10-Q

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, 2012
	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, Idaho  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 X   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 27, 2012:    

IDACORP, Inc.:        50,095,905

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 Instruction (H)(1)(a) and (b) of Form 10-Q and is therefore filing this report on Form 10-Q with the reduced disclosure format.

1

COMMONLY USED TERMS
The following select abbreviations, terms, or acronyms are commonly used or found in multiple locations in this report:
ADITC	-	Accumulated Deferred Investment Tax Credits
AFUDC	-	Allowance for Funds Used During Construction
BCC	-	Bridger Coal Company, a joint venture of IERCo
CAMP	-	Comprehensive Aquifer Management Plan
CO2	-	Carbon Dioxide
CSPP	-	Cogeneration and Small Power Production
EGUs	-	Electric Utility Steam Generating Units
EPA	-	U.S. Environmental Protection Agency
EPS	-	Earnings Per Share
ESPA	-	Eastern Snake Plain Aquifer
FCA	-	Fixed Cost Adjustment
FERC	-	Federal Energy Regulatory Commission
GHG	-	Greenhouse Gas
HAPs	-	Hazardous Air Pollutants
HCC	-	Hells Canyon Complex
IDACORP	-	IDACORP, Inc., an Idaho corporation
Idaho Power	-	Idaho Power Company, an Idaho corporation
Idaho ROE	-	Idaho-jurisdiction return on year-end equity
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	-	U.S. Internal Revenue Service
kW	-	Kilowatt
MD&A	-	Management’s Discussion and Analysis of Financial Condition and Results of Operations
MW	-	Megawatt
MWh	-	Megawatt-hour
NOx	-	Nitrous Oxide
NSPS	-	New Source Performance Standards
O&M	-	Operations and Maintenance
OATT	-	Open Access Transmission Tariff
OPUC	-	Oregon Public Utility Commission
PCA	-	Power Cost Adjustment
PURPA	-	Public Utility Regulatory Policies Act of 1978
REC	-	Renewable Energy Certificate
SEC	-	U.S. Securities and Exchange Commission
SO2	-	Sulfur Dioxide
USBR	-	U.S. Bureau of Reclamation
Valmy	-	North Valmy Steam Electric Generating Plant
VIEs	-	Variable Interest Entities

2

TABLE OF CONTENTS
				Page
Part I. Financial Information
	Item 1.  Financial Statements (unaudited)
		IDACORP, Inc.:
			Condensed Consolidated Statements of Income	4
			Condensed Consolidated Statements of Comprehensive Income	5
			Condensed Consolidated Balance Sheets	6
			Condensed Consolidated Statements of Cash Flows	8
			Condensed Consolidated Statements of Equity	9
		Idaho Power Company:
			Condensed Consolidated Statements of Income	10
			Condensed Consolidated Statements of Comprehensive Income	11
			Condensed Consolidated Balance Sheets	12
			Condensed Consolidated Statements of Capitalization	14
			Condensed Consolidated Statements of Cash Flows	15
		Notes to the Condensed Consolidated Financial Statements		16
		Reports of Independent Registered Public Accounting Firm		31
	Item 2.  Management’s Discussion and Analysis of Financial Condition and Results of
			Operations	33
	Item 3.  Quantitative and Qualitative Disclosures About Market Risk			57
	Item 4.  Controls and Procedures			59
Part II.  Other Information:
	Item 1.  Legal Proceedings			59
	Item 1A.  Risk Factors			59
	Item 2.  Unregistered Sales of Equity Securities and Use of Proceeds			60
	Item 4.  Mine Safety Disclosures			60
	Item 5. Other Information			60
	Item 6.  Exhibits			61
Signatures				62
Exhibit Index				63

SAFE HARBOR STATEMENT

This Quarterly 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” and in IDACORP, Inc.'s and Idaho Power Company's Annual Report on Form 10-K for the year ended December 31, 2011, 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," "intends," "plans," "predicts," "projects," "may result," "may continue," or similar expressions.

3

PART I – FINANCIAL INFORMATION

ITEM 1.  FINANCIAL STATEMENTS

IDACORP, Inc.

Condensed Consolidated Statements of Income

(unaudited)

	Three months ended March 31,
	2012			2011
	(thousands of dollars except for per share amounts)
Operating Revenues:
Electric utility:
General business	$	197,429		$	203,272
Off-system sales	27,708			29,845
Other revenues	15,346			17,945
Total electric utility revenues	240,483			251,062
Other	657			432
Total operating revenues	241,140			251,494
Operating Expenses:
Electric utility:
Purchased power	34,277			25,094
Fuel expense	32,751			29,902
Power cost adjustment	9,008			31,306
Other operations and maintenance	78,514			70,661
Energy efficiency programs	4,477			6,711
Depreciation	30,542			29,464
Taxes other than income taxes	8,100			7,211
Total electric utility expenses	197,669			200,349
Other	1,127			1,054
Total operating expenses	198,796			201,403
Operating Income	42,344			50,091
Other Income, Net	6,593			4,538
Earnings (Losses) of Unconsolidated Equity-Method Investments	1,419			(1,294		)
Interest Expense:
Interest on long-term debt	19,499			20,847
Other interest, net of AFUDC	(2,294		)	(1,888		)
Total interest expense, net	17,205			18,959
Income Before Income Taxes	33,151			34,376
Income Tax Expense	8,333			4,888
Net Income	24,818			29,488
Adjustment for loss attributable to noncontrolling interests	112			252
Net Income Attributable to IDACORP, Inc.	$	24,930		$	29,740
Weighted Average Common Shares Outstanding - Basic (000’s)	49,860			49,290
Weighted Average Common Shares Outstanding - Diluted (000’s)	49,905			49,356
Earnings Per Share of Common Stock:
Earnings Attributable to IDACORP, Inc. - Basic	$	0.50		$	0.60
Earnings Attributable to IDACORP, Inc. - Diluted	$	0.50		$	0.60
Dividends Declared Per Share of Common Stock	$	0.33		$	0.30

The accompanying notes are an integral part of these statements.

4

IDACORP, Inc.

Condensed Consolidated Statements of Comprehensive Income

(unaudited)

	Three months ended March 31,
	2012		2011
	(thousands of dollars)
Net Income	$	24,818	$	29,488
Other Comprehensive Income:
Net unrealized holding gains arising during the period,   net of tax of $874 and $355	1,362		553
Unfunded pension liability adjustment, net of tax   of $170 and $150	265		234
Total Comprehensive Income	26,445		30,275
Comprehensive loss attributable to noncontrolling interests	112		252
Comprehensive Income Attributable to IDACORP, Inc.	$	26,557	$	30,527

The accompanying notes are an integral part of these statements.

5

IDACORP, Inc.

Condensed Consolidated Balance Sheets

(unaudited)

	March 31, 2012			December 31, 2011
	(thousands of dollars)
Assets
Current Assets:
Cash and cash equivalents	$	8,857		$	27,813
Receivables:
Customer (net of allowance of $1,369 and $1,239, respectively)	68,246			66,296
Other (net of allowance of $187 and $196, respectively)	14,102			8,197
Income taxes receivable	786			421
Accrued unbilled revenues	37,078			46,441
Materials and supplies (at average cost)	48,428			46,490
Fuel stock (at average cost)	56,531			47,865
Prepayments	11,323			12,405
Deferred income taxes	37,359			16,159
Current regulatory assets	35,958			34,279
Other	4,617			4,606
Total current assets	323,285			310,972
Investments	195,978			199,931
Property, Plant and Equipment:
Utility plant in service	4,476,618			4,466,873
Accumulated provision for depreciation	(1,696,788		)	(1,677,609		)
Utility plant in service - net	2,779,830			2,789,264
Construction work in progress	614,851			591,475
Utility plant held for future use	7,107			6,974
Other property, net of accumulated depreciation	18,817			18,877
Property, plant and equipment - net	3,420,605			3,406,590
Other Assets:
American Falls and Milner water rights	18,691			20,015
Company-owned life insurance	23,678			24,060
Regulatory assets	963,055			953,068
Long-term receivables (net of allowance of $2,783 and $2,743, respectively)	5,621			5,621
Other	39,708			40,352
Total other assets	1,050,753			1,043,116
Total	$	4,990,621		$	4,960,609

The accompanying notes are an integral part of these statements.

6

IDACORP, Inc.

