could adversely impact access to capital markets and would require the posting of additional collateral to counterparties pursuant to existing power purchase and credit arrangements;


•	Results of financing efforts, including the ability to obtain financing or refinance existing debt when necessary or on favorable terms, which can be affected by factors such as credit ratings, volatility in the financial markets, and other economic conditions;


•	The continuing effects of the weak economy in Idaho Power's service territory and elsewhere, including decreased demand for electricity and reduced revenue from sales of excess energy during periods of low wholesale market prices, impaired financial soundness of vendors and service providers, and elevated levels of uncollectible customer accounts;


•	Changes in tax laws or related regulations or new interpretations of applicable law by the Internal Revenue Service or state and local taxing jurisdictions, and the availability and use by IDACORP or Idaho Power of tax credits;


•	Unionization, or the attempt to unionize, all or part of the companies' workforce, and the resulting effects on production, profitability, and operations;


•	The failure of information systems or the failure to secure information system data, security breaches, or the occurrence of events that affect homeland security, and acts of war or terrorism;


•	Adoption of or changes in accounting policies, principles, or estimates; and


•	New accounting or Securities and Exchange Commission or New York Stock Exchange requirements, or new interpretations of existing requirements.

Any forward-looking statement speaks only as of the date on which such statement is made. New factors emerge from time to time and it is not possible for management to predict all such factors, nor can it assess the impact of any such factor on the business or the extent to which any factor, or combination of factors, may cause results to differ materially from those contained in any forward-looking statement. IDACORP and Idaho Power disclaim any obligation to update publicly any forward-looking information, whether in response to new information, future events, or otherwise, except as required by applicable law.

INTRODUCTION

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

IDACORP is a holding company formed in 1998 whose principal operating subsidiary is Idaho Power. IDACORP’s common stock is listed and trades on the New York Stock Exchange under the trading symbol “IDA.”

Idaho Power is an electric utility with a service territory covering approximately 24,000 square miles in southern Idaho and eastern Oregon. Idaho Power provided electric service to approximately 492,000 general business customers as of March 31, 2011. 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. Idaho Power generates revenues and cash flows primarily from the sale and distribution of electricity to customers in its Idaho and Oregon service territories, as well as from the wholesale sale and transmission of electricity. Idaho Power’s revenues and income from operations are subject to fluctuations during the year due to the impacts of seasonal weather conditions on demand for electricity, availability of water for hydroelectric generation, price changes, customer usage patterns (which are affected in large part by the condition of the local economy), and the availability and price of purchased power and fuel. Idaho Power is a dual peaking utility that typically experiences its highest retail energy sales during the summer irrigation and cooling season, with a lower peak in the winter that generally results from heating demand. IDACORP’s and Idaho Power’s financial condition is also affected by regulatory decisions, through which Idaho Power seeks to recover its costs, including purchased power and fuel costs, on a timely basis, and to earn an authorized return on investment, and by the ability to obtain financing through the issuance of debt and/or equity securities.

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

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

EXECUTIVE OVERVIEW

Overview of General Factors and Trends Affecting Results of Operations and Financial Condition

IDACORP's and Idaho Power's results of operations and financial condition and outlook are affected by a number of important business, regulatory, economic, and other factors. IDACORP and Idaho Power closely monitor these and other factors to plan for the companies' current needs, and to adjust their expectations, financial budgets, and forecasts appropriately. For the three months ended March 31, 2011, IDACORP's net income was affected primarily by two factors: (1) rate and regulatory changes at Idaho Power, including the effect of the power cost and fixed cost adjustment mechanisms; and (2) increased sales volumes at Idaho Power, resulting primarily from cooler weather during the first quarter of 2011 relative to the prior year, which increased demand for electricity for heating purposes. Further detail on these primary drivers, as well as other factors affecting IDACORP's and Idaho Power's current and future financial performance, are set forth below in this “Executive Overview” and in other sections of this MD&A.

Regulatory Framework, Rates, and Cost Recovery: Idaho Power is under the retail jurisdiction (as to rates, service, accounting, and other general matters of utility operation) of the Idaho Public Utilities Commission (IPUC) and the Oregon Public Utility Commission (OPUC), and has authority to charge market-based rates for wholesale energy sales under its FERC tariff and to provide transmission services under its open access transmission tariff (OATT). The prices that the IPUC and OPUC authorize Idaho Power to charge for its retail services and the tariff rate that the FERC permits Idaho Power to charge for transmission are major factors in determining IDACORP's and Idaho Power's results of operations and financial condition. The IPUC and OPUC have the authority to disallow recovery of any costs that they consider unreasonable or imprudently incurred, and the FERC formula rates may be insufficient for recovery of actual costs incurred. Because of the significant impact of ratemaking decisions on Idaho Power's business and financial condition, the company's management continues to focus on timely recovery of its costs through filings with the IPUC and the OPUC.

In accordance with a January 2010 settlement stipulation, Idaho Power's first opportunity to file a new general rate case with the IPUC is June 1, 2011. On March 31, 2011, Idaho Power filed with the IPUC a notification of its intent to file a general rate case on or after June 1, 2011. While filing of the notice is a prerequisite to filing a general rate case, filing of the notice of intent does not obligate Idaho Power to file a general rate case, and Idaho Power continues to evaluate its general rate case needs and options.

Two of Idaho Power's primary regulatory mechanisms are its power cost adjustment (PCA) mechanisms in Idaho and Oregon, which provide for annual adjustments to the rates charged to its Idaho and Oregon retail customers. The PCA mechanisms track Idaho Power's actual net power supply costs (primarily fuel and purchased power less off-system sales) and compares these amounts to net power supply costs currently being recovered in retail rates. Most of the variance between these two amounts is deferred for future recovery from or refund to customers. Because of the PCA mechanisms, the primary financial impact of power supply cost variations is on the timing of cash flows. If costs rise above the level currently recovered in retail rates it negatively affects Idaho Power's operating cash flow and liquidity until those costs are recovered from customers. Idaho Power made its annual Idaho PCA filing with the IPUC on April 15, 2011 to implement new Idaho PCA rates to be effective June 1, 2011 through May 31, 2012. Idaho Power's application sought a $40.4 million net reduction to Idaho PCA rates. Idaho Power also has a fixed cost adjustment (FCA) mechanism that is 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. Idaho Power made its annual FCA filing with the IPUC on March 15, 2011, seeking an aggregate increase of $3.0 million in FCA rates for the residential and small general service customer classes in its Idaho jurisdiction, to be effective June 1, 2011 through May 31, 2012.

Economic Conditions and Customer Growth: Economic conditions within and outside of Idaho Power's service area can impact consumer demand for electricity, collectability of accounts, the volume of off-system sales due to power demand, and Idaho Power's need for purchased power. Since 2008, economic conditions in Idaho Power's service territory have been relatively weak. Unemployment rates remain high relative to historic unemployment levels and the customer growth rate has been low relative to prior years. During the twelve months ended March 31, 2011, the customer growth rate in Idaho Power's service territory was 0.5 percent. By comparison, for the period from 2005 through 2008, the average annual customer growth rate in Idaho Power's service territory was 2.6 percent. While customer growth rates are influenced by a number of factors, economic conditions can be a significant driver. Management cannot predict when economic recovery may occur in Idaho Power's service territory. As such, Idaho Power continues to manage costs while executing on its three part strategy of responsible planning, responsible development and protection of resources, and responsible energy use. In the current economic environment, management is focused on factors such as customer growth, customer load, future capital requirements and the timing of capital expenditures, system reliability and efficiency, liquidity and access to capital markets, accounts receivable balances and collections, employee remuneration and retirement benefits plans, and counterparty risk.

Weather Conditions and Associated Impacts: Weather conditions and agricultural growing conditions have a significant impact on energy sales and result in seasonality of those sales. Relatively low and high temperatures result in greater energy usage for heating and cooling, respectively. Customer usage increased in the three months ended March 31, 2011 relative to the same period in 2010, in part due to cooler temperatures in the service area compared to the same period in 2010, which increased the demand for electricity for heating purposes. During the growing season, which in large part occurs during the second and third quarters of each calendar year, irrigation customers use electricity to operate irrigation pumps. Increased precipitation during the growing season reduces electricity sales to these customers. Variations in energy usage necessitate a continual balancing of loads, generating and transmission resources, and purchases and sales of energy.

The effect of weather on Idaho Power's hydroelectric power generation projects can also impact Idaho Power's financial condition and results of operations. Hydroelectric generation depends on stream flows in the Snake River and its tributaries, on which Idaho Power's hydroelectric facilities are located. The availability of hydroelectric power depends on the amount of snow pack in the mountains upstream of Idaho Power's hydroelectric facilities, reservoir storage, springtime snow pack run-off, river base flows in the Snake River, spring flows, rainfall, water leases and other water rights, and other weather and stream flow considerations. During low water years, when stream flows into Idaho Power's hydroelectric projects are reduced and reservoir storage is low, Idaho Power's hydroelectric generation is reduced. This results in reduced generation from Idaho Power's resource portfolio available to serve Idaho Power's customers and for off-system sales and, generally, an increased use of more expensive coal- or gas-fired generation or purchased power to meet load requirements. Both of these situations result in increased power supply costs. Regional energy market prices can also be affected by hydroelectric generating conditions. In times with high hydroelectric generation, the availability of abundant energy tends to reduce wholesale prices, and during low hydroelectric generation periods wholesale prices tend to be higher. While the cost of purchased power is typically higher than the cost of hydroelectric generation, the incremental cost is currently included in the PCA mechanisms that allow Idaho Power to recover most of these costs. Idaho Power expects hydroelectric generation during 2011 in the range of 8.5 to 10.5 million MWh, compared to 7.3 million MWh in 2010, as a result of above-average precipitation during the most recent snow

accumulation period. Median annual hydroelectric generation is 8.6 million MWh.

Fuel and Purchased Power Expense: Fuel and purchased power costs included in the condensed consolidated statements of income are impacted by electricity sales volumes, the terms of contracts for purchased power and fuel (primarily coal and natural gas), Idaho Power's power generation capacity, the rate of expansion of alternative energy generation sources such as wind energy, the availability of hydroelectric generation resources, transmission capacity, energy market prices, Idaho Power's hedging program for managing power costs, and power supply cost deferrals and the recovery of deferred amounts.

In addition to its hydroelectric generation facilities, Idaho Power relies significantly on coal and natural gas to fuel its generation facilities. For the three months ended March 31, 2011, Idaho Power's weighted average cost per MWh for coal, natural gas, and other fuels increased 24 percent relative to the same period in 2010, primarily due to coal price increases and lower generation output. Notwithstanding the increase in fuel cost per MWh generated, for the three months ended March 31, 2011, total fuel expense decreased 20 percent relative to the prior year comparable period, due to a 35 percent decrease in MWh generated from fuel-fired power generating plants. Increases in demand for coal and natural gas may result in market price increases, short-term price volatility, and/or supply availability issues. Operation of the Langley Gulch power plant that Idaho Power is currently constructing will increase Idaho Power's demand for natural gas, and thus its exposure to volatility in natural gas prices.

Idaho Power relies in part on purchased power to meet load requirements. Idaho Power makes economic dispatch decisions continuously throughout a given period based on numerous factors, including plant availability, customer demand, and current wholesale prices, in an effort to minimize power costs for its retail customers. As a result, the proportion of power generated and purchased in the wholesale market to meet retail loads can vary from period to period. To help reduce power demand, Idaho Power has several energy efficiency programs in place and in development, targeting savings across the entire year and across a wide range of customer segments. The emphasis of these programs is to reduce energy consumption, especially during periods of high demand, and delay the need to build new supply-side alternatives. The majority of Idaho Power's energy efficiency activities are funded through a rider mechanism on customer bills in both Idaho and Oregon.