Condensed Consolidated Balance Sheets

(unaudited)

	March 31, 2012			December 31, 2011
	(thousands of dollars)
Liabilities and Equity
Current Liabilities:
Current maturities of long-term debt	$	1,064		$	101,064
Notes payable	63,000			54,200
Accounts payable	71,275			100,432
Income taxes accrued	2,837			505
Interest accrued	23,434			21,797
Current regulatory liabilities	49,487			29,738
Other	72,847			60,511
Total current liabilities	283,944			368,247
Other Liabilities:
Deferred income taxes	806,495			772,047
Regulatory liabilities	332,153			332,057
Pension and other postretirement benefits	335,456			363,209
Other	71,509			75,805
Total other liabilities	1,545,613			1,543,118
Long-Term Debt	1,486,568			1,387,550
Commitments and Contingencies
Equity:
IDACORP, Inc. shareholders’ equity:
Common stock, no par value (shares authorized 120,000,000;      50,092,260 and 49,964,172 shares issued, respectively)	831,296			828,389
Retained earnings	849,327			840,916
Accumulated other comprehensive loss	(9,995		)	(11,622		)
Treasury stock (3,362 and 12,177 shares at cost, respectively)	(60		)	(29		)
Total IDACORP, Inc. shareholders’ equity	1,670,568			1,657,654
Noncontrolling interests	3,928			4,040
Total equity	1,674,496			1,661,694
Total	$	4,990,621		$	4,960,609
The accompanying notes are an integral part of these statements.

7

IDACORP, Inc.

Condensed Consolidated Statements of Cash Flows

(unaudited)

	Three months ended March 31,
	2012			2011
	(thousands of dollars)
Operating Activities:
Net income	$	24,818		$	29,488
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization	31,875			31,592
Deferred income taxes and investment tax credits	5,008			1,266
Changes in regulatory assets and liabilities	15,586			35,850
Pension and postretirement benefit plan expense	7,673			4,553
Contributions to pension and postretirement benefit plans	(35,203		)	(593		)
(Earnings) Losses of unconsolidated equity-method investments	(1,419		)	1,294
Distributions from unconsolidated equity-method investments	9,050			—
Allowance for equity funds used during construction	(7,616		)	(5,329		)
Other non-cash adjustments to net income, net	827			724
Change in:
Accounts receivable and prepayments	365			(4,774		)
Accounts payable and other accrued liabilities	(23,215		)	(26,910		)
Taxes accrued/receivable	10,352			22,665
Other current assets	(1,242		)	54
Other current liabilities	4,812			8,440
Other assets	305			(109		)
Other liabilities	(4,326		)	(4,992		)
Net cash provided by operating activities	37,650			93,219
Investing Activities:
Additions to property, plant and equipment	(48,382		)	(101,880		)
Proceeds from the sale of emission allowances and RECs	785			2,055
Investments in affordable housing	(350		)	(905		)
Investments in unconsolidated affiliates	—			(300		)
Other	(1,034		)	1,026
Net cash used in investing activities	(48,981		)	(100,004		)
Financing Activities:
Retirement of long-term debt	(1,064		)	(121,064		)
Dividends on common stock	(16,800		)	(15,147		)
Net change in short-term borrowings	8,800			7,200
Issuance of common stock	2,487			2,215
Acquisition of treasury stock	(2,062		)	(1,904		)
Other	1,014			749
Net cash used in financing activities	(7,625		)	(127,951		)
Net decrease in cash and cash equivalents	(18,956		)	(134,736		)
Cash and cash equivalents at beginning of the period	27,813			228,677
Cash and cash equivalents at end of the period	$	8,857		$	93,941
Supplemental Disclosure of Cash Flow Information:
Cash paid (received) during the period for:
Income taxes	$	198		$	(12,700	)
Interest (net of amount capitalized)	$	14,943		$	18,430
Non-cash investing activities:
Additions to property, plant and equipment in accounts payable	$	21,241		$	24,641

The accompanying notes are an integral part of these statements.

8

IDACORP, Inc.

Condensed Consolidated Statements of Equity

(unaudited)

	Three months ended March 31,
	2012			2011
	(thousands of dollars)
Common Stock
Balance at beginning of period	$	828,389		$	807,842
Issued	2,487			2,215
Other	420			(83		)
Balance at end of period	831,296			809,974
Retained Earnings
Balance at beginning of period	840,916			733,879
Net income attributable to IDACORP, Inc.	24,930			29,740
Common stock dividends ($0.33 and $0.30 per share)	(16,519		)	(14,855		)
Balance at end of period	849,327			748,764
Accumulated Other Comprehensive (Loss) Income
Balance at beginning of period	(11,622		)	(9,568		)
Unrealized gain on securities (net of tax)	1,362			553
Unfunded pension liability adjustment (net of tax)	265			234
Balance at end of period	(9,995		)	(8,781		)
Treasury Stock
Balance at beginning of period	(29		)	(40		)
Issued	2,031			1,944
Acquired	(2,062		)	(1,904		)
Balance at end of period	(60		)	—
Total IDACORP, Inc. shareholders’ equity at end of period	1,670,568			1,549,957
Noncontrolling Interests
Balance at beginning of period	4,040			3,871
Net loss attributable to noncontrolling interests	(112		)	(252		)
Balance at end of period	3,928			3,619
Total equity at end of period	$	1,674,496		$	1,553,576

The accompanying notes are an integral part of these statements.

9

Idaho Power Company

Condensed Consolidated Statements of Income

(unaudited)

	Three months ended March 31,
	2012			2011
	(thousands of dollars)
Operating Revenues:
General business	$	197,429		$	203,272
Off-system sales	27,708			29,845
Other revenues	15,346			17,945
Total operating revenues	240,483			251,062
Operating Expenses:
Operation:
Purchased power	34,277			25,094
Fuel expense	32,751			29,902
Power cost adjustment	9,008			31,306
Other operations and maintenance	78,514			70,661
Energy efficiency programs	4,477			6,711
Depreciation	30,542			29,464
Taxes other than income taxes	8,100			7,211
Total operating expenses	197,669			200,349
Income from Operations	42,814			50,713
Other Income (Expense):
Allowance for equity funds used during construction	7,616			5,329
Earnings of unconsolidated equity-method investments	4,293			858
Other expense, net	(1,479		)	(1,013		)
Total other income	10,430			5,174
Interest Charges:
Interest on long-term debt	19,499			20,847
Other interest	1,560			1,213
Allowance for borrowed funds used during construction	(3,949		)	(3,214		)
Total interest charges	17,110			18,846
Income Before Income Taxes	36,134			37,041
Income Tax Expense	10,315			7,193
Net Income	$	25,819		$	29,848

The accompanying notes are an integral part of these statements.

10

Idaho Power Company

Condensed Consolidated Statements of Comprehensive Income

(unaudited)

	Three months ended March 31,
	2012		2011
	(thousands of dollars)
Net Income	$	25,819	$	29,848
Other Comprehensive Income:
Net unrealized holding gains arising during the period,   net of tax of $874 and $355	1,362		553
Unfunded pension liability adjustment, net of tax   of $170 and $150	265		234
Total Comprehensive Income	$	27,446	$	30,635

The accompanying notes are an integral part of these statements.

11

Idaho Power Company

Condensed Consolidated Balance Sheets

(unaudited)

	March 31, 2012			December 31, 2011
	(thousands of dollars)
Assets
Electric Plant:
In service (at original cost)	$	4,476,618		$	4,466,873
Accumulated provision for depreciation	(1,696,788		)	(1,677,609		)
In service - net	2,779,830			2,789,264
Construction work in progress	614,851			591,475
Held for future use	7,107			6,974
Electric plant - net	3,401,788			3,387,713
Investments and Other Property	127,295			128,674
Current Assets:
Cash and cash equivalents	2,991			19,316
Receivables:
Customer (net of allowance of $1,369 and $1,239, respectively)	68,246			66,296
Other (net of allowance of $187 and $196, respectively)	13,925			8,011
Income taxes receivable	17,555			4,644
Accrued unbilled revenues	37,078			46,441
Materials and supplies (at average cost)	48,428			46,490
Fuel stock (at average cost)	56,531			47,865
Prepayments	11,093			12,274
Deferred income taxes	16,486			14,099
Current regulatory assets	35,958			34,279
Other	4,617			4,606
Total current assets	312,908			304,321
Deferred Debits:
American Falls and Milner water rights	18,691			20,015
Company-owned life insurance	23,678			24,060
Regulatory assets	963,055			953,068
Other	38,385			38,988
Total deferred debits	1,043,809			1,036,131
Total	$	4,885,800		$	4,856,839

The accompanying notes are an integral part of these statements.

12

Idaho Power Company

Condensed Consolidated Balance Sheets

(unaudited)

	March 31, 2012			December 31, 2011
	(thousands of dollars)
Capitalization and Liabilities
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	712,258			704,758
Capital stock expense	(2,097		)	(2,097		)
Retained earnings	744,553			735,304
Accumulated other comprehensive loss	(9,995		)	(11,622		)
Total common stock equity	1,542,596			1,524,220
Long-term debt	1,486,568			1,387,550
Total capitalization	3,029,164			2,911,770
Current Liabilities:
Long-term debt due within one year	1,064			101,064
Notes payable	1,500			—
Accounts payable	70,796			99,716
Accounts payable to affiliates	2,479			1,512
Interest accrued	23,434			21,797
Current regulatory liabilities	49,487			29,738
Other	72,411			59,785
Total current liabilities	221,171			313,612
Deferred Credits:
Deferred income taxes	898,786			863,044
Regulatory liabilities	332,153			332,057
Pension and other postretirement benefits	335,456			363,209
Other	69,070			73,147
Total deferred credits	1,635,465			1,631,457
Commitments and Contingencies
Total	$	4,885,800		$	4,856,839
The accompanying notes are an integral part of these statements.

13

Idaho Power Company

Condensed Consolidated Statements of Capitalization

(unaudited)

	March 31, 2012			December 31, 2011
	(thousands of dollars)
Common Stock Equity:
Common stock	$	97,877		$	97,877
Premium on capital stock	712,258			704,758
Capital stock expense	(2,097		)	(2,097		)
Retained earnings	744,553			735,304
Accumulated other comprehensive loss	(9,995		)	(11,622		)
Total common stock equity	1,542,596			1,524,220
Long-Term Debt:
First mortgage bonds:
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			1,295,000
Amount due within one year	—			(100,000		)
Net first mortgage bonds	1,295,000			1,195,000
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	5,318			6,382
Note guarantee due within one year	(1,064		)	(1,064		)
Unamortized premium/discount - net	(3,031		)	(3,113		)
Total long-term debt	1,486,568			1,387,550
Total Capitalization	$	3,029,164		$	2,911,770

The accompanying notes are an integral part of these statements.

14

Idaho Power Company

Condensed Consolidated Statements of Cash Flows

(unaudited)

	Three months ended March 31,
	2012			2011
	(thousands of dollars)
Operating Activities:
Net income	$	25,819		$	29,848
Adjustments to reconcile net income to net cash provided by
operating activities:
Depreciation and amortization	31,723			31,435
Deferred income taxes and investment tax credits	25,114			2,259
Changes in regulatory assets and liabilities	15,586			35,850
Pension and postretirement benefit plan expense	7,673			4,553
Contributions to pension and postretirement benefit plans	(35,203		)	(593		)
Earnings of unconsolidated equity-method investments	(4,293		)	(858		)
Distributions from unconsolidated equity-method investments	9,050			—
Allowance for equity funds used during construction	(7,616		)	(5,329		)
Other non-cash adjustments to net income	559			303
Change in:
Accounts receivables and prepayments	317			(6,107		)
Accounts payable	(22,998		)	(26,700		)
Taxes accrued/receivable	(4,564		)	33,601
Other current assets	(1,241		)	54
Other current liabilities	4,813			8,443
Other assets	305			(109		)
Other liabilities	(4,105		)	(4,151		)
Net cash provided by operating activities	40,939			102,499
Investing Activities:
Additions to utility plant	(48,382		)	(101,880		)
Proceeds from the sale of emission allowances and RECs	785			2,055
Investments in unconsolidated affiliates	—			(300		)
Other	(1,033		)	405
Net cash used in investing activities	(48,630		)	(99,720		)
Financing Activities:
Retirement of long-term debt	(1,064		)	(121,064		)
Dividends on common stock	(16,570		)	(14,922		)
Net change in short term borrowings	1,500			—
Capital contribution from parent	7,500			—
Other	—			(8		)
Net cash used in financing activities	(8,634		)	(135,994		)
Net decrease in cash and cash equivalents	(16,325		)	(133,215		)
Cash and cash equivalents at beginning of the period	19,316			224,233
Cash and cash equivalents at end of the period	$	2,991		$	91,018
Supplemental Disclosure of Cash Flow Information:
Cash (received) paid during the period for:
Income taxes	$	(3,008	)	$	(22,323	)
Interest (net of amount capitalized)	$	14,848		$	18,310
Non-cash investing activities:
Additions to property, plant and equipment in accounts payable	$	21,241		$	24,641

The accompanying notes are an integral part of these statements.

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IDACORP, INC. AND IDAHO POWER COMPANY

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(unaudited)

1.  SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

This Quarterly Report on Form 10-Q is a combined report of IDACORP, Inc. (IDACORP) and Idaho Power Company (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's utility operations are regulated primarily 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.  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 $20 million of assets, primarily a hydroelectric plant, and approximately $15 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 was $97 million at March 31, 2012, and Idaho Power's maximum exposure to loss is the carrying value, plus any additional future contributions to BCC and a $63 million guarantee for mine reclamation costs, which is discussed further in Note 8.

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 $60 million at March 31, 2012.

Regulation of Utility Operations

IDACORP's and Idaho Power's financial statements reflect the effects of the different ratemaking principles followed by the jurisdictions regulating Idaho Power.  The application of accounting principles related to regulated operations sometimes results

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in Idaho Power recording expenses and revenues in a different period than when an unregulated enterprise would otherwise record expenses and revenues.  In these instances, the amounts are deferred as regulatory assets or regulatory liabilities on the balance sheet and recorded on the income statement when recovered or returned in rates.  Additionally, regulators can impose regulatory liabilities upon a regulated company for amounts previously collected from customers and for amounts that are expected to be refunded to customers.  The effects of applying these regulatory accounting principles to Idaho Power's operations are discussed in more detail in Note 3.

Financial Statements

In the opinion of management of IDACORP and Idaho Power, the accompanying unaudited condensed consolidated financial statements contain all adjustments necessary to present fairly each company's consolidated financial position as of March 31, 2012, consolidated results of operations and cash flows for the three months endedMarch 31, 2012 and 2011.  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, 2011.  The results of operations for the interim period 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 the 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.

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 interim 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

Set forth below is a summary of income tax expense for the three months endedMarch 31 (in thousands of dollars):

	IDACORP						Idaho Power
	2012			2011			2012			2011
Income tax at statutory rates (federal and state)	$	13,006		$	13,540		$	14,128		$	14,483
Additional ADITC amortization	(825		)	(3,855		)	(825		)	(3,855		)
Other	(3,848		)	(4,797		)	(2,988		)	(3,435		)
Income tax expense	$	8,333		$	4,888		$	10,315		$	7,193
Effective tax rate	25.1		%	14.1		%	28.5		%	19.4		%

The increase in first quarter 2012 income tax expense as compared to the same period in 2011 was primarily due to lower utilization of additional ADITC amortization (discussed below) at Idaho Power. Net regulatory flow-through tax adjustments at Idaho Power and tax credits at IFS for the three months endedMarch 31, 2012 were comparable to the same period in 2011.

Idaho Power's December 2011 settlement agreement with the Idaho Public Utilities Commission (IPUC) and other parties provides 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 2012 to 2014.  Under the settlement

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agreement, Idaho Power has up to $25 million of additional ADITC amortization available for use in 2012. Idaho Power recorded $0.8 million of additional ADITC amortization in the first quarter of 2012 based on itsestimate of 2012 Idaho jurisdictional return on year-end equity.

3.  REGULATORY MATTERS

Recent and Pending Idaho Regulatory Matters

Idaho General Rate Case Settlement

On June 1, 2011, Idaho Power filed a general rate case and proposed rate schedules with the IPUC, Case No. IPC-E-11-08. On September 23, 2011, Idaho Power, the IPUC Staff, and other interested parties publicly filed a settlement stipulation with the IPUC resolving most of the key contested issues in the Idaho general rate case. On December 30, 2011, the IPUC issued an order approving the settlement stipulation. The settlement stipulation provides for a 7.86 percent authorized rate of return on an Idaho-jurisdictional rate base of approximately $2.36 billion. The approved settlement stipulation resulted in a 4.07 percent, or $34.0 million, overall increase in Idaho Power's annual Idaho jurisdictional base rate revenues, effective January 1, 2012. While both are final, neither the order nor the settlement stipulation specified an authorized rate of return on equity.