The PCA mechanisms described above mitigate in large part the potential adverse impacts of fluctuations in Idaho Power's power supply costs by deferring for future recovery from, or refund to, customers most of the variance between actual net power supply costs and net power supply costs currently being recovered in retail rates. Idaho Power also uses derivative instruments, such as physical and financial forward contracts, for both electricity and fuel in order to manage the risks relating to fuel and power price exposures.

Regulatory and Environmental Compliance Costs and Expenditures: Idaho Power is subject to extensive federal and state laws, policies, and regulations, as well as regulatory actions and audits. Compliance with these requirements directly influences Idaho Power's operating environment and may significantly increase Idaho Power's operating costs. Further, potential monetary and non-monetary penalties for a violation of applicable laws or regulations may be substantial. Accordingly, Idaho Power has in place numerous compliance policies and initiatives, and frequently evaluates, updates, and supplements these policies and initiatives.

Idaho Power is also subject to a substantial body of rapidly changing regulations by federal, state, and local authorities governing the protection of the environment. Environmental laws and regulations may, among other things, increase the cost of operating power generation plants and constructing new facilities, require that Idaho Power install additional pollution control devices at existing generating plants, or require that Idaho Power shut down certain power generation plants. For instance, the Boardman coal-fired power plant, in which Idaho Power owns a 10 percent interest, was recently the subject of proceedings with Oregon regulators relating to the installation of costly emission controls and an anticipated early shut-down of the facility in 2020, and in September 2010 the U.S. Environmental Protection Agency (EPA) issued a Notice of Violation to Portland General Electric Company (PGE), the operator of the Boardman plant, alleging Clean Air Act violations. Idaho Power continues to monitor developing legislation and increased regulation concerning greenhouse gas emissions and the potential impacts on its power generation facilities, and as legislation further develops will assess the impact of any resulting legislation on the costs to operate those facilities, as well as the willingness or ability of power plant participants to fund any required pollution control equipment upgrades. Idaho Power intends to seek recovery of such costs through the ratemaking process.

Other Current and Future Matters

Tax-Related Projects: In 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. The ultimate resolution of these tax matters and the associated regulatory treatment may have a substantial impact on IDACORP's and Idaho Power's financial condition and results of operations. In late April 2011, IDACORP and the IRS reached an agreement on Idaho Power's capitalized repairs method change. 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. 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.

Further, a January 2010 settlement agreement with the IPUC 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, and recorded $3.9 million of that amount in the first quarter of 2011. Idaho Power expects to record approximately $15 million of additional ADITC amortization for the full year 2011. However, the amount of ADITC recorded during 2011 could change significantly based on the outcome of the Joint Committee's review of the uniform capitalization method or other items impacting Idaho Power's actual return on year-end equity.

Retirement Benefit Plans: In September 2010, Idaho Power contributed $60 million to its defined benefit pension plan. The contribution was in excess of the $6 million minimum contribution required to be made in September 2010 for the 2009 plan year. 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 $17.1 million annually. The IPUC has approved processing of the March 15, 2011 rate increase request 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 acceptance of Idaho Power's 2011 retirement benefit package, and on April 28, 2011, the IPUC issued an order accepting Idaho Power's 2011 retirement benefits package.

PURPA Power Purchase Contracts: Pursuant to the requirements of Section 210 of PURPA, the IPUC and OPUC have each issued orders and rules regulating Idaho Power's purchase of power from cogeneration and small power production facilities. A key component of the PURPA power purchase contracts is the energy price contained within the agreements. Regulatory mandated execution of PURPA agreements may result in Idaho Power acquiring energy at above wholesale market prices and at times when a surplus already exists, require that Idaho Power sell excess power into the market at a loss, and require additional operational integration costs, thus increasing costs to Idaho Power's customers. Substantially all PURPA power purchase costs are recovered through base rates and Idaho Power's power supply cost mechanisms, and thus the primary impact of the PURPA agreements is on customer rates. On February 7, 2011, the IPUC issued an order temporarily reducing the eligibility cap for projects entitled to published avoided cost rates from 10 average MW to 100 kilowatts (kW) for wind and solar PURPA projects while the IPUC further investigates the implications of large projects disaggregating into smaller projects to qualify for higher published avoided cost rates and other benefits.

Relicensing of Hydroelectric Projects: Idaho Power is involved in renewing federal licenses for the Hells Canyon Complex (HCC), its largest hydroelectric generation source, and the Swan Falls hydroelectric project. Relicensing involves numerous environmental issues and substantial costs. Idaho Power is working with the states of Idaho and Oregon, regulatory authorities, and interested parties to address concerns and take appropriate measures relating to the relicensing of Idaho Power's hydroelectric projects. Given the number of parties and issues involved, Idaho Power's relicensing costs have been and will continue to be substantial. Idaho Power will request recovery of relicensing costs through the ratemaking process.

Water Management Issues: Power generation at Idaho Power's hydroelectric power plants on the Snake River and its tributaries depends on the state water rights held by Idaho Power and the long-term sustainability of the Snake River, tributary spring flows, and the Eastern Snake Plain Aquifer that is connected to the Snake River. Idaho Power continues to participate in water management issues in Idaho that may affect those water rights and resources with the goal to preserve, to the fullest extent possible, the long-term availability of water for use at Idaho Power's hydroelectric projects on the Snake River.

Summary of First Quarter 2011 Financial Results

A summary of net income attributable to IDACORP, Inc. and earnings per diluted share for the three months ended March 31, 2011 and 2010 is as follows:



	Three months ended March 31,
	2011		2010
Net income attributable to IDACORP, Inc.	$	29,740	$	16,063
Average outstanding shares – diluted (000’s)	49,356		47,885
Earnings per basic and diluted share	$	0.60	$	0.34

The following table presents a reconciliation of net income attributable to IDACORP, Inc. for the three-month period ended March 31, 2011 to the same period in 2010 (items are in millions and are before tax unless otherwise noted):



	Three months ended
Net income attributable to IDACORP, Inc. - March 31, 2010				$	16.1
Change in Idaho Power net income before taxes:
Rate and other regulatory changes, including power cost and
fixed cost adjustment mechanisms	$	9.8
Increased sales volumes	5.6
Other changes in operating income, net	0.9
Change in Idaho Power operating income	16.3
Other net increases	0.2
Change in additional amortization of accumulated deferred income tax credits	(0.7		)
Increase in other income tax expense	(4.2		)
Total increase in Idaho Power net income				11.6
Changes at holding company (net of tax)				2.4
Other net decreases, net of tax				(0.4		)
Net income attributable to IDACORP, Inc. - March 31, 2011				$	29.7

Although Idaho Power experienced lower revenues due to a significant decrease in PCA rates, its 2011 first quarter operating income increased $16.3 million over the same period in 2010, due primarily to base rate increases and increased sales volumes.

On June 1, 2010, several Idaho rate orders increasing base rates were implemented, as was a decrease in Idaho PCA rates. Including the Idaho PCA, these rate changes reduced Idaho-jurisdiction revenues approximately $10.4 million in the quarter. The revenue impact of certain of these rate changes was directly offset by changes in operating expense. For example, Idaho PCA amortization expense was reduced $22.5 million compared to the first quarter of 2010 due to the decrease in the corresponding Idaho PCA rate. The rate changes and changes in power supply costs, net of the related PCA mechanisms, increased operating income by approximately $9.8 million.

Increased sales volumes improved operating income by $5.6 million. Cooler temperatures contributed to the increased electricity demand from residential customers, many of whom rely on electric power for heating systems during the winter months.

Holding company earnings increased $2.4 million for the quarter primarily due to the effects of intra-period tax allocations. In accordance with interim reporting requirements, IDACORP uses its consolidated group annual effective tax rate to determine income tax expense for the quarter, which results in an intra-period allocation of expense. IDACORP records this intra-period allocation at the holding company.

In accordance with a provision in its January 2010 settlement agreement with the IPUC, Idaho Power recorded an additional amortization of $3.9 million of ADITC in the first quarter of 2011. The agreement allows an additional amortization up to $25 million of ADITC in 2011 if Idaho Power's actual rate of return on year-end equity in its Idaho jurisdiction is below 9.5 percent.

In the first quarter of 2010, Idaho Power recorded additional amortization of $4.5 million of ADITC that was reversed in the second quarter of 2010 due to a change in estimated annual return on equity. Any unused credits carry over to future periods, making them available to benefit customers or shareholders in the future. While the actual amount could change significantly based on Idaho Power's actual 2011 return on year-end equity, as of the end of the first quarter Idaho Power expects to record approximately $15 million of additional ADITC amortization for the full year 2011.

Key Operating and Financial Metrics

IDACORP’s and Idaho Power’s outlook for 2011 full year metrics is as follows:



	2011 Estimates
	Current⁽³⁾	Previous⁽⁴⁾
Idaho Power Operation & Maintenance Expense (millions)	No change	$300-$310
Idaho Power Capital Expenditures (millions)⁽¹⁾	No change	$320-$330
Idaho Power Hydroelectric Generation (million MWh)⁽²⁾	8.5-10.5	7.5-9.5
Non-regulated subsidiary earnings and holding company expenses (millions)	No change	$0.0-$3.0

(1) The range for capital expenditures includes amounts for the Langley Gulch power plant and expenditures for the siting and permitting of major transmission expansions for the Boardman to Hemingway and Gateway West transmission projects, excluding AFUDC.
(2) The range of estimated hydroelectric generation has been revised to reflect actual hydroelectric generation through March and estimated ranges of hydroelectric generation for the remainder of the year.
(3) As of May 5, 2011.
(4) As of February 23, 2011, the date of filing of IDACORP's and Idaho Power's Annual Report on Form 10-K for the year ended December 31, 2010.

RESULTS OF OPERATIONS

This section of the MD&A takes a closer look at the significant factors that affected IDACORP’s and Idaho Power’s earnings during the three months ended March 31, 2011. In this analysis, the results for the three months ended March 31, 2011 are compared to the same period in 2010.

Results for the Three Months Ended March 31, 2011

The following table presents net income (losses) for IDACORP and its subsidiaries for the three months ended March 31, 2011 and 2010:



	Three months ended March 31,
	2011			2010
Idaho Power – Utility operations	$	29,848		$	18,221
IDACORP Financial Services	35			(39		)
Ida-West Energy	233			177
IDACORP Energy	(26		)	197
Holding company	(350		)	(2,493		)
Net income attributable to IDACORP, Inc.	$	29,740		$	16,063
Average common shares outstanding (diluted, in 000’s)	49,356			47,885
Earnings per diluted share	$	0.60		$	0.34

Utility Operations

The table below presents Idaho Power’s energy sales and supply (in thousands of MWhs) for the three months ended March 31, 2011 and 2010:



	Three months ended March 31,
	2011		2010
General business sales	3,241		3,109
Off-system sales	849		766
Total energy sales	4,090		3,875
Hydroelectric generation	2,699		1,902
Coal generation	1,194		1,874
Natural gas and other generation	18		2
Total system generation	3,911		3,778
Purchased power	471		395
Line losses	(292	)	(298	)
Total energy supply	4,090		3,875

For the three months ended March 31, 2011, hydroelectric generation comprised 69 percent of Idaho Power’s total system generation and 62 percent of its total energy supply. Based on current reservoir levels, forecasted stream flow, and other conditions relevant to hydroelectric generation capacity, Idaho Power expects to generate between 8.5 and 10.5 million MWh from its hydroelectric facilities in 2011, compared to 7.3 million MWh in 2010. Idaho Power’s modeled median annual hydroelectric generation is 8.6 million MWh, based on hydrologic conditions for the period 1928 through 2010 and adjusted to reflect the current level of water resource development. The increase in hydroelectric generation during the first quarter of 2011 resulted in a decreased reliance on coal-fired generation, contributing to a $7.3 million decrease in fuel expense relative to the first quarter of 2010. Most of the incremental decrease in power supply costs that typically results from increased hydroelectric generation is returned to customers through the PCA mechanisms.

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

General business revenue: The following table presents Idaho Power’s general business revenues, MWh sales, and number of customers for the three months ended March 31, 2011 and 2010:



	Three months ended March 31,
	2011			2010
Revenue
Residential	$	117,268		$	111,595
Commercial	56,018			57,931
Industrial	31,951			36,118
Irrigation	621			676
Deferred revenue related to Hells Canyon
Complex relicensing AFUDC⁽¹⁾	(2,586		)	(2,575		)
Total	$	203,272		$	203,745
MWh
Residential	1,499			1,399
Commercial	964			931
Industrial	771			771
Irrigation	7			8
Total	3,241			3,109
Customers (period end)
Residential	408,862			406,771
Commercial	64,671			64,262
Industrial	126			128
Irrigation	18,530			18,561
Total	492,189			489,722

⁽¹⁾ As part of its February 1, 2009 general rate case order, the IPUC allowed Idaho Power to recover AFUDC for the Hells Canyon Complex relicensing asset even though the relicensing process in not yet complete and the relicensing asset has not been placed in service. Idaho Power expects to collect approximately $10.6 million annually, but will defer revenue recognition of the amounts collected until the license is issued and the asset is placed in service. This deferral offset revenues by approximately $2.6 million in the first quarter of 2011.

Changes in customer demand and changes in rates are the primary causes of fluctuations in general business revenue. Several significant rate actions have recently been implemented or are pending and are discussed further in “Regulatory Matters” in this MD&A and in Note 3 - “Regulatory Matters” to the condensed consolidated financial statements included in this report.

The primary influences on customer demand are weather and economic conditions. Extreme temperatures increase sales to customers who use electricity for cooling and heating, and moderate temperatures decrease sales. Precipitation levels during the agricultural growing season affect sales to customers who use electricity to operate irrigation pumps, with increased precipitation reducing electricity sales. The following table presents Boise, Idaho weather conditions for the three months ended March 31, 2011 and 2010:

General business revenue decreased $0.5 million in the first quarter of 2011 compared to the same period in 2010. The change is primarily attributable to the effects of rate changes offset by increases in customer usage attributable to cooler weather during the first quarter of 2011. These factors are discussed in more detail below:

• Rates: The following table presents notable rate increases and decreases, shown on an annualized basis, that affected results for the quarter:



		Percentage	Annualized
	Effective	Rate Increase	$ Impact
Description	Date	(Decrease)	(millions)
2010 Idaho settlement agreement	6/1/2010	9.9%	89
2010 Idaho PCA	6/1/2010	(16.4%)	(147	)
2010 Idaho pension expense recovery	6/1/2010	0.8%	5
2010 Idaho AMI	6/1/2010	0.4%	2
2010 Idaho FCA	6/1/2010	0.9%	4
2010 Oregon power cost update	6/1/2010	5.5%	2

These rate changes combined to reduce general business revenue by $10.4 million for the quarter. The revenue impact of several of these changes was directly offset by changes in operating expenses. For example, Idaho PCA amortization expense was reduced $22.5 million compared to the first quarter of 2010 due to the decrease in the corresponding Idaho PCA rate. The pension expense recovery and FCA rate changes were fully offset by related amortizations.

The 2010 Idaho settlement agreement included two components, an increase in base power supply costs of $64 million and a general base rate increase of $25 million. For more information related to the settlement agreement, see “Regulatory Matters” later in this MD&A.

• Usage: An increase in average amount used per customer improved general business revenue $8.7 million for the quarter, due primarily to cooler weather, which increases power demand for heating purposes during the winter months. Sales to residential customers increased seven percent in the first quarter relative to the same period in 2010.

• Customers: Growth in customer count contributed to an increase of $1.0 million in general business revenue for the first quarter compared to the same period in 2010. For the quarter, total customer count increased 0.5 percent compared to the same period in 2010.

Off-system sales: Off-system sales consist primarily of long-term sales contracts and opportunity sales of surplus system energy. The following table presents Idaho Power’s off-system sales for the three months ended March 31, 2011 and 2010:



	Three months ended March 31,
	2011		2010
Revenue	$	29,845	$	34,406
MWh sold	849		766
Revenue per MWh	$	35.15	$	44.92

Despite the increase in the volume of MWh sold, off-system sales revenue decreased $4.6 million, or 13 percent, for the first quarter of 2011 as compared to the same period of 2010 due to a 22 percent decrease in average prices. An increase in output from hydroelectric and wind resources throughout the region increased surplus power available for sale and decreased the market price.

Other revenues: The table below presents the components of other revenues for the three months ended March 31, 2011 and 2010:



	Three months ended March 31,
	2011		2010
Transmission services and other	$	11,234	$	9,275
Energy efficiency	6,711		5,034
Total	$	17,945	$	14,309

Transmission services revenue increased $2.0 million in the first quarter due to the new Hemingway substation operating agreement, which became effective in June 2010, and an increase in FERC transmission rates that took effect on October 1, 2010.

Energy efficiency activities are currently funded through a rider mechanism on customer bills. Energy efficiency program expenditures are reported as an operating expense with an equal amount of revenues recorded in other revenues, resulting in no net impact on earnings. The cumulative variance between expenditures and amounts collected through the rider is recorded as a regulatory asset or liability pending future collection from or obligation to customers. A liability balance indicates that Idaho Power has collected more than it has spent and an asset balance indicates that Idaho Power has spent more than it has collected. For the first quarter of 2011 as compared to the same period in 2010, Idaho Power increased its energy efficiency program expenses and matching revenues by $1.7 million. As of March 31, 2011, Idaho Power’s energy efficiency rider balance was a regulatory asset of $17 million, and Idaho Power expects the balance to decrease to $15 million by the end of 2011.

Purchased power: The following table presents Idaho Power’s purchased power expenses and volumes for the three months ended March 31, 2011 and 2010:



	Three months ended March 31,
	2011		2010
Purchased power expense	$	25,094	$	21,174
MWh purchased	471		395
Cost per MWh purchased	$	53.28	$	53.61

Purchased power expense increased $3.9 million, or 19 percent, for the quarter compared to the same period in 2010. Cogeneration and small power production purchases increased $5.8 million for the quarter as several new PURPA projects, which receive favorable rates, came on line. This increase was partially offset by a $1.7 million decrease in power purchased in the wholesale market due to improved hydroelectric conditions.

Fuel expense: The following table presents Idaho Power’s fuel expenses and generation at its thermal generating plants for the three months ended March 31, 2011 and 2010:



	Three months ended March 31,
	2011		2010
Expense
Coal	$	28,006	$	36,065
Natural gas and other	1,896		1,122
Total fuel expense	$	29,902	$	37,187
MWh generated
Coal	1,194		1,874
Natural gas and other	18		2
Total MWh generated	1,212		1,876
Cost per MWh
Coal	$	23.46	$	19.24
Natural gas and other	105.33		561.00
Weighted average, all sources	24.67		19.82

Fuel expense decreased $7.3 million, or 20 percent, for the quarter as compared to the same period in 2010 due to lower generation at the Bridger, Valmy, and Boardman plants. The output at these plants was down 679,484 MWh, or 36 percent, for the quarter as compared to the same period in 2010. The reduced output was primarily caused by lower regional power prices due to higher regional hydroelectric and wind production and lower natural gas prices. Idaho Power expects this trend of lower output to continue in the second quarter of 2011, as wholesale power prices are forecasted to continue to be low with above-normal hydrologic conditions and low natural gas prices. The impact of these reductions was partially offset by higher contract prices for coal. During 2010, Bridger and Valmy received force majeure tons and deferral tons from prior lower cost contracts. In 2011, there are no significant contract expirations and prices are expected to remain stable; however, most fuel supply contracts are subject to changes in published indexes that are closely related to materials and supplies, labor, and diesel costs. Output at the natural gas plants was higher this quarter due to real-time market economic dispatch decisions and dispatch for system reliability for certain periods.

In addition to commodity (variable) costs, both natural gas and coal expense include costs that are more fixed in nature for items such as capacity charges, transportation, and fuel handling. Period to period variances in fuel expense per MWh are noticeably impacted by this fact when generation output is substantially different between the two periods.

PCA mechanisms: PCA expense represents the effects of the Idaho and Oregon power supply cost adjustment mechanisms. The following table presents the components of the Idaho and Oregon PCA mechanisms for the three months ended March 31, 2011 and 2010:



	Three months ended March 31,
	2011		2010
Idaho power supply cost accrual	$	24,915	$	19,839
Oregon power supply cost accrual	465		44
Amortization of prior year authorized balances	5,926		28,441
Total power cost adjustment	$	31,306	$	48,324

Changes in the Idaho and Oregon PCA decreased expenses $17.0 million for the first quarter compared to the same period in 2010. The amortization of the prior year’s deferral decreased $22.5 million, which is also reflected in decreased rates for the period, and was partially offset by a $5.5 million increase in the current year accrual, the combined result of changes in forecast rates and base and actual power supply costs.

Other operations and maintenance expenses: Other operations and maintenance (O&M) expense decreased $1.4 million for the first quarter compared to the same period in 2010. The decrease was due to a reduction of $1.2 million in legal expenses, a reduction in customer-related expenses of $1.6 million due to the implementation of Advanced Metering Infrastructure (AMI)

and the completed amortization of demand-side management program expenses, and reduced thermal plant costs of $0.5 million due to economic shutdowns at the Bridger and Valmy plants resulting from low wholesale energy prices in the region. Those decreases were partially offset by a $1.9 million increase related to the recovery of Idaho-jurisdiction pension expense that began in June 2010.

Income Taxes

Income Tax Expense: IDACORP's and Idaho Power's income tax expense for the three months ended March 31, 2011 relative to the same period in 2010 increased $3.6 million and $4.9 million, respectively, primarily as a result of higher pre-tax earnings. For information relating to IDACORP's and Idaho Power's computation of income tax expense and estimated annual effective tax rate, see Note 2 - “Income Taxes” to the condensed consolidated financial statements included in this report.

Idaho Power's January 2010 settlement agreement with the IPUC and other parties provided for additional amortization of 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. As of the date of this report, Idaho Power expects to record approximately $15 million of ADITC amortization for the full year 2011 based on its estimate of 2011 Idaho jurisdictional return on year-end equity. The amount of ADITC recorded during 2011 could change significantly based on Idaho Power's actual 2011 net income.

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 IRS, subject to subsequent review by the 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.

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. Idaho Power expects that the increased deduction would produce approximately $5 to $6 million of additional tax benefit annually. IDACORP and Idaho Power cannot predict exactly when the Joint Committee will complete its review or the outcome of that review, but believe the likelihood of receiving a determination in 2011 is enhanced given the case was submitted in April 2011.

ADITC Amortization and Revenue Sharing: Idaho Power's estimate of additional ADITC amortization for 2011 will be reduced by any tax benefits from the capitalized repair method change settlement; however, other changes in 2011 operating results may increase or decrease the estimate of additional ADITC amortization. Idaho Power anticipates that recognition of the tax benefits associated with the uniform capitalization method change would increase Idaho Power's estimated 2011 Idaho jurisdictional return on year-end equity above 9.5 percent, thus eliminating its ability to amortize additional ADITC for 2011. Any previously recorded 2011 additional amortization would be reversed in the quarter during which the tax benefits from the uniform capitalization method change are recognized.