Settlement Stipulation -- Investment Tax Credits and Idaho Sharing Mechanism

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 provided for (a) the use of additional ADITC to help achieve a minimum 9.5 percent return on year-end equity in the Idaho jurisdiction, and (b) an equal sharing between Idaho Power and its customers of any Idaho jurisdiction earnings exceeding a return on year-end equity of 10.5 percent in the Idaho jurisdiction.  The sharing and ADITC amortization provisions of the January 2010 settlement agreement terminated on December 31, 2011.

On November 2, 2011, Idaho Power filed an application with the IPUC requesting an extension of the two elements of the January 2010 settlement agreement described above. On December 27, 2011, the IPUC issued an order, separate from the then-pending Idaho general rate case proceeding, approving a settlement stipulation that provides as follows:

• if Idaho Power's actual rate of return on year-end equity in the Idaho jurisdiction (Idaho ROE) for 2012, 2013, or 2014 is less than 9.5 percent, then Idaho Power may amortize additional ADITC to help achieve a minimum 9.5 percent Idaho ROE in the applicable year. Idaho Power would be permitted to amortize additional ADITC in an aggregate amount up to $45 million over the three-year period, but could use no more than $25 million in 2012;

• if Idaho Power's actual Idaho ROE for 2012, 2013, or 2014 exceeds 10.0 percent, the amount of Idaho Power's Idaho jurisdictional earnings exceeding a 10.0 percent but less than a 10.5 percent Idaho ROE for the applicable year would be shared equally between Idaho Power and its Idaho customers; and

• if Idaho Power's actual Idaho ROE for 2012, 2013, or 2014 exceeds 10.5 percent, the amount of Idaho Power's Idaho jurisdictional earnings exceeding a 10.5 percent Idaho ROE for the applicable year would be allocated 25 percent to Idaho Power and 75 percent to benefit Idaho customers through an offset in the pension balancing account.

The settlement stipulation provides that the Idaho ROE thresholds (9.5 percent, 10.0 percent, and 10.5 percent) will be automatically adjusted prospectively in the event the IPUC approves a change to Idaho Power's authorized return on equity as part of a general rate case proceeding seeking a rate change effective prior to January 1, 2015. The automatic adjustments would be as follows: (a) the 9.5 percent Idaho ROE trigger in the settlement stipulation would be replaced by the percentage equal to 95 percent of the new authorized rate of return on equity; (b) the 10.0 percent Idaho ROE trigger in the settlement stipulation would be re-established at the new authorized rate of return on equity; and (c) the 10.5 percent Idaho ROE trigger in the settlement stipulation would be replaced by the percentage equal to 105 percent of the new authorized rate of return on equity.

Annual Power Cost Adjustment Mechanism Filing

Idaho Power has power cost adjustment (PCA) mechanisms in its Idaho and Oregon jurisdictions that address the volatility of power supply costs and provide for annual adjustments to the rates charged to retail customers. In the Idaho jurisdiction, the annual PCA adjustments are based on (a) a forecast component, based on a forecast of net power supply costs in the coming year as compared to net power supply costs in base rates, and (b) a true-up component, based on the difference between the previous year’s actual net power supply costs and the previous year’s forecast.  The latter component also includes a balancing mechanism so that, over time, the actual collection or refund of authorized true-up dollars matches the amounts authorized.  On April 13, 2012, Idaho Power made its annual Idaho PCA filing with the IPUC, requesting a $43.0 million increase to Idaho

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PCA rates, effective for the period from June 1, 2012 to May 31, 2013. The PCA rates in effect from June 1, 2011 to May 31, 2012 were based on a May 31, 2011 IPUC order approving Idaho Power's requested $40.4 million Idaho PCA rate decrease.

Fixed Cost Adjustment Filings

The fixed cost adjustment (FCA) began as a pilot program for Idaho Power’s Idaho residential and small general service customers, running from 2007 through 2009.  The FCA 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.  The FCA is adjusted each year to collect, or refund, the difference between the allowed fixed-cost recovery amount and the actual fixed costs recovered by Idaho Power during the year.

On April 29, 2010, the IPUC approved a two-year extension of the FCA pilot program, retroactively effective from January 1, 2010, through December 31, 2011. On October 19, 2011, Idaho Power filed an application with the IPUC requesting that the FCA pilot program become permanent for residential and small general service customer classes effective January 1, 2012. On March 30, 2012, the IPUC issued an order approving the FCA as a permanent program. The IPUC noted in its order, however, that the FCA does not isolate or identify changes in cost recovery associated solely with Idaho Power's energy efficiency programs, and instead responds to all changes in load reduction. While the IPUC rejected the IPUC Staff's proposal that FCA results be shared 50 percent with customers, the IPUC's order directed Idaho Power to file with the IPUC a proposal to adjust the FCA to address the exclusion of changes in load not related to energy efficiency programs. The order also maintained the existing 3 percent cap on the FCA adjustment.

On March 2, 2012, Idaho Power filed an application with the IPUC requesting an order authorizing Idaho Power to increase the annual FCA collection to $10.3 million, a $1.2 million increase in FCA rates, for the period from June 1, 2012 to May 31, 2013. As of the date of this report, a determination and order from the IPUC is pending.

Langley Gulch Power Plant Cost Recovery Filing - Idaho

On September 1, 2009, Idaho Power received pre-approval from the IPUC to include $396.6 million of construction costs in Idaho Power’s rate base when the Langley Gulch natural gas-fired power plant, currently under construction, achieves commercial operation. On March 2, 2012, Idaho Power filed an application with the IPUC requesting an increase in annual Idaho-jurisdiction base rates of $59.9 million, effective July 1, 2012, for recovery of Idaho Power's investment in the Langley Gulch power plant. Idaho Power's application stated that its estimated investment in the plant through June 2012 will be approximately $398 million. After the impact of depreciation, deferred income taxes, amounts currently included in rates, and an Idaho-jurisdictional cost allocation, Idaho Power's application requests a $336.7 million increase in Idaho jurisdiction rate base. Idaho Power's requested base rate increase is based on an overall rate of return of 7.86 percent, as authorized by a prior IPUC order. As of the date of this report, Idaho Power is unable to determine the outcome of the proceeding. The IPUC has, however, approved Idaho Power's request to process the application under modified procedure.

Energy Efficiency and Demand Response Programs

Idaho Power manages a wide range of opportunities for its customers to participate in energy efficiency and demand response programs.  On March 15, 2012, Idaho Power filed an application with the IPUC requesting an order designating Idaho Power's 2011 demand-side management expenditures of $42.6 million as prudently incurred. As of the date of this report, a determination and order from the IPUC is pending. Idaho Power's previous application filed in March 2011, which was approved by the IPUC in August 2011, designated Idaho Power's 2010 Idaho energy efficiency rider expenditures of approximately $42 million as prudently incurred expenses.

Cost Recovery for Cessation of Boardman Coal-Fired Operations

In December 2010, the Oregon Environmental Quality Commission approved a plan to cease coal-fired operations at the Boardman power plant not later than December 31, 2020. The plan for a 2020 shutdown of coal-fired operations at the Boardman plant results in increased revenue requirements for Idaho Power related to accelerated depreciation expense, additional plant investments, and decommissioning costs. As a result, in response to an application filed by Idaho Power, on February 15, 2012 the IPUC issued an order accepting Idaho Power's regulatory accounting and cost recovery plan associated with the early plant shut-down and approving the establishment of a balancing account whereby incremental costs and benefits associated with the early shut-down will be tracked for recovery in a subsequent proceeding. On February 15, 2012, Idaho Power filed an application with the IPUC requesting a $1.6 million annual increase in Idaho-jurisdiction base rates to recover the incremental Idaho jurisdictional annual revenue deficiency associated with early shut-down. As of the date of this report, a

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determination and order from the IPUC is pending. As of March 31, 2012, Idaho Power's net book value in the Boardman plant was approximately $22.5 million.

Idaho Depreciation Rate Filings

The advanced metering infrastructure (AMI) project provides the means to automatically retrieve energy consumption information, eliminating manual meter reading expense. On February 12, 2009, the IPUC approved Idaho Power’s application requesting a Certificate of Public Convenience and Necessity for the deployment of AMI technology and approval of accelerated depreciation of existing non-AMI metering equipment.  Commencing June 1, 2009, the IPUC approved a rate increase, allowing Idaho Power to recover the three-year accelerated depreciation of the existing non-AMI metering equipment and to begin earning a return on its AMI investment.  On April 27, 2012, the IPUC approved Idaho Power's February 15, 2012 application requesting approval of a $10.6 million decrease in rates for specified customer classes, effective June 1, 2012, as a result of the removal of accelerated depreciation expense associated with non-AMI metering equipment.