Further, the January 2010 Idaho settlement agreement provides that if Idaho Power's return on year-end equity exceeds 10.5 percent in the Idaho jurisdiction for 2011, Idaho Power is required to share with Idaho customers 50 percent of the earnings in excess of the 10.5 percent return. If Idaho Power's 2011 net income reaches the 10.5 percent return level as provided for in the Idaho settlement, Idaho Power estimates that earnings at IDACORP would approximate $3.15 to $3.25 per share, beyond which sharing would begin. This estimate is based on assumptions including the levels of net income, year-end common equity, and jurisdictional allocations and could vary significantly based on actual results.

Bonus Depreciation Legislation: The Small Business Jobs Act (Jobs Act) and the Tax Relief, Unemployment Insurance Reauthorization, and Job Creation Act of 2010 (Tax Relief Act) includes provisions for the extension and increase of bonus depreciation. Bonus depreciation provides for the accelerated deduction of current capital expenditures from certain asset classes. The Jobs Act extended 50 percent bonus depreciation to 2010 and the Tax Relief Act extended bonus depreciation to 2011-2012 and increased it to 100 percent for a portion of 2010 and 2011. Idaho Power has included an estimated bonus deprecation deduction in its current income tax provision. The estimated deduction would reduce Idaho Power's 2011 federal income tax liability by approximately $42 million. The State of Idaho did not conform to the federal bonus depreciation rules for 2010-2012.

LIQUIDITY AND CAPITAL RESOURCES

Overview

IDACORP's operating cash flows are driven principally by Idaho Power, and the primary source of operating cash flows for Idaho Power is sales of electricity and transmission capacity. General business revenues and the costs to supply power to general business customers, and the timing of income tax payments, are factors that have the greatest impact on Idaho Power's operating cash flows and are subject to risks and uncertainties relating to power generation conditions and Idaho Power's ability to obtain rate relief to cover its operating costs and provide a return on investment.

Significant uses of cash flows from Idaho Power's utility operations include the purchase of electricity, the purchase of fuel for power generation, and payment of other operating expenses, taxes, and interest, with any excess amount being available for other uses such as capital expenditures and the payment of dividends. Idaho Power is experiencing a cycle of heavy infrastructure investment, adding capacity to its baseload generation, transmission system, and distribution facilities in an effort to ensure an adequate supply of electricity, to provide service to new customers, and to maintain system reliability. Idaho Power's aging hydroelectric and thermal generation facilities require continuing upgrades and component replacement, and the costs related to relicensing hydroelectric facilities and complying with the new licenses are substantial. Due to heavy infrastructure requirements in the near term, Idaho Power has been focused on critical infrastructure needs that relate to system reliability and resource adequacy, and expects that total capital expenditures will be between $770 million and $800 million from 2011 through 2013.

Idaho Power's operating cash flows usually do not fully support the amount required for utility capital expenditures, particularly during a period of heavy infrastructure development as is presently occurring. Idaho Power uses operating and capital budgets to control operating costs and optimize capital expenditures, and funds its liquidity needs for capital expenditures through cash flows from operations, debt offerings, commercial paper markets, credit facilities, and capital contributions from IDACORP. Idaho Power seeks to recover its operating costs and earn a return on its capital expenditures through rates, periodically filing for rate adjustments for recovery of operating costs and capital investments to provide the opportunity to align Idaho Power's earned returns with those allowed by regulators.

IDACORP and Idaho Power expect minimal need for external financing in 2011, other than issuances under the dividend reinvestment and employee-related plans and potentially issuances of IDACORP common stock pursuant to IDACORP's continuous equity program. A significant focus for the remainder of 2011 will continue to be to generate sufficient cash from operations to meet operating needs and contribute to capital projects by managing recovery of costs through the regulatory process and by controlling costs.

Beyond 2011, IDACORP and Idaho Power expect to continue financing capital requirements with a combination of internally generated funds and externally financed capital. Idaho Power expects it will continue to be engaged in significant construction projects during the coming years, and has $100 million of first mortgage bonds maturing in November 2012. In addition, IDACORP's and Idaho Power's credit facilities expire in April 2012. Maintaining or improving IDACORP's and Idaho Power's credit ratings will be important in negotiating favorable financing terms under new credit facilities and future first mortgage bond or other debt issuances.

As of March 31, 2011, IDACORP's and Idaho Power's access to debt, equity, and credit arrangements include:


•	their respective $100 million and $300 million revolving credit facilities;


•	IDACORP's shelf registration statement, which can be used for the issuance of debt securities and common stock, including equity securities under its continuous equity program; approximately $539 million remained available as of March 31, 2011;


•	Idaho Power's shelf registration statement, which can be used for the issuance of first mortgage bonds and debt securities; $300 million remained available as of March 31, 2011; and


•	IDACORP's and Idaho Power's issuance of commercial paper, which can be used to meet short-term liquidity requirements.

The conditions of the capital markets in recent periods and the weak economy have in recent years caused a general concern regarding access to sufficient capital at a reasonable cost. However, IDACORP and Idaho Power have not been significantly impacted by this disruption in the credit environment, including in the commercial paper markets, and currently expect to continue to be able to access the capital markets to meet short- and long-term borrowing needs.

Operating Cash Flows

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

IDACORP’s and Idaho Power’s operating cash inflows for the three months ended March 31, 2011, were $93 million and $102 million, respectively. IDACORP's operating cash flows decreased by $7 million while Idaho Power’s operating cash flows increased by $2 million compared to the three months ended March 31, 2010. With the exception of cash flows related to income taxes, IDACORP’s operating cash flows are principally derived from the operating cash flows of Idaho Power. Significant items that affected the companies' operating cash flows in the first three months of 2011 and 2010 are as follows:


•	income before income taxes increased by $17 million for IDACORP and Idaho Power;

• cash inflows related to income taxes increased by $11 million and $19 million for IDACORP and Idaho Power, respectively. IDACORP received income tax refunds of nearly $13 million this year compared with $1 million for the same period in 2010. Idaho Power’s net refunds from IDACORP for income tax were $22 million for the three months ended March 31, 2011, compared with $3 million for the same period in 2010;


•	changes in regulatory assets associated with the Idaho and Oregon PCA mechanisms reduced cash flows by $17 million, as Idaho Power collected $23 million less of previously deferred costs partially offset by a $6 million increase in the current year accrual, as compared with the first three months of 2010;

• changes in accounts receivable and unbilled revenues resulted in an $8 million reduction in cash flows. During the first quarter of 2011, the balances of accounts receivable and unbilled revenues decreased by $8 million less than they decreased during the same period in 2010, resulting in a reduction in cash collected in excess of the revenues recorded; and


•	a $6 million increase in fuel inventories during the first quarter of 2011 compared with a slight decrease during the same period in 2010 reduced cash flows.

For at least the period 2011 to 2014, Idaho Power expects to make significant cash contributions to its pension plan and has significant obligations under other postretirement benefit plans. See Note 10 - “Benefit Plans” to the condensed consolidated financial statements included in this report for additional information relating to Idaho Power’s pension plan funding and postretirement benefit obligations, and Note 3 - “Regulatory Matters” to the condensed consolidated financial statements included in this report for a discussion of Idaho Power’s recovery of pension plan contributions through the ratemaking process.

Investing Cash Flows

Cash flows from investing activities consist primarily of capital expenditures related to new construction and improvements to Idaho Power’s distribution, transmission, and generation facilities. IDACORP’s and Idaho Power’s investing cash outflows were $100 million for the three months ended March 31, 2011, an increase of $29 million and $31 million for IDACORP and Idaho Power, respectively, compared to the three months ended March 31, 2010. Investing cash outflows for 2011 were primarily for construction of utility infrastructure needed to address Idaho Power’s peak demand growth, aging plant and equipment, and forecasted customer growth.

Financing Cash Flows

Financing activities provide supplemental cash for both day-to-day operations and capital requirements as needed. Idaho Power funds liquidity needs for capital investment, working capital, energy and price hedging, and other financial commitments through cash flows from continuing operations, public debt offerings, commercial paper markets, and credit facilities. IDACORP funds its cash requirements, such as payment of taxes, capital contributions to Idaho Power, and non-utility expenses allocated to IDACORP, through cash flows from operations, commercial paper markets, sales of common stock, and credit facilities.

IDACORP’s and Idaho Power’s financing cash outflows for the three months ended March 31, 2011, were $128 million and $136 million, respectively. The following are significant items that affected financing cash flows in 2011:

• on March 2, 2011, Idaho Power repaid at maturity $120 million of its first mortgage bonds using proceeds from first mortgage bonds issued in August 2010;

• IDACORP and Idaho Power paid cash dividends of $15 million; and

• IDACORP had net borrowings of $7 million of commercial paper.

Idaho Power's next upcoming material long-term debt repayment obligation is its $100 million of first mortgage bonds that mature in November 2012.

Financing Programs

IDACORP's consolidated capital structure consisted of common equity of 50 percent and debt of 50 percent at March 31, 2011. Idaho Power's consolidated capital structure consisted of common equity of 49 percent and debt of 51 percent at March 31, 2011.

Shelf Registrations: IDACORP has an effective registration statement that as of the date of this report can be used for the issuance of up to $539 million of debt securities and common stock. Idaho Power has an effective registration statement that as of the date of this report can be used for the issuance of up to $300 million of first mortgage bonds and unsecured debt. Refer to Note 4 - “Long-Term Debt” to IDACORP's and Idaho Power's condensed consolidated financial statements included in this report for more information regarding long-term financing arrangements.

The issuance of first mortgage bonds requires that Idaho Power meet interest coverage and security provisions set forth in the Indenture of Mortgage and Deed of Trust securing the bonds. Future issuances of first mortgage bonds are subject to satisfaction of covenants and security provisions set forth in the Indenture of Mortgage and Deed of Trust, market conditions, regulatory authorizations, or by covenants and tests contained in other financing agreements. The Indenture of Mortgage and Deed of Trust limits the amount of additional first mortgage bonds that Idaho Power may issue to the sum of (a) the principal amount of retired first mortgage bonds and (b) 60 percent of total unfunded property additions. As of March 31, 2011, Idaho Power could issue approximately $1.2 billion of additional first mortgage bonds based on retired first mortgage bonds and total unfunded property additions. However, the Indenture of Mortgage and Deed of Trust further limits the maximum amount of first mortgage bonds at any one time outstanding to $2.0 billion, and as a result the maximum amount of first mortgage bonds Idaho Power could issue as of March 31, 2011 was limited to approximately $539 million. Idaho Power may increase the $2.0 billion limit on the maximum amount of first mortgage bonds outstanding by filing a supplemental indenture with the trustee as provided in the Indenture of Mortgage and Deed of Trust.

Credit Facilities: IDACORP and Idaho Power each have a five-year credit agreement that terminates on April 25, 2012, to be used for general corporate purposes and commercial paper back-up, and that provide for the issuance of loans and standby letters of credit. IDACORP's facility permits borrowings of up to $100 million at any one time outstanding, which may be increased upon request, subject to specified conditions, to $150 million. Idaho Power's facility permits borrowings of up to $300 million at any one time outstanding, which may be increased upon request, subject to specified conditions, to $450 million. Each company may request one-year extensions of the then-existing termination date. Interest on borrowings under the facilities is a Eurodollar rate or a floating rate, plus a margin determined by the company's ratings on its senior unsecured long-term debt securities. The companies also pay a utilization fee and a facility fee.