In connection with a depreciation study authorized by Idaho Power and conducted by a third party, on February 15, 2012, Idaho Power filed an application with the IPUC seeking to institute revised depreciation rates for electric plant-in-service, based upon updated service life estimates and net salvage percentages for all plant assets, and adjust Idaho-jurisdictional base rates to reflect the revised depreciation rates. Idaho Power's application requested a $2.7 million increase in Idaho-jurisdictional base rates, with new rates effective June 1, 2012. As of the date of this report, a determination and order from the IPUC is pending.

Recent and Pending Oregon Regulatory Matters

Oregon General Rate Case Filing

On July 29, 2011, Idaho Power filed a general rate case and proposed rate schedules with the OPUC, Case No. UE 233. The filing requested a $5.8 million increase in annual Oregon jurisdictional revenues and an authorized rate of return on equity of 10.5 percent, with an Oregon retail rate base of approximately $121.9 million. Idaho Power, the OPUC Staff, and other interested parties executed and filed a partial settlement stipulation with the OPUC on February 1, 2012, resolving all matters in the general rate case other than the prudence of costs associated with pollution control investments at the Jim Bridger coal-fired power plant. The settlement stipulation provided for a $1.8 million base rate increase, a return on equity of 9.9 percent, and an overall rate of return of 7.757 percent in the Oregon jurisdiction. On February 23, 2012, the OPUC issued an order adopting the settlement stipulation. New rates in conformity with the settlement stipulation went into effect on March 1, 2012. The OPUC will conduct a second phase of the proceedings to address the prudence of Idaho Power's pollution control investments at the Jim Bridger plant.

Langley Gulch Power Plant Cost Recovery Filing - Oregon

On March 9, 2012, Idaho Power filed an application with the OPUC requesting an annual increase in Oregon-jurisdictional revenues of $3.0 million, for inclusion of the Langley Gulch power plant in Idaho Power's rate base. As of the date of this report, Idaho Power is unable to determine the outcome of the proceeding. A scheduling order issued by the OPUC provides for an OPUC decision by January 2013 and inclusion in rates by March 31, 2013.

4.  LONG-TERM DEBT

As of March 31, 2012, IDACORP had approximately $539 million remaining on a shelf registration statement filed with the U.S. Securities and Exchange Commission (SEC) that can be used for the issuance of debt securities or IDACORP 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.  At March 31, 2012, $300 million remained on Idaho Power’s shelf registration for the issuance of first mortgage bonds and debt securities. On April 13, 2012, Idaho Power issued $75 million of 2.95% first mortgage bonds, medium-term notes, Series I, maturing on April 1, 2022, and $75 million of 4.30% first mortgage bonds, medium-term notes, Series I, maturing on April 1, 2042. The first mortgage bonds were issued under Idaho Power's shelf registration statement. As a result of this issuance, as of the date of this report $150 million remained on Idaho Power’s shelf registration for the issuance of first mortgage bonds and debt securities.

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In April 2012, Idaho Power issued an irrevocable notice of redemption to redeem, prior to maturity, its $100 million in principal amount of 4.75% first mortgage bonds, medium-term notes due November 2012. Idaho Power intends to use a portion of the net proceeds of the April 2012 sale of first mortgage bonds, medium-term notes to effect the redemption. As a result, the $100 million of 4.75% first mortgage bonds, medium-term notes due November 2012 are reported as long-term debt in the condensed consolidated balance sheets, instead of as current maturities of long-term debt.

5.  NOTES PAYABLE

Credit Facilities

IDACORP and Idaho Power have $125 million and $300 million credit facilities, respectively, which may be used for general corporate purposes and commercial paper backup. IDACORP's credit facility consists of a revolving line of credit not to exceed the aggregate principal amount at any one time outstanding of $125 million, including swingline loans in an aggregate principal amount at any time outstanding not to exceed $15 million, and letters of credit in an aggregate principal amount at any time outstanding not to exceed $50 million. Idaho Power's credit facility consists of a revolving line of credit, through the issuance of loans and standby letters of credit, not to exceed the aggregate principal amount at any one time outstanding of $300 million, including swingline loans in an aggregate principal amount at any time outstanding not to exceed $30 million. IDACORP and Idaho Power have the right to request an increase in the aggregate principal amount of the facilities to $150 million and $450 million, respectively, in each case subject to certain conditions. The credit facilities mature on October 26, 2016, although IDACORP and Idaho Power have the right to request up to two one-year extensions of the credit agreement, in each case subject to certain conditions.

The IDACORP and Idaho Power credit agreements have similar terms and conditions. The interest rates for any borrowings under the facilities are based on either (1) a floating rate that is equal to the highest of the prime rate, federal funds rate plus 0.5 percent, or LIBOR rate plus 1.0 percent, or (2) the LIBOR rate, plus, in each case, an applicable margin. The margin is based on IDACORP's or Idaho Power's, as applicable, senior unsecured long-term indebtedness credit rating by Moody's Investors Service, Inc., Standard and Poor's Ratings Services, and Fitch Rating Services, Inc., as set forth on a schedule to the credit agreements. Under their respective facilities, the companies pay a facility fee on the commitment based on the respective company's credit rating for senior unsecured long-term debt securities.

At March 31, 2012, no loans were outstanding under either IDACORP's or Idaho Power's facilities then in effect.  At March 31, 2012, Idaho Power had regulatory authority to incur up to $450 million principal amount of short-term indebtedness at any one time outstanding. Balances and interest rates of IDACORP’s and Idaho Power's short-term borrowings were as follows at March 31, 2012 and December 31, 2011 (in thousands of dollars):

	March 31, 2012									December 31, 2011
	Idaho Power			IDACORP			Total			Idaho Power			IDACORP			Total
Commercial paper outstanding	$	1,500		$	61,500		$	63,000		$	—		$	54,200		$	54,200
Weighted-average annual interest rate	0.41		%	0.46		%	0.46		%	—		%	0.47		%	0.47		%

6.  COMMON STOCK

IDACORP Common Stock

During the three months endedMarch 31, 2012, IDACORP issued an aggregate of 128,088 shares of common stock pursuant to its IDACORP, Inc. Dividend Reinvestment and Stock Purchase Plan, Idaho Power Company Employee Savings Plan, IDACORP, Inc. Restricted Stock Plan, and IDACORP, Inc. 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 pursuant to a continuous equity program.  IDACORP's current sales agency agreement is with BNY Mellon Capital Markets, LLC. As of March 31, 2012, there were approximately 3 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 endedMarch 31, 2012.

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Restrictions on Dividends

A covenant in each of 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 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, 2012, the leverage ratios for IDACORP and Idaho Power were 48 percent and 49 percent, respectively.  Based on these restrictions, IDACORP’s and Idaho Power’s dividends were limited to $836 million and $741 million, respectively, at March 31, 2012.  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, 2012, IDACORP and Idaho Power were in compliance with all facility covenants.

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. 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.

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.

In addition to contractual restrictions on the amount and payment of dividends, the Federal Power Act prohibits the payment of dividends from "capital accounts." The term "capital accounts" is undefined in the Federal Power Act, but if conservatively interpreted could limit the payment of dividends by Idaho Power to the amount of Idaho Power's retained earnings.

7.  EARNINGS PER SHARE

The table below presents the computation of IDACORP’s basic and diluted earnings per share (EPS) for the three months endedMarch 31, 2012 and 2011 (in thousands, except for per share amounts).

	Three months ended March 31,
	2012		2011
Numerator:
Net income attributable to IDACORP, Inc.	$	24,930	$	29,740
Denominator:
Weighted-average common shares outstanding - basic	49,860		49,290
Effect of dilutive securities:
Options	5		14
Restricted Stock	40		52
Weighted-average common shares outstanding - diluted	49,905		49,356
Basic earnings per share	$	0.50	$	0.60
Diluted earnings per share	$	0.50	$	0.60

The diluted EPS computation for the three months endedMarch 31, 2011 excludes 265,089 options because the options’ exercise prices were greater than the average market price of the common stock during that period.  In total, 20,806 options were outstanding at March 31, 2012, with expiration dates between 2013 and 2015.

8.  COMMITMENTS

Purchase Obligations

Only one material change to long-term purchase commitments occurred during the three months endedMarch 31, 2012. In March 2012, the power purchase agreement with a solar energy project was terminated, which reduced Idaho Power's contractual payment obligations by approximately $90 million over the 25-year life of the contract.