Each facility contains a covenant requiring a leverage ratio of consolidated indebtedness to consolidated total capitalization of no more than 65 percent as of the end of each fiscal quarter. In determining the leverage ratio, “consolidated indebtedness” broadly includes all indebtedness of the respective borrower and its subsidiaries, excluding indebtedness evidenced by certain hybrid securities (as defined in the credit agreement). “Consolidated total capitalization” is calculated as the sum of all

consolidated indebtedness, consolidated stockholders' equity of the borrower and its subsidiaries, and the aggregate value of outstanding hybrid securities. At March 31, 2011, the leverage ratios for IDACORP and Idaho Power were 50 percent and 51 percent, respectively. IDACORP's and Idaho Power's ability to utilize the credit facilities is conditioned upon their continued compliance with the leverage ratio covenants included in the credit facilities, which could limit the ability of the companies to issue first mortgage bonds and debt securities. There are additional covenants, subject to exceptions, that prohibit or restrict certain investments or acquisitions, mergers or sale or disposition of property without consent, the creation of certain liens, and any agreements restricting dividend payments from any material subsidiary. At March 31, 2011, IDACORP and Idaho Power were in compliance with all facility covenants.

The events of default under the facilities include nonpayment of principal, interest, and fees, when due or subject to a grace period; materially false representations or warranties; breach of covenants, subject in some instances to grace periods; bankruptcy or insolvency-related events; default in the payment of indebtedness in excess of $25 million, defaults that will permit acceleration of such debt, or the acceleration of any of such debt; the acquisition of 20 percent of the outstanding voting shares of the company; the failure of IDACORP to own all of the outstanding voting stock of Idaho Power; any reportable event occurring with any employee pension benefit plan as defined by the Internal Revenue Code or the Employee Retirement Income Security Act of 1974 (ERISA); failure to meet minimum funding standards for any employee pension benefit plan under the Internal Revenue code or ERISA; notice provided by Idaho Power to terminate an employee pension benefit plan if the plan's unfunded liabilities exceed $75 million; and environmental proceedings, investigations, or violations of law which could reasonably be expected to have a material adverse effect.

A default or an acceleration of indebtedness of IDACORP or Idaho Power in excess of $25 million, including indebtedness under the applicable facility, will result in a cross default under the other facility. Upon any bankruptcy or insolvency-related event of default, the obligations of the lenders to make loans under the facility will automatically terminate and all unpaid obligations will become due and payable. Upon any other event of default, the lenders holding more than 50 percent of the outstanding loans or of the aggregate commitments may terminate or suspend the obligations to make loans or declare the obligations to be due and payable.

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

Without additional approval from the IPUC, the OPUC, and the Public Service Commission of Wyoming, the aggregate amount of short-term borrowings by Idaho Power at any one time outstanding may not exceed $450 million.

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



	March 31, 2011						December 31, 2010
				Idaho						Idaho
	IDACORP(2)			Power			IDACORP(2)			Power
Revolving credit facility	$	100,000		$	300,000		$	100,000		$	300,000
Commercial paper outstanding	(74,100		)	—			(66,900		)	—
Identified for other use (1)	—			(24,245		)	—			(24,245		)
Net balance available	$	25,900		$	275,755		$	33,100		$	275,755
(1) Port of Morrow and American Falls bonds that holders may put to Idaho Power.
(2) Holding company only.

At April 29, 2011, IDACORP had no loans under its credit facility and $72.9 million of commercial paper outstanding, and Idaho Power had no loans under its credit facility and no commercial paper outstanding.

The following table presents additional information about short term borrowing during the three-month period ended March 31, 2011:



	Three months ended March 31, 2011
	IDACORP ⁽¹⁾			Idaho Power
Commercial paper:
Period end:
Amount outstanding	$	74,100		$	—
Weighted average interest rate	0.40		%	—		%
Daily average amount outstanding during the period	$	69,850		$	—
Weighted average interest rate during the period	0.40		%	—		%
Maximum month-end balance	$	74,400		$	—

(1) Holding company only

Impact of Credit Ratings on Liquidity

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



	S&P		Moody’s
	Idaho		Idaho
	Power	IDACORP	Power	IDACORP
Corporate Credit Rating/Long-Term Issuer Rating	BBB	BBB	Baa 1	Baa 2
Senior Secured Debt	A-	None	A2	None
Senior Unsecured Debt	BBB	None	Baa 1	None
Short-Term Tax-Exempt Debt	BBB/A-2	None	Baa 1/ VMIG-2	None
Commercial Paper	A-2	A-2	P-2	P-2
Senior Unsecured Credit Facility	None	None	Baa 1	Baa 2
Rating Outlook	Stable	Stable	Stable	Stable

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

Idaho Power maintains margin agreements relating to its wholesale commodity contracts that allow performance assurance collateral to be requested of and/or posted with certain counterparties. As of March 31, 2011, Idaho Power had posted approximately $2.7 million of assurance collateral. Should Idaho Power experience a reduction in its credit rating on Idaho Power’s unsecured debt to below investment grade Idaho Power could be subject to additional requests by its wholesale counterparties to post additional performance assurance collateral. Counterparties to derivative instruments and other forward contracts could request immediate payment or demand immediate ongoing full daily collateralization on derivative instruments and contracts in net liability positions. Based upon Idaho Power’s current energy and fuel portfolio and market conditions as of March 31, 2011, the approximate amount of additional collateral that could be requested upon a downgrade to below investment grade is approximately $14 million. Idaho Power actively monitors the portfolio exposure and the potential exposure to additional requests for performance assurance collateral calls, through sensitivity analysis, to minimize capital requirements.

Capital Requirements

Idaho Power is experiencing a cycle of heavy infrastructure investment, adding capacity to its baseload generation, transmission system, and distribution facilities to ensure an adequate supply of electricity, to provide service to new customers, and to maintain system reliability. Idaho Power's aging hydroelectric and thermal generation facilities require continuing upgrades and component replacement, and the costs related to relicensing hydroelectric facilities and complying with the new licenses are substantial. Due to these heavy infrastructure requirements, Idaho Power will continue to focus on critical infrastructure needs that relate to system reliability and resource capacity and adequacy and has reduced ongoing capital expenditures and major projects from prior estimates. Capital projects are subject to continuing review and are revised in light of changes in financial and economic conditions, load forecasts, legislative and regulatory developments, and changing environmental standards, among other factors. Idaho Power's ability to complete capital projects will be affected by its financial condition, the availability of internal funds, and the cost of external funds.

Idaho Power expects that total capital expenditures will be between $770 million and $800 million from 2011-2013. Internal cash generation after dividends is expected to provide less than the full amount of total capital requirements during that period. While circumstances could change, IDACORP and Idaho Power expect minimal need for external financing in 2011, other than issuances under the dividend reinvestment and employee-related plans and potentially issuances of IDACORP common stock pursuant to its continuous equity program. Beyond 2011, IDACORP and Idaho Power expect to continue financing capital requirements with a combination of internally generated funds and externally financed capital. As discussed above, for future external financing needs IDACORP and Idaho Power have shelf registration statements available for the issuance of equity (in the case of IDACORP only) and debt securities, as well as credit facilities.

Idaho Power's construction expenditures were $102 million and $69 million during the three month periods ended March 31, 2011 and 2010, respectively. The following table presents Idaho Power's estimated cash requirements for construction, excluding AFUDC, for 2011 through 2013 (in millions of dollars):



	2011	2012-2013
Ongoing capital expenditures	$190-192	$400-411
Langley Gulch Power Plant (detailed below)	126-130	30-34
Other major projects	4-8	20-25
Total	$320-330	$450-470

Major Infrastructure Projects:

Idaho Power is engaged in the development of a number of significant projects, and has entered into and is in discussions with third parties concerning arrangements for joint infrastructure development. The discussion below provides a summary of notable developments with respect to these projects during the three months ended March 31, 2011 and since the discussion of these matters included in Part II, Item 7 - “MD&A - Capital Requirements” in IDACORP's and Idaho Power's Annual Report on Form 10-K for the year ended December 31, 2010.

Langley Gulch Power Plant:

The Langley Gulch Power Plant is a natural gas-fired combined cycle combustion turbine generating plant with a summer nameplate capacity of approximately 300 MW and a winter capacity of approximately 330 MW. Construction of the plant, substation, and transmission lines is underway. The plant is being constructed near New Plymouth, Idaho and is contracted to achieve commercial operation by November 1, 2012. Based on contract incentives and the current project status, Idaho Power estimates that the plant will be in service by June 2012. The commitment estimate for the project is $427 million, $254 million of which Idaho Power has incurred from inception in 2009 through March 31, 2011. AFUDC is included in both amounts. As of the date of this report, the overall project remains on schedule and Idaho Power expects the total project cost to be at or below the commitment estimate.

During the first quarter of 2011, plant construction activities continued. Major equipment incorporated into the project during the first quarter of 2011 included the balance of the combustion turbine equipment, heat recovery steam generator drums, condenser, and various pumps and tanks. As of the date of this report, the water delivery system that will provide cooling water to the site is under construction with the pipeline completed during the first quarter of 2011 and the pumping station under construction. The natural gas delivery system is under final design and construction is expected to begin in the summer of 2011. The plant will connect to Idaho Power's existing grid through a new substation and two new transmission lines. The substation is under construction and on schedule. One of the new transmission lines has been constructed and has been incorporated into the grid, while the other is under design. The second line is expected to be complete by May 2012.

Transmission Projects:

Idaho Power continues to focus on expansion of its existing transmission system in an effort to improve system reliability and resource adequacy. Two current significant transmission projects include the Boardman-Hemingway line, a proposed 299 mile, 500-kV transmission project between a substation near Boardman, Oregon and the Hemingway station near Boise, Idaho; and Idaho Power's and PacifiCorp's pursuit of the joint development of the Gateway West project to build transmission lines between Windstar, a station located near Douglas, Wyoming, and the Hemingway station.

Termination of Memorandum of Understanding:

On March 5, 2010, Idaho Power and PacifiCorp entered into a Memorandum of Understanding (MOU) under which Idaho Power and PacifiCorp agreed to negotiate in good faith to reach arrangements pertaining to the sale by the parties to one another of an undivided ownership interest in certain transmission facilities, and joint development and construction of three transmission projects. The parties also agreed to negotiate in good faith to reach arrangements pertaining to interconnection of their respective systems; joint ownership, operation, and maintenance of parts of the systems; cost-sharing; capital improvements; and each party's rights to a specified transmission capacity on applicable transmission lines. The MOU further provided that Idaho Power and PacifiCorp would negotiate in good faith to attempt to reach an agreement to terminate existing transmission capacity rights agreements over portions of Idaho Power's existing transmission system and replace them with new agreements, if required. The MOU provided that it may be terminated by either party at any time.

In connection with the MOU, in April 2010 Idaho Power entered into a Joint Purchase and Sale Agreement with PacifiCorp, pursuant to which Idaho Power agreed to sell to PacifiCorp an interest in certain high-voltage transmission-related and interconnection equipment located at the Hemingway station, and PacifiCorp agreed to sell to Idaho Power an interest in certain high-voltage transmission-related and interconnection equipment located at PacifiCorp's Populus station in southeast Idaho. Closing of the purchase and sale occurred in May 2010, and the parties subsequently executed Joint Ownership and Operating Agreements that specify the parties' relative rights and obligations as to the Hemingway and Populus substations.

In subsequent months, Idaho Power and PacifiCorp sought to negotiate the terms and conditions of the other arrangements contemplated by the MOU. The parties were unable to reach agreement on those arrangements, and on April 26, 2011, Idaho Power notified PacifiCorp that it was terminating the MOU, effective as of that date. Notwithstanding termination of the MOU, Idaho Power intends to continue pursuing the joint development of the Boardman-Hemingway transmission line with one or more parties and continue its participation with PacifiCorp in the permitting process for the Gateway West transmission project.

AMI/Smart Grid (American Recovery and Reinvestment Act of 2009 (ARRA)):

The AMI project provides the means to automatically retrieve energy consumption information, eliminating manual meter reading expense. Idaho Power intends to install this technology for approximately 99 percent of its customers and is on pace to complete the installations by the end of 2011. As of March 31, 2011, Idaho Power had installed approximately 378,000 AMI meters at a cost of $56 million. The total cost estimate for the project is approximately $74 million. The 2011 estimated costs are included in the Capital Requirements table above.

Under the ARRA, Idaho Power was awarded a grant of $47 million from the DOE. This grant matches a $47 million investment by Idaho Power in Smart Grid technology, including AMI. The grant was signed by the DOE on April 2, 2010 and applies to project costs incurred beginning in August 2009. As of March 31, 2011, Idaho Power had invoiced approximately $23 million from the DOE, of which $20 million had been received, and expects to continue billing and collecting monthly over the three-year term of the award. The costs to be reimbursed by the grant are not included in the Capital Requirements table above.

Contractual Obligations

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

Dividends

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

dividends on its common stock is dependent upon dividends paid to it by its subsidiaries, primarily Idaho Power. For additional information relating to IDACORP and Idaho Power dividends, including restrictions on IDACORP’s and Idaho Power’s payment of dividends, see Note 6 – “Common Stock” to the condensed consolidated financial statements included in this report.

REGULATORY MATTERS

Overview

As a regulated utility, many of Idaho Power's fundamental business decisions are subject to the approval of governmental agencies. Idaho Power is under the retail jurisdiction (as to rates, service, accounting, and other general matters of utility operation) of the IPUC and the OPUC, which determine the rates that Idaho Power charges to its general business customers. Idaho Power is also under the regulatory jurisdiction of the IPUC, the OPUC, and the Public Service Commission of Wyoming as to the issuance of debt and equity securities. Also, as a public utility under the Federal Power Act, Idaho Power has authority to charge market-based rates for wholesale energy sales under its FERC tariff and to provide transmission services under its FERC OATT. Idaho Power uses general rate cases, cost adjustment mechanisms, and subject-specific filings to recover its costs of providing service and the costs of its energy efficiency and demand-side resources programs, seeking to earn a return on investment.

In addition to the discussion below, which includes notable regulatory developments during the quarter ended March 31, 2011 and since the discussion of these matters in Item 7 of IDACORP's and Idaho Power's Annual Report on Form 10-K for the year ended December 31, 2010, refer to Note 3 - “Regulatory Matters” to the condensed consolidated financial statements included in this report for additional information and updates relating to Idaho Power's regulatory matters and recent regulatory filings, including information on the following pending rate applications:


•	annual Idaho fixed cost adjustment filing, requesting an aggregate increase of $3.0 million in FCA rates;


•	recovery of cash contributions to Idaho Power's defined benefit pension plan, requesting recovery of the Idaho-allocated portion of those contributions of $17.1 million annually, an increase of $11.7 million over current rates;


•	annual Idaho PCA filing, requesting a $40.4 million reduction to current Idaho PCA rates for the period from June 1, 2011 to May 31, 2012, which amount is net of Idaho Power’s additional request in the application to recover in Idaho PCA rates $10.0 million of the energy efficiency rider deferral balance that the IPUC had previously authorized for recovery;


•	request that the IPUC designate Idaho Power's Idaho-allocated expenditures of $42.5 million in energy efficiency rider funds incurred in 2010 as prudently incurred expenses and authorized for recovery through rates; and


•	annual power cost update filing for the Oregon PCA, requesting a $0.9 million decrease in amounts collected in Oregon jurisdiction customer rates.

Change in Deferred Net Power Supply Costs

Idaho Power's power supply costs can vary significantly from year to year, primarily because of the impacts of weather, system loads, and commodity markets. To address the volatility of power supply costs, Idaho Power has PCA mechanisms in both Idaho and Oregon. These mechanisms allow Idaho Power to recover from or refund to customers most of the fluctuations in power supply costs. Because of these mechanisms, the primary financial impacts of power supply cost variations is that cash is paid out but recovery from customers does not occur until a future period, or cash that is collected is refunded to customers, resulting in fluctuations in operating cash flows from year to year. A summary of the changes in deferred power supply costs during the three months ended March 31, 2011 is set forth below:



	Idaho			Oregon(1)			Total
Balance at December 31, 2010	$	17,559		$	12,194		$	29,753
Current period net power supply costs accrued	(24,915		)	(465		)	(25,380		)
Prior costs expensed and recovered through rates	(5,394		)	(532		)	(5,926		)
SO₂ allowance and renewable energy certificate (REC) sales	(1,684		)	(278		)	(1,962		)
Interest and other	(29		)	170			141
Balance at March 31, 2011	$	(14,463	)	$	11,089		$	(3,374	)
(1) Oregon power supply cost deferrals are subject to a statute that specifically limits rate amortizations of deferred costs to six percent of gross Oregon revenue per year (approximately $2 million). Deferrals are amortized sequentially.

Idaho Settlement Agreement and General Rate Case Notification

On January 13, 2010, the IPUC approved a rate settlement agreement among Idaho Power, several of Idaho Power's customers, the IPUC Staff, and other parties. The settlement agreement contains four important elements: (1) a general rate freeze until January 1, 2012, with some exceptions; (2) a specified distribution of the expected 2010 Idaho PCA decrease to directly reduce customer rates, providing some general rate relief to Idaho Power and resetting base level power supply costs for the Idaho PCA going forward; (3) use of investment tax credits to help achieve a minimum 9.5 percent return on year-end equity in the Idaho jurisdiction; and (4) an equal sharing of any Idaho earnings exceeding the authorized return on year-end equity of 10.5 percent. As a result of the moratorium on general rate relief included in the settlement agreement, Idaho Power's first opportunity to file a new general rate case with the IPUC is June 2011.

On March 31, 2011, Idaho Power filed with the IPUC a notification of its intent to file a general rate case with the IPUC on or after June 1, 2011. While filing of the notice of intent is a prerequisite to filing a general rate case, filing of the notice does not obligate Idaho Power to file a general rate case with the IPUC, and Idaho Power continues to evaluate its general rate case needs and options.

PURPA Power Purchase Contracts

Pursuant to the requirements of Section 210 of PURPA, the IPUC and OPUC have each issued orders and rules regulating Idaho Power's purchase of power from cogeneration and small power production facilities. A key component of the PURPA power purchase contracts is the energy price contained within the agreements. Regulatory mandated execution of PURPA agreements may result in Idaho Power acquiring energy at above wholesale market prices and at times when a surplus already exists as well as requiring additional operational integration measures, thus increasing costs to Idaho Power's customers. Substantially all PURPA power purchase costs are recovered through base rates and Idaho Power's power supply cost mechanisms, and thus the primary impact of the PURPA agreements is on customer rates.

In response to a November 5, 2010 application filed by Idaho Power and two other electric utilities with Idaho service territories, on February 7, 2011, the IPUC issued an order temporarily reducing the eligibility cap for projects entitled to published avoided cost rates from 10 average MW to 100 kW for wind and solar PURPA projects while the IPUC further investigates the implications of large projects disaggregating into smaller projects to qualify for higher published avoided cost rates and other benefits. On March 28, 2011, the IPUC denied the portion of a petition for reconsideration filed by an intervening party that sought reinstatement of the 10 average MW eligibility cap for the published avoided cost rate.

Modifications to Idaho Jurisdiction Irrigation Peak Rewards Program

On December 10, 2010, Idaho Power filed an application with the IPUC requesting an order authorizing prospective changes to its irrigation peak rewards program. The irrigation peak rewards program is a voluntary load control program available to agricultural irrigation customers, and its purpose is to decrease Idaho Power's system summer load peak by interrupting service, within specified parameters, to specified irrigation pumps with the use of load control devices between the period from June 15 to August 15 of each year. In exchange for interruption of electric service, participating customers receive a credit for usage during the applicable months. The cost of the program was $13.3 million and $9.7 million in 2010 and 2009, respectively. The bulk of program incentive payments are currently recovered in Idaho and Oregon through the energy efficiency riders.

Idaho Power's application proposed to change the incentive structure for the program from a 100 percent fixed incentive payment methodology to a methodology that combines a 40 percent fixed and 60 percent variable incentive payment to better align annual program costs with capacity needs. On March 9, 2011, the IPUC issued an order approving a change in the incentive payment amount to include a 75 percent fixed and a 25 percent variable portion, with payment of the variable incentive amounts to occur within 45 days after the close of each program season. As a result of this order, Idaho Power estimates program cost savings, based on historical program usage and depending on variables such as the number of participants and number and extent of service interruptions, of up to $2 million per year relative to the prior incentive payment structure. However, if the program was fully utilized with a maximum number of authorized interruptions and increased participation, program costs under the revised methodology could be greater than under the prior methodology.

Bonneville Power Administration Residential Exchange Program

The Pacific Northwest Electric Power Planning and Conservation Act of 1980, through the Residential Exchange Program (REP), has provided access to the benefits of low-cost federal hydroelectric power to residential and small farm customers of the region's investor-owned utilities (IOUs). The program is administered by the Bonneville Power Administration (BPA).

Pursuant to agreements between the BPA and Idaho Power, benefits from the REP were passed through to Idaho Power’s Idaho and Oregon residential and small farm customers in the form of electricity bill credits. However, on May 3, 2007, the U.S. Court of Appeals for the Ninth Circuit ruled that the settlement agreements entered into between the BPA and the IOUs (including Idaho Power) are inconsistent with the Northwest Power Act. As a result, on May 21, 2007, the BPA notified Idaho Power and six other IOUs that it was immediately suspending the REP payments. Since that time, Idaho Power has been working with other northwest IOUs and consumer-owned utilities, northwest state public utility commissions, and the BPA to craft an agreement so that residential and small farm customers of Idaho Power can resume sharing in the benefits of the federal Columbia River power system. In April 2011, pursuant to a previously executed Agreement in Principle, numerous parties approved a settlement agreement resolving challenges over BPA's implementation of the REP; however, the settlement agreement failed to receive approval from a pre-established threshold of customers and therefore did not become effective. Notwithstanding disapproval of the initial settlement agreement, certain of the parties are continuing to work toward a revised settlement. Since any benefits, other than any RECs to which Idaho Power may be entitled, would pass directly through to Idaho Power's eligible residential and small farm customers, any resulting settlement arrangement is not expected to have a material effect on Idaho Power's financial condition or results of operations.

FERC Compliance Programs

The FERC has approved an extensive number of reliability standards developed by the North American Electric Reliability Corporation and the Western Electricity Coordinating Council (WECC), including critical infrastructure protection (CIP) standards and regional standard variations. As part of its compliance program, Idaho Power periodically reviews its operations for compliance with FERC rules, orders, and standards and self-reports compliance issues to the FERC and the WECC. Recent reports Idaho Power has submitted to the FERC have generally focused on Standards of Conduct and Idaho Power’s FERC OATT. Idaho Power has also self-reported matters relating to CIP and other reliability standards to the WECC. During the three months ended March 31, 2011, Idaho Power self-reported to the FERC and received notices of alleged violations from the FERC and the WECC. Idaho Power has also received notification that the FERC intends to take no further action regarding several issues previously reported by Idaho Power. Consistent with its historical practice, Idaho Power is working with the FERC and the WECC to resolve alleged violations and items it self-reported to the FERC and the WECC. Idaho Power is unable to predict what action, if any, the WECC or the FERC will take on those unresolved matters, but Idaho Power does not expect any material adverse effect on its financial position, results of operations, or cash flows. Idaho Power plans to continue its policy of reducing potential violations through its compliance program and self-reporting compliance issues to, and working with, the FERC and the WECC.