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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, 2012, representing IERCo's one-third share of BCC's total reclamation obligation.  BCC has a reclamation trust fund set aside specifically for the purpose of paying these reclamation costs.  At March 31, 2012, the value of the reclamation trust fund totaled $88 million. BCC periodically 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 indemnification provisions 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, 2012, 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 9.  Some of these claims, controversies, disputes, and other contingent matters involve litigation and regulatory or other contested proceedings.  IDACORP and Idaho Power intend to vigorously protect and defend their interests and pursue their rights.  However, the ultimate resolution and outcome of litigation and regulatory proceedings is inherently difficult to determine, particularly where (a) the remedies or penalties sought are indeterminate, (b) the proceedings are in the early stages or the substantive issues have not been well developed, or (c) the matters involve complex or novel legal theories or a large number of parties. In accordance with applicable accounting guidance, IDACORP and Idaho Power, as applicable, establish an accrual for legal proceedings when those matters proceed to a stage where they present loss contingencies that are both probable and reasonably estimable. In such cases, there may be a possible exposure to loss in excess of any amounts accrued. IDACORP and Idaho Power monitor those matters for developments that could affect the likelihood of a loss and the accrued amount, if any, thereof, and adjust the amount as appropriate. If the loss contingency at issue is not both probable and reasonably estimable, IDACORP and Idaho Power do not establish an accrual and the matter will continue to be monitored for any developments that would make the loss contingency both probable and reasonably estimable. As of the date of this report, IDACORP's and Idaho Power's accruals for legal proceedings are not material to their financial statements as a whole; however, future accruals could be material in a given period. IDACORP's and Idaho Power's determination is based on currently available information, and estimates presented in financial statements and other financial disclosures involve significant judgment and may be subject to significant uncertainty. As available information changes, the matters for which IDACORP and Idaho Power are able to estimate the loss may change, and the estimates themselves may change.

For certain of those matters described in this report for which IDACORP or Idaho Power have determined a loss contingency may, in the future, be at least reasonably possible, IDACORP and Idaho Power have stated that they are unable to estimate the possible loss or a range of possible loss that may result from those matters. Depending on a range of factors, such as the complexity of the facts, the unique nature of the legal theories, the pace of discovery, the timing of decisions of the court or arbiter, and the adverse party's willingness to negotiate towards a resolution, it may be months or years after the filing of a case or commencement of a proceeding before IDACORP or Idaho Power may be in a position to estimate the possible loss or range of possible loss for those matters.

Given the substantial or indeterminate amounts sought in certain of the matters described below, and the inherent unpredictability of such matters, an adverse outcome in certain of these matters could have a material adverse effect on IDACORP's and Idaho Power's financial condition, results of operations, or cash flows in particular quarterly or annual periods. 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.

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Pacific Northwest Refund Proceedings

On July 25, 2001, the FERC issued an order establishing a 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.  During that period, Idaho Power or IE both sold and purchased electricity in the Pacific Northwest. 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 California Department of Water Resources (CDWR) in the scope of the proceeding.  The Ninth Circuit officially returned the case to the FERC on April 16, 2009.  On October 3, 2011, the FERC issued its order on remand. The FERC ordered that the record be re-opened to permit parties seeking refunds to submit seller-specific evidence in support of their claims for sales made during the period confined to December 25, 2000 through June 20, 2001. The seller-specific claims must show that a seller engaged in unlawful market activity with a causal connection to have directly affected the negotiation of the specific contract or contracts to which the seller was a party. IE and Idaho Power understand the order to provide that neither claims of general dysfunction in the California markets nor in the Pacific Northwest market will be sufficient to support claims. While directing a trial-type hearing, the FERC also directed that the hearings be held in abeyance so that the matter may be presented to a settlement judge. On November 2, 2011, each of the City of Seattle, Washington, the City of Tacoma, Washington, the Port of Seattle, and the California Parties (consisting of the California Attorney General and the California Public Utilities Commission) filed requests for rehearing, seeking to expand the scope of the October 3, 2011 order. The designated settlement judge has met with the parties and convened a settlement conference to establish settlement procedures. The FERC's Chief Administrative Law Judge memorialized certain settlement procedures to which the parties agreed in an order issued on November 23, 2011.

IE and Idaho Power intend to continue to defend their positions in the Pacific Northwest refund proceedings vigorously. Idaho Power does not believe that claims conforming to the requirements of the FERC's October 3, 2011 order have been submitted, and the FERC's order remains subject to rehearing and reconsideration. Idaho Power and IE are unable to predict when and how the FERC will act on the rehearing requests, which contracts would be subject to refunds, whether the FERC will order refunds, or how the refunds would be calculated. As a result of these factors, as of the date of this report Idaho Power and IE are unable to estimate the reasonably possible loss or range of losses that Idaho Power or IE could incur as a result of this matter. However, in the first quarter of 2012 Idaho Power reached a tentative settlement, subject to review and approval by the FERC, with one party to the proceedings. While Idaho Power is unable to quantify or determine the outcome of claims made by parties that have not yet settled, the settlement amount agreed upon by Idaho Power and the settling party was immaterial to IDACORP's and Idaho Power's financial statements.

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 in March 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

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file water rights 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 rights 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 continues to work with the Idaho Water Resource Board, other stakeholders, and the Idaho Legislature in exploring opportunities for implementation 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 anticipate any material modification of its water rights as a result of the SRBA process.

Other Legal Proceedings

IDACORP and Idaho Power are parties to legal claims, actions, and proceedings in addition to those discussed above.  However, as of the date of this report the companies 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 defined benefit 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.

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The table below 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
	2012			2011			2012		2011		2012			2011
Service cost	$	6,441		$	5,165		$	538	$	488	$	351		$	372
Interest cost	7,892			7,551			805		773		818			893
Expected return on plan assets	(7,712		)	(7,951		)	—		—		(604		)	(667		)
Amortization of transition obligation	—			—			—		—		510			510
Amortization of prior service cost	87			130			53		61		(105		)	(99		)
Amortization of net loss	3,463			2,094			382		323		143			171
Net periodic benefit cost	10,171			6,989			1,778		1,645		1,113			1,180
Costs not recognized due to the effects of regulation (1)	(5,389		)	(5,260		)	—		—		—			—
Net periodic benefit cost recognized for financial reporting (1)	$	4,782		$	1,729		$	1,778	$	1,645	$	1,113		$	1,180

⁽¹⁾  Net periodic benefit costs for the pension plan are recognized based upon the authorization of each regulatory jurisdiction Idaho Power operates within. Under IPUC order, income statement recognition of pension plan costs has been deferred until costs are recovered through rates. 

During the three months endedMarch 31, 2012, Idaho Power contributed $34 million to its pension plan, which is consistent with its total estimated pension contribution requirements for 2012.

11.  INVESTMENTS IN 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.

The table below summarizes investments in equity securities by IDACORP and Idaho Power as of March 31, 2012 and December 31, 2011 (in thousands of dollars).

	March 31, 2012						December 31, 2011
	Gross Unrealized Gain		Gross Unrealized Loss		Fair Value		Gross Unrealized Gain		Gross Unrealized Loss		Fair Value
Available-for-sale securities	$	6,455	$	—	$	26,687	$	4,220	$	1	$	22,205

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, 2012, no securities were in an unrealized loss position. At December 31, 2011, one security was in an immaterial unrealized loss position. No other-than-temporary impairment was recognized for this security due to the limited severity and duration of the unrealized loss position.

There were no sales of available-for-sale securities during the three months endedMarch 31, 2012 or 2011.

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.

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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 qualify for the normal purchases and normal sales exception.

All of Idaho Power's derivative instruments have been entered into for the purpose of economically hedging forecasted purchases and sales, though none of these instruments have been designated as cash flow hedges under derivative accounting guidance. Idaho Power offsets fair value amounts recognized on its balance sheet related to derivative instruments executed with the same counterparty under the same master netting agreement.

Derivative Instrument Summary

The table below presents the fair values and locations of derivative instruments not designated as hedging instruments recorded on the balance sheets at March 31, 2012 and December 31, 2011 (in thousands of dollars).

	Asset Derivatives			Liability Derivatives
	Balance Sheet	Fair		Balance Sheet	Fair
	Location	Value		Location	Value
March 31, 2012
Current:
Financial swaps	Other current assets	$	6,374	Other current assets	$	1,444
Financial swaps	Other current liabilities	5,379		Other current liabilities	9,740
Forward contracts	Other current assets	31		Other current liabilities	2,256
Forward contracts	Other current liabilities	116
Long-term:
Financial swaps	Other assets	13		Other liabilities	385
Financial swaps	Other liabilities	76
Forward contracts	Other assets	248
Total		$	12,237		$	13,825
December 31, 2011
Current:
Financial swaps	Other current assets	$	4,361	Other current assets	$	1,036
Financial swaps	Other current liabilities	1,526		Other current liabilities	4,755
Forward contracts	Other current assets	70		Other current liabilities	1,370
Long-term:
Financial swaps	Other assets	359		Other liabilities	108
Total		$	6,316		$	7,269

The table below presents the gains and losses on derivatives not designated as hedging instruments for the three months endedMarch 31, 2012 and 2011 (in thousands of dollars).

		Gain/(Loss) on Derivatives Recognized
		in Income(1)
	Location of Gain/(Loss) on	March 31,
	Derivatives Recognized in Income	2012			2011
Financial swaps	Off-system sales	$	4,439		$	6,721
Financial swaps	Purchased power	(993		)	(167		)
Financial swaps	Fuel expense	(84		)	—
Financial swaps	Other operations and maintenance	(45		)	—

⁽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

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derivatives are recorded in other operations and maintenance expense.  See Note 13 for additional information concerning the determination of fair value for Idaho Power’s assets and liabilities from price risk management activities.

Idaho Power had volumes of derivative commodity forward contracts and swaps outstanding at March 31, 2012 and 2011 set forth in the table below.

		March 31,
Commodity	Units	2012	2011
Electricity purchases	MWh	256,200	486,000
Electricity sales	MWh	1,417,270	501,250
Natural gas purchases	MMBtu	10,082,392	1,867,316
Natural gas sales	MMBtu	913,379	—
Diesel purchases	Gallons	807,978	804,146

Credit Risk

At March 31, 2012, 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, 2012, was $14.0 million.  Idaho Power posted no collateral related to this amount.  If the credit-risk-related contingent features underlying these agreements were triggered on March 31, 2012, Idaho Power would have been required to post $7.3 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.

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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.

An item recorded at fair value is reclassified between levels when changes in the nature of valuation inputs cause the item to no longer meet the criteria for the level in which it was previously categorized. There have been no material reclassifications between levels during the current period.

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 location basis, 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. Notes receivable are related to Ida-West and are valued based on unobservable inputs, including discounted cash flows, which are partially based on forecasted hydroelectric conditions. Long-term debt is not traded on an exchange and is valued using quoted rates for similar debt in active markets. There were no material changes in valuation techniques or inputs during the quarter ended March 31, 2012 or the year ended December 31, 2011.

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, 2012 and December 31, 2011 (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 material 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, 2012
Assets:
Derivatives	$	3,202	$	381	$	—	$	3,583
Money market funds	100		—		—		100
Trading securities:  Equity securities	2,370		—		—		2,370
Available-for-sale securities:  Equity securities	26,687		—		—		26,687
Liabilities:
Derivatives	$	275	$	6,534	$	—	$	6,809
December 31, 2011
Assets:
Derivatives	$	3,654	$	100	$	—	$	3,754
Money market funds	100		—		—		100
Trading securities:  Equity securities	3,439		—		—		3,439
Available-for-sale securities:  Equity securities	22,205		—		—		22,205
Liabilities:
Derivatives	$	405	$	4,302	$	—	$	4,707

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, 2012 and December 31, 2011, 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

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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 analysis as appropriate. 

	March 31, 2012				December 31, 2011
	Carrying		Estimated		Carrying		Estimated
	Amount		Fair Value		Amount		Fair Value
	(thousands of dollars)
IDACORP
Assets:
Notes receivable (1)	$	3,097	$	3,097	$	3,097	$	3,097
Liabilities:
Long-term debt (1)	1,490,663		1,678,075		1,491,727		1,737,912
Idaho Power
Liabilities:
Long-term debt (1)	$	1,490,663	$	1,678,075	$	1,491,727	$	1,737,912

⁽¹⁾ Notes receivable and long-term debt are categorized as Level 3 and Level 2, respectively, of the fair value hierarchy, as defined earlier in this financial statement footnote.

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 in the table below.  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 table below 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, 2012:
Revenues	$	240,483	$	657		$	—		$	241,140
Net income (loss) attributable to IDACORP, Inc.	25,819		(889		)	—			24,930
Total assets as of March 31, 2012	4,885,800		120,997			(16,176		)	4,990,621
Three months ended March 31, 2011:
Revenues	$	251,062	$	432		$	—		$	251,494
Net income (loss) attributable to IDACORP, Inc.	29,848		(108		)	—			29,740

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Shareholders of

IDACORP, Inc.

Boise, Idaho

We have reviewed the accompanying condensed consolidated balance sheet of IDACORP, Inc. and subsidiaries (the “Company”) as of March 31, 2012, and the related condensed consolidated statements of income, comprehensive income, equity, and cash flows for the three-month periods ended March 31, 2012 and 2011.  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, 2011, 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 22, 2012, 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, 2011 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 3, 2012

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Shareholder of

Idaho Power Company

Boise, Idaho

We have reviewed the accompanying condensed consolidated balance sheet and statement of capitalization of Idaho Power Company and subsidiary (the “Company”) as of March 31, 2012, and the related condensed consolidated statements of income, comprehensive income, and cash flows for the three-month periods ended March 31, 2012 and 2011.  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 and statement of capitalization of Idaho Power Company and subsidiary as of December 31, 2011, 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 22, 2012, 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, 2011 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 3, 2012

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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, such as statements regarding projected or future financial performance, cash flows, capital expenditures, dividends, capital structure or ratios, strategic goals, challenges, and objectives, and plans for future operations. Such statements 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 set forth in this report; IDACORP's and Idaho Power's Annual Report on Form 10-K for the year ended December 31, 2011, particularly Item 1A - “Risk Factors” and Part II, Item 7 - “Management’s Discussion and Analysis of Financial Condition and Results of Operations”; 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;

• variable hydrological conditions and over-appropriation of surface and groundwater in the Snake River basin, which can impact stream flows and the amount of generation from Idaho Power's hydroelectric facilities;

• the cost and availability of materials, fuel, and commodities, and their impact on Idaho Power's infrastructure costs, power costs, and 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, hydroelectric plant licenses under reasonable terms (and the costs resulting from conditions in such licenses), rights-of-way, and siting, and risks related to contracting, construction, and start-up;

• disruptions or outages of Idaho Power's generation or transmission systems or the western interconnected transmission system affecting Idaho Power's ability to deliver power to its customers and requiring the dispatch of more expensive generation resources or purchasing power, which may ultimately increase costs;

• increased costs associated with the legislatively mandated purchase of intermittent power, such as wind, at above-market rates, and the costs and other challenges of integrating intermittent power sources into Idaho Power's resource 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;

• the continuing effects of the weak economy in Idaho Power's service territory and elsewhere, including decreased demand for electricity, reducing 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 and costs of compliance with laws, regulations, and policies relating to the environment, natural resources, and endangered species and the adoption and interpretation of laws and regulations addressing greenhouse gas emissions, global climate change, and energy policies 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;

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• 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 swaps and derivatives;

• wholesale market conditions, including the volatility of prices and availability of power on the spot market and the ability to enter into commodity financial hedges with creditworthy counterparties, and the cost of those hedges, which may affect the prices Idaho Power must pay for power as well as the prices at which Idaho Power can sell any excess power;

• deteriorating values in the equity markets, changes in interest rates and credit spreads, reductions in demand for investment-grade commercial paper, 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 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, increase 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;

• the ability to obtain debt and equity 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, the companies' financial performance, and other economic conditions;

• whether the companies will be able to continue to pay dividends under the terms of their respective financing and credit agreements and regulatory limitations, and whether the companies' boards of directors will continue to declare common stock dividends based on the boards of directors’ periodic consideration of factors ordinarily affecting dividend policy, such as current and prospective financial condition, earnings and liquidity, prospective business conditions, regulatory factors, and restrictions in applicable agreements;

• the potential effects of negative publicity regarding business practices, whether true or not, which could result in, among other things, costly litigation and a decline in IDACORP's common stock price;

• 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;

• employee workforce factors, including the ability to attract and retain skilled workers, unionization or the attempt to unionize all or part of the companies' workforce, the ability to adjust the labor cost structure to changes in growth within Idaho Power's service territory, and increasing health care and other benefit costs;

• the failure of information systems or the failure to secure information system data, security breaches, or the direct or indirect effect on the companies' business resulting from the occurrence of cyber attacks, terrorist incidents or the threat of terrorist incidents, and acts of war;

• adoption of or changes in accounting policies, principles, or estimates, including the potential adoption of all or a portion of International Financial Accounting Standards; 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.