Relicensing of Hydroelectric Projects

Costs for the relicensing of Idaho Power's hydroelectric projects are recorded in construction work in progress until new multi-year licenses are issued by the FERC, at which time the charges are transferred to electric plant in service. Relicensing costs and costs related to new licenses will be submitted to regulators for recovery through the ratemaking process. Relicensing costs of $134 million and $5 million for the HCC and Swan Falls projects, respectively, were included in construction work in progress at March 31, 2011. The IPUC currently authorizes Idaho Power to include in rates approximately $6.8 million annually ($10.6 million grossed up for income taxes) of AFUDC relating to the HCC relicensing project, and collecting these amounts will reduce the relicensing amount submitted to regulators for recovery through the ratemaking process.

LEGAL MATTERS

IDACORP and Idaho Power are involved in a number of litigation, regulatory, and tax-related proceedings, and are subject to claims and legal actions arising in the ordinary course of business, that could affect their future earnings and financial condition. Litigation over environmental issues and claims of various types, including property damage, personal injury, common law nuisance, and citizen enforcement of environmental requirements such as opacity and air and water quality standards, has increased generally throughout the United States. Notable pending legal proceedings to which IDACORP or Idaho Power are parties or are otherwise involved include the following:


•	Western Energy Proceedings - proceedings initiated by numerous purchasers of electricity in the California and western wholesale markets during 2000 and 2001, seeking refunds or other forms of relief, and related proceedings initiated by or involving the FERC;

•

Boardman Power Plant Proceedings - proceedings alleging that PGE, the operator of the Boardman coal-fired power plant (of which Idaho Power is a 10 percent owner), violated opacity permit limits and provisions of the Clean Water Act; and a September 2010 notice of violation issued by the EPA alleging that PGE had violated the New Source Performance Standards and operating permit requirements under the Clean Air Act as a result of modifications made

to the plant in 1998 and 2004;


•	Snake River Basin Adjudication - a general adjudication to determine the nature, extent, and priority of rights of all water users, including Idaho Power's, in the Snake River basin; and


•	U.S. Bureau of Reclamation Proceedings - an adjudication of spaceholder contract rights for storage and delivery of water to Idaho Power from American Falls Reservoir, a U.S. Bureau of Reclamation storage reservoir on the Snake River in Idaho, the critical issues in which were substantially resolved in April 2011.

See Note 9 - “Contingencies” to the condensed consolidated financial statements included in this report for a further discussion of these pending legal proceedings, including developments in these matters during the quarter ended March 31, 2011. IDACORP and Idaho Power are unable to predict the outcomes of these matters or estimate the impact they may have on their financial positions, results of operations, or cash flows.

ENVIRONMENTAL MATTERS

Idaho Power is subject to a broad range of federal, state, regional, and local laws and regulations designed to protect, restore, and enhance the environment. Current and pending legislation relates to, among other items, climate change, greenhouse gas emissions and air quality, renewable energy standards (RES), mercury and other emissions, hazardous wastes, and polychlorinated biphenyls. In addition to imposing continuing compliance obligations, these laws and regulations provide authority to levy substantial penalties for noncompliance including fines, injunctive relief, and other sanctions. These laws and regulations are administered by the EPA and various other state and local agencies. All such laws and regulations are subject to a range of interpretation, which may ultimately be resolved by the courts. Environmental laws and regulations may increase the cost of operating power generation plants and constructing new facilities, require that Idaho Power install additional pollution control devices at existing generating plants, or require that Idaho Power discontinue operating certain power generation plants. Environmental regulation continues to impact Idaho Power's operations due to the cost of installation and operation of equipment and facilities required for compliance with such regulations, and the modification of system operations to accommodate such regulations.

Further, the FERC licenses issued for Idaho Power's hydroelectric generating plants impose numerous environmental requirements, such as aeration of turbine water to meet dissolved gas and temperature standards in the tail waters downstream from the plants. Idaho Power monitors these issues and reports the results to the appropriate regulatory agencies. Also, Idaho Power co-owns three coal-fired power plants and owns two natural gas combustion turbine power plants that are subject to a broad range of environmental requirements, including air quality regulation. These regulations could affect IDACORP's and Idaho Power's results of operations and financial condition if such costs cannot be fully recovered in rates on a timely basis.

Idaho Power's environmental compliance costs will continue to be significant for the foreseeable future. Idaho Power anticipates that a number of impending EPA rulemakings and proceedings addressing, among other things, ozone and fine particulate matter pollution, emissions, and disposal of coal combustion residuals could result in substantially increased operating and compliance costs. The discussion below provides a summary of notable developments in environmental, climate change, sustainability, and related issues impacting Idaho Power during the quarter ended March 31, 2011 and since the discussion of these and other matters included in Part II, Item 7 - “MD&A - Environmental Issues” and “MD&A - Liquidity and Capital Resources - Capital Requirements - Environmental Regulation Costs” in IDACORP's and Idaho Power's Annual Report on Form 10-K for the year ended December 31, 2010. Also, refer to Note 9 - “Contingencies” to the condensed consolidated financial statements included in this report for additional information regarding certain environmental proceedings affecting Idaho Power's properties.

Recent Mercury Emission Proposed Regulations: In April 2010, the U.S. District Court for the District of Columbia approved, by consent decree, a timetable that would require the EPA to propose a standard to control mercury emissions from coal-fired power plants by May 2011 and to finalize it by November 2011. Mercury continuous emission monitoring systems have been installed on all of the coal-fired units at the Jim Bridger, Boardman, and Valmy plants. On March 16, 2011, the EPA proposed new regulations to control emissions of mercury and other hazardous air pollutants (HAPs) from coal- and oil-fired electric utility steam generating units (EGUs) under the federal Clean Air Act. In the same notice, the EPA further proposed to revise the new source performance standards (NSPS) for fossil fuel-fired EGUs. The proposed regulation would impose maximum achievable control technology and NSPS standards on all coal-fired EGUs and would replace the former Clean Air Mercury Rule. Specifically, the proposed regulation would set numeric emission limitations on coal-fired EGUs for total particulate matter (a surrogate for non-mercury HAPs), hydrogen chloride, and mercury. In addition, the proposed regulation would impose a work practice standard for organic HAPs, including dioxins and furans. For the revised NSPS, for EGUs commencing construction of a new source after publication of the proposed regulation, the EPA would establish amended emission limitations for particulate matter, sulfur dioxide, and nitrogen oxides. Idaho Power is reviewing the proposed

regulations and is in the process of determining how these regulations will impact the current coal-fired EGUs, including Bridger, Boardman, and Valmy.

Renewable Energy and PURPA Contracts - Wind: As of March 31, 2011, Idaho Power had contracts to purchase energy from 18 on-line wind projects with a combined nameplate rating of 395 MW. At that date, Idaho Power also had signed and commission-approved PURPA contracts to purchase energy from an additional 16 wind projects with a combined nameplate rating of 360 MW. These projects are expected to be online between mid-2011 and the end of 2012. In addition, at March 31, 2011, Idaho Power had pending for possible approval before the IPUC contracts with 13 wind projects with a combined nameplate capacity of 294 MW.

REC Sales: Idaho Power is selling its near-term RECs and returning to customers their share of those proceeds through the PCA. Idaho Power filed a REC Management Plan with the IPUC in December 2009 to address its treatment of future RECs. Under Idaho Power's REC Management Plan, Idaho Power would sell near-term RECs, while continuing to acquire and hold long-term contractual rights to own RECs for use in meeting future RES requirements. For the three months ended March 31, 2011, Idaho Power's REC sales totaled $1 million.

OTHER MATTERS

Critical Accounting Policies and Estimates

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

IDACORP’s and Idaho Power’s critical accounting policies are reviewed by the audit committee of the boards of directors. These policies have not changed materially from the discussion of those policies included under “Critical Accounting Policies and Estimates” in the Annual Report on Form 10-K for the year ended December 31, 2010.

Recently Issued Accounting Pronouncements

There have been no recently issued accounting pronouncements that have had or are expected to have a material impact on IDACORP's or Idaho Power's results of operations or financial condition.

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

IDACORP and Idaho Power are exposed to market risks, including changes in interest rates, changes in commodity prices, credit risk, and equity price risk. The following discussion summarizes these risks and the financial instruments, derivative instruments, and derivative commodity instruments sensitive to changes in interest rates, commodity prices, and equity prices that were held at March 31, 2011.

Interest Rate Risk

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

Variable Rate Debt: As of March 31, 2011, IDACORP had $58.6 million in net floating-rate debt. The fair market value of this debt was $58.6 million. Assuming no change in financial structure, if variable interest rates were to average one percentage-point higher than the average rate on March 31, 2011, interest rate expense would increase and pre-tax earnings would decrease by approximately $0.6 million. As of March 31, 2011, Idaho Power had no floating-rate debt.

Fixed Rate Debt: As of March 31, 2011, IDACORP and Idaho Power each had $1.5 billion in fixed rate debt, with a fair

market value equal to $1.5 billion. These instruments are fixed rate and, therefore, do not expose the companies to a loss in earnings due to changes in market interest rates. However, the fair value of these instruments would increase by approximately $147 million for both IDACORP and Idaho Power if interest rates were to decline by one percentage point from their March 31, 2011 levels.

Commodity Price Risk

Idaho Power's exposure to changes in commodity prices is related to its ongoing utility operations that produce electricity to meet the demand of its retail electric customers. To supplement its generation resources and balance its supply of power with the demand of its retail customers, Idaho Power participates in the wholesale marketplace. IDACORP’s and Idaho Power’s commodity price risk as of March 31, 2011 had not changed materially from that reported in Item 7A of IDACORP's and Idaho Power's Annual Report on Form 10-K for the year ended December 31, 2010. Information regarding Idaho Power’s use of derivative instruments to manage commodity price risk can be found in Note 12 – “Derivative Financial Instruments” to the condensed consolidated financial statements included in this report.

Credit Risk

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

The use of performance assurance collateral in the form of cash, letters of credit, or guarantees is common industry practice. Idaho Power maintains margin agreements relating to its wholesale commodity contracts that allow performance assurance collateral to be requested of and/or posted with certain counterparties. As of March 31, 2011, Idaho Power had posted approximately $2.7 million of assurance collateral. Should Idaho Power experience a reduction in its credit rating on Idaho Power's unsecured debt to below investment grade, Idaho Power could be subject to additional requests by its wholesale counterparties to post additional performance assurance collateral. Counterparties to derivative instruments and other forward contracts could request immediate payment or demand immediate ongoing full daily collateralization on derivative instruments and contracts in net liability positions. Based upon Idaho Power's current energy and fuel portfolio and market conditions as of March 31, 2011, the approximate amount of additional collateral that could be requested upon a downgrade to below investment grade is approximately $14 million. Idaho Power actively monitors the portfolio exposure and the potential exposure to additional requests for performance assurance collateral calls, through sensitivity analysis, to minimize capital requirements.

Idaho Power’s credit risk related to uncollectible accounts as of March 31, 2011 had not changed materially from that reported in Item 7A of IDACORP's and Idaho Power's Annual Report on Form 10-K for the year ended December 31, 2010.

Equity Price Risk

IDACORP and Idaho Power are exposed to price fluctuations in equity markets, primarily through their defined benefit pension plan assets, a mine reclamation trust fund owned by an equity-method investment of Idaho Power, and other equity investments at Idaho Power. IDACORP’s and Idaho Power’s equity price risk as of March 31, 2011 had not changed materially from that reported in Item 7A of IDACORP's and Idaho Power's Annual Report on Form 10-K for the year ended December 31, 2010.

ITEM 4. CONTROLS AND PROCEDURES

Disclosure Controls and Procedures

IDACORP: The Chief Executive Officer and the Chief Financial Officer of IDACORP, based on their evaluation of IDACORP’s disclosure controls and procedures (as defined in Exchange Act Rule 13a-15(e)) as of March 31, 2011, have concluded that IDACORP’s disclosure controls and procedures are effective as of that date.