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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. While reading the MD&A, please refer to the accompanying condensed consolidated financial statements of IDACORP and Idaho Power, and the notes thereto. This discussion updates the MD&A included in the Annual Report on Form 10-K for the year ended December 31, 2011, and should also be read in conjunction with the information in that report.

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 496,000 general business customers as of March 31, 2012.  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 Idaho Public Utilities Commission (IPUC) and the Oregon Public Utility Commission (OPUC), which determine the rates that Idaho Power charges to its general business customers.  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 Federal Energy Regulatory Commission (FERC) tariff and to provide transmission services under its FERC open access transmission tariff (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, and to seek to earn a return on investment.

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.  Idaho Power has implemented a tiered-rate structure and seasonal rates. Both mechanisms increase the rates customers pay during higher-usage periods based on the amount of usage and time of year and are premised on encouraging energy efficiency during higher-usage periods and reflect the higher cost of providing service in those periods. These rate structures also contribute to seasonal fluctuations in earnings and revenues. IDACORP’s and Idaho Power’s financial condition are also affected by regulatory decisions, through which Idaho Power seeks to recover its 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 of 1978 (PURPA); and IDACORP Energy, a marketer of energy commodities, which wound down operations in 2003. 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.

EXECUTIVE OVERVIEW

Brief Overview of First Quarter 2012 Financial Results

IDACORP's earnings were $0.50 per diluted share for the quarter ended March 31, 2012, compared to $0.60 per diluted share for the first quarter of 2011. IDACORP's earnings in the first quarter of 2012 relative to the same period in 2011 were negatively impacted by a $3.0 million decrease in the use of additional accumulated deferred investment tax credits (ADITC) for the quarter, increased operating and maintenance expenses, including pension and payroll-related expenses, and decreased sales volumes resulting from milder weather. These reductions were partially offset by the favorable effect of customer rate changes that went into effect in June 2011 and January 2012, an increase in earnings at BCC, and increased allowance for funds used during construction.

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 are generally affected by regulatory, economic, and other factors, many of which are described below.

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Emphasis on Timely Regulatory Cost Recovery:  The prices that Idaho Power is authorized to charge for its electric service is a major factor in determining IDACORP's and Idaho Power's results of operations and financial condition.  Because of the significant impact of ratemaking decisions on Idaho Power's business and financial condition, the company continues to focus on timely recovery of its costs through filings with the company's regulators. Effective implementation of Idaho Power's purposeful regulatory strategy is particularly important in an economic climate that puts more pressure on regulators to limit rate increases or otherwise take actions to limit the potential adverse impact of rate increases on customers. Certain notable regulatory developments that IDACORP and Idaho Power expect to have an impact on their future results, each of which is discussed in more detail under "Regulatory Matters" in this MD&A or in Note 3 - "Regulatory Matters" to the condensed consolidated financial statements included in this report, are described below. Additional important regulatory matters are also discussed in IDACORP's and Idaho Power's Annual Report on Form 10-K for the year ended December 31, 2011.

• Idaho 2011 General Rate Case Settlement - In December 2011, the IPUC approved a settlement stipulation providing for a $34.0 million overall increase in Idaho Power's annual Idaho jurisdictional base rate revenues, effective January 1, 2012.

• Idaho ADITC and Revenue Sharing - In December 2011, the IPUC approved a settlement stipulation, separate from the general rate case settlement, that permits Idaho Power to amortize additional ADITC to help achieve a minimum 9.5 percent rate of return on year-end equity in the Idaho jurisdiction (Idaho ROE) in 2012, 2013, and 2014, subject to prescribed limits and conditions. The settlement stipulation also provides for the potential sharing of Idaho-jurisdictional earnings in excess of specified levels of Idaho ROE.

• Langley Gulch Power Plant - In March 2012, Idaho Power filed an application with the IPUC requesting an increase in annual Idaho-jurisdiction base rates of $59.9 million, effective July 1, 2012, for recovery of Idaho Power's investment in the Langley Gulch power plant. The application is being processed under modified procedure, which increases the likelihood of, but does not assure, inclusion of the plant in rate base by the requested date. On March 9, 2012, Idaho Power filed an application with the OPUC requesting an annual increase in Oregon-jurisdictional revenues of $3.0 million, for inclusion of the Langley Gulch power plant in Idaho Power's rate base.

• Idaho PCA Orders - In both its Idaho and Oregon jurisdictions, Idaho Power has power cost adjustment (PCA) mechanisms that address the volatility of power supply costs and provide for annual adjustments to the rates charged to retail customers.  On April 13, 2012, Idaho Power made its annual Idaho PCA filing with the IPUC, requesting a $43 million increase to Idaho PCA rates, effective for the period from June 1, 2012 to May 31, 2013.

• Idaho Non-AMI Meter Depreciation - On April 27, 2012, the IPUC approved Idaho Power's application to decrease rates by $10.6 million, effective June 1, 2012, as a result of the removal of accelerated depreciation expense associated with non-advanced metering infrastructure (AMI) metering equipment.

• Oregon 2011 General Rate Case Settlement - In Idaho Power's Oregon general rate case, in February 2012 the OPUC approved a settlement stipulation providing for a $1.8 million base rate increase, effective March 1, 2012.

Economic Conditions and Customer Growth: Since 2008, economic conditions in Idaho Power's service territory have been relatively weak.  Unemployment rates remain high compared to historical levels. After peaking at 10.0 percent in early 2011, the service area unemployment rate fell to 8.4 percent by the end of 2011 and reached 7.8 percent by the end of February 2012, according to Idaho Department of Labor data. During the 12 months ended March 31, 2012, the customer growth rate in Idaho Power's service territory was 0.8 percent. By comparison, for the 20-year period ending 2011 the average annual customer growth rate in Idaho Power's service territory was 2.6 percent. Economic conditions can impact consumer demand for electricity, collectability of accounts, the volume of off-system sales, and Idaho Power's need for purchased power.  Management cannot predict the timing of, and pace at which, economic recovery may occur in Idaho Power's service territory.  Idaho Power continues to manage costs while executing its three-part strategy of responsible planning, responsible development and protection of resources, and responsible energy use. 

Weather Conditions and Associated Impacts:  Weather conditions normally have a significant impact on energy sales and the seasonality of those sales. Relatively low and high temperatures result in greater energy usage for heating and cooling, respectively.  During the agricultural growing season, which in large part occurs during the second and third quarters each calendar year, irrigation customers use electricity to operate irrigation pumps.  A 3.1 percent decrease in energy usage by customers during the first quarter of 2012 compared to the first quarter of 2011 is largely attributable to milder weather conditions during the first quarter of 2012, which decreased electricity demand for heating systems. As noted above, Idaho Power also has tiered rates and seasonal rates, which further contribute to increased revenues during higher-load periods.

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Idaho Power's hydroelectric facilities comprise approximately one-half of Idaho Power's nameplate generation capacity. The actual 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, base flows in the Snake River, spring flows, rainfall, water leases and other water rights, and other weather and stream flow considerations.  At the date of this report, Idaho Power expects hydroelectric generation during 2012 to be in the range of 7.5 to 9.5 million MWh, based on reservoir storage levels and forecasted weather conditions as of March 31, 2012, compared to 10.9 million MWh in 2011 and 7.3million MWh in 2010. Median annual hydroelectric generation is 8.6 million MWh. Due largely to favorable hydroelectric generation conditions, hydroelectric generation comprised 69 percent of Idaho Power's total system generation during 2011. For the three months ended March 31, 2012, hydroelectric generation comprised 68 percent of Idaho Power’s total system generation.  Hydroelectric generation decreased five percent in the first quarter of 2012 compared to the first quarter of 2011. Most of the decrease in power supply costs that typically results from increased hydroelectric generation is returned to customers through the PCA mechanisms.

Where favorable hydroelectric generating conditions exist for Idaho Power, they also may be abundant for other Pacific Northwest hydroelectric facility operators, thus increasing the available supply of lower-cost power and depressing regional wholesale market prices, which impacts the revenue Idaho Power receives from off-system sales of its excess power. Average wholesale power prices per MWh for sales for resale decreased 19 percent in the first quarter of 2012 compared to the first quarter of 2011, due to an abundant supply of wholesale power.

Fuel and Purchased Power Expense:  In addition to hydroelectric generation and power it purchases in the wholesale markets, Idaho Power relies significantly on coal and natural gas to fuel its generation facilities.  Fuel costs are impacted by electricity sales volumes, the terms of contracts for fuel, 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, and Idaho Power's hedging program for managing fuel costs. Looking ahead, operation