Idaho Power: The Chief Executive Officer and the Chief Financial Officer of Idaho Power, based on their evaluation of Idaho Power’s disclosure controls and procedures (as defined in Exchange Act Rule 13a-15(e)) as of March 31, 2011, have concluded that Idaho Power’s disclosure controls and procedures are effective as of that date.

Changes in Internal Control Over Financial Reporting

There have been no changes in IDACORP’s or Idaho Power’s internal control over financial reporting during the quarter ended March 31, 2011, that have materially affected, or are reasonably likely to materially affect, IDACORP’s or Idaho Power’s internal control over financial reporting.

PART II – OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS

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

ITEM 1A. RISK FACTORS

The factors discussed in Part I - Item 1A - “Risk Factors” in IDACORP’s and Idaho Power’s Annual Report on Form 10-K for the year ended December 31, 2010, could materially affect IDACORP’s and Idaho Power’s business, financial condition, or future results. There have been no material changes from the risk factors set forth in that section.

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

Restrictions on Dividends

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

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

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

Issuer Purchases of Equity Securities

During the quarter ended March 31, 2011, IDACORP effected the following repurchases of its common stock:



Period		(a) Total Number of Shares Purchased ⁽¹⁾	(b) Average Price Paid per Share		(c) Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs	(d) Maximum Number (or Approximate Dollar Value) of Shares that May Yet Be Purchased Under the Plans or Programs
January 1 - January 31, 2011		12,360	$	37.38	—	—
February 1 - February 28, 2011		—	—		—	—
March 1 - March 31, 2011		38,684	37.71		—	—
	Total	51,044	$	37.63	—	—
⁽¹⁾These shares were withheld for taxes upon vesting of restricted stock.

ITEM 5. OTHER INFORMATION

Mine Safety and Health Matters

Idaho Power is the parent company of Idaho Energy Resources Co. (IERCo), a joint venturer in Bridger Coal Company (BCC), which mines coal at the Bridger Coal Mine and processing facility (Mine) near Rock Springs, Wyoming. The Mine,

comprised of the Bridger surface and underground mines, supplies the mined coal to the Jim Bridger generating plant owned in part by Idaho Power. Day-to-day operation and management of coal mining and processing operations at the Mine are conducted through IERCo's joint venture partner. IERCo owns a one-third interest in BCC. All personnel involved in the operation and maintenance of BCC are retained and employed by IERCo's joint venture partner. In addition to operating the Mine, the joint venture partner is responsible for the development and implementation of a safety program for the protection of Mine personnel. The mine safety program developed for BCC includes extensive training and compliance monitoring and has been developed with the objective of eliminating workplace incidents and complying with all mining-related regulations. While Idaho Power is not involved in the day-to-day operation of the Mine, the agreement governing the relationship between the joint venture partners provides that IERCo is entitled to designate two members of the four member management committee, which under the terms of the agreement is responsible for making decisions with regard to development of the coal resources, construction of improvements, mining operations, reclamation plans, and acquisition of equipment or property.

The operation of the Mine is regulated by the Mine Safety and Health Administration (MSHA) under the Federal Mine Safety and Health Act of 1977 (Mine Safety Act). MSHA inspects the Mine on a regular basis and may issue citations, notices, orders, or any combination thereof, when it believes a violation has occurred under the Mine Safety Act. Monetary penalties are assessed by MSHA for citations. Citations, notices, and orders can be contested and appealed. The severity and assessment of penalties may be reduced or, in some cases, dismissed through the appeal process.

The table below summarizes the total number of citations, notices, and orders issued and penalties assessed by MSHA for the Mine under the indicated provisions of the Mine Safety Act, and other information, for the three months ended March 31, 2011.



Bridger Coal Mine and Coal Processing Facility

		(surface)		(underground)
Mine Safety Act
	Section 104(a) Significant & Substantial Citations ⁽¹⁾		3		4
	Section 104(b) Orders ⁽²⁾		-		-
	Section 104(d) Citations & Orders ⁽³⁾		-		-
	Section 110(b)(2) Flagrant Violations ⁽⁴⁾		-		-
	Section 107(a) Imminent Danger Orders ⁽⁵⁾		-		-
	Section 104(e) Notice ⁽⁶⁾		-		-

Total Value of Proposed MSHA Assessments (in thousands)		$	6	$	25
Legal Actions ⁽⁷⁾			8		17
Number of Fatalities			-		-
_______________
⁽¹⁾ For alleged violations of a mandatory mining safety standard or regulation where such violation contributed to a discrete safety hazard and there exists a reasonable likelihood that the hazard will result in an injury or illness and there is a reasonable likelihood that such injury will be of a reasonably serious nature.
⁽²⁾ For alleged failure to totally abate the subject matter of a Mine Safety Act Section 104(a) citation within the period specified in the citation or as subsequently extended.
⁽³⁾ For an alleged unwarrantable failure (i.e., aggravated conduct constituting more than ordinary negligence) to comply with a mining safety standard or regulation.
⁽⁴⁾ The term “flagrant” with respect to a violation means a reckless or repeated failure to make reasonable efforts to eliminate a known violation of mandatory health or safety standard that substantially and proximately caused, or reasonably could have been expected to cause, death or serious bodily injury.
⁽⁵⁾ The existence of any condition or practice in a coal or other mine that could reasonably be expected to cause death or serious physical harm if normal mining operations were permitted to proceed in the area before such condition or practice is eliminated.
⁽⁶⁾For a pattern, or the potential to have a pattern, of violations of mandatory health or safety standards that are of such nature as could have significantly and substantially contributed to the cause and effect of coal or other mine health or safety hazards.
⁽⁷⁾Represents the total number of legal actions or proceedings pending before the Federal Mine Safety and Health Review Commission, which is not exclusive to citations, notices, orders, and penalties assessed by MSHA, as of March 31, 2011.

ITEM 6. EXHIBITS



Exhibit No.	Description

10.69 ¹	IDACORP, Inc. 2000 Long-Term Incentive and Compensation Plan - Form of Performance Share Award Agreement (performance with two goals) (February 25, 2011).
12.1	IDACORP, Inc. Computation of Ratio of Earnings to Fixed Charges and Supplemental Ratio of Earnings to Fixed Charges
12.2	Idaho Power Company Computation of Ratio of Earnings to Fixed Charges and Supplemental Ratio of Earnings to Fixed Charges
15.1	Letter Re: Unaudited Interim Financial Information
31.1	IDACORP, Inc. Rule 13a-14(a) CEO certification
31.2	IDACORP, Inc. Rule 13a-14(a) CFO certification
31.3	Idaho Power Rule 13a-14(a) CEO certification
31.4	Idaho Power Rule 13a-14(a) CFO certification
32.1	IDACORP, Inc. Section 1350 CEO certification
32.2	IDACORP, Inc. Section 1350 CFO certification
32.3	Idaho Power Section 1350 CEO certification
32.4	Idaho Power Section 1350 CFO certification
101.INS²	XBRL Instance Document
101.SCH²	XBRL Taxonomy Extension Schema Document
101.CAL²	XBRL Taxonomy Extension Calculation Linkbase Document
101.LAB²	XBRL Taxonomy Extension Label Linkbase Document
101.PRE²	XBRL Taxonomy Extension Presentation Linkbase Document
101.DEF²	XBRL Taxonomy Extension Definition Linkbase Document

1 Management contract or compensatory plan or arrangement
2 Includes data files for the following materials from the quarterly report on Form 10-Q of IDACORP, Inc. for the quarter ended March 31, 2011, formatted in Extensible Business Reporting Language (XBRL): (i) the Condensed Consolidated Statements of Income; (ii) the Condensed Consolidated Balance Sheets; (iii) the Condensed Consolidated Statements of Cash Flows; (iv) the Condensed Consolidated Statements of Comprehensive Income; (v) the Condensed Consolidated Statements of Equity; and (vi) the Notes to Condensed Consolidated Financial Statements tagged as blocks of text. Pursuant to Rule 406T of SEC Regulation S-T, these interactive data files are deemed not filed or part of a registration statement or prospectus for purposes of Sections 11 or 12 of the Securities Act of 1933, are deemed not filed for purposes of Section 18 of the Securities Exchange Act of 1934, and otherwise are not subject to liability under those sections. These files are being furnished only by IDACORP, Inc. and not by its subsidiary, Idaho Power Company.

SIGNATURES

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



		IDACORP, INC.
		(Registrant)



Date:	May 5, 2011	By:	/s/ J. LaMont Keen
			J. LaMont Keen
			President and Chief Executive Officer

Date:	May 5, 2011	By:	/s/ Darrel T. Anderson
			Darrel T. Anderson
			Executive Vice President - Administrative
			Services and Chief Financial Officer





		IDAHO POWER COMPANY
		(Registrant)



Date:	May 5, 2011	By:	/s/ J. LaMont Keen
			J. LaMont Keen
			President and Chief Executive Officer

Date:	May 5, 2011	By:	/s/ Darrel T. Anderson
			Darrel T. Anderson
			Executive Vice President - Administrative
			Services and Chief Financial Officer

EXHIBIT INDEX



Exhibit No.	Description

10.69 ¹	IDACORP, Inc. 2000 Long-Term Incentive and Compensation Plan - Form of Performance Share Award Agreement (performance with two goals) (February 25, 2011).
12.1	IDACORP, Inc. Computation of Ratio of Earnings to Fixed Charges and Supplemental Ratio of Earnings to Fixed Charges
12.2	Idaho Power Company Computation of Ratio of Earnings to Fixed Charges and Supplemental Ratio of Earnings to Fixed Charges
15.1	Letter Re: Unaudited Interim Financial Information
31.1	IDACORP, Inc. Rule 13a-14(a) CEO certification
31.2	IDACORP, Inc. Rule 13a-14(a) CFO certification
31.3	Idaho Power Rule 13a-14(a) CEO certification
31.4	Idaho Power Rule 13a-14(a) CFO certification
32.1	IDACORP, Inc. Section 1350 CEO certification
32.2	IDACORP, Inc. Section 1350 CFO certification
32.3	Idaho Power Section 1350 CEO certification
32.4	Idaho Power Section 1350 CFO certification
101.INS²	XBRL Instance Document
101.SCH²	XBRL Taxonomy Extension Schema Document
101.CAL²	XBRL Taxonomy Extension Calculation Linkbase Document
101.LAB²	XBRL Taxonomy Extension Label Linkbase Document
101.PRE²	XBRL Taxonomy Extension Presentation Linkbase Document
101.DEF²	XBRL Taxonomy Extension Definition Linkbase Document

1 Management contract or compensatory plan or arrangement
2 Includes data files for the following materials from the quarterly report on Form 10-Q of IDACORP, Inc. for the quarter ended March 31, 2011, formatted in Extensible Business Reporting Language (XBRL): (i) the Condensed Consolidated Statements of Income; (ii) the Condensed Consolidated Balance Sheets; (iii) the Condensed Consolidated Statements of Cash Flows; (iv) the Condensed Consolidated Statements of Comprehensive Income; (v) the Condensed Consolidated Statements of Equity; and (vi) the Notes to Condensed Consolidated Financial Statements tagged as blocks of text. Pursuant to Rule 406T of SEC Regulation S-T, these interactive data files are deemed not filed or part of a registration statement or prospectus for purposes of Sections 11 or 12 of the Securities Act of 1933, are deemed not filed for purposes of Section 18 of the Securities Exchange Act of 1934, and otherwise are not subject to liability under those sections. These files are being furnished only by IDACORP, Inc. and not by its subsidiary, Idaho Power Company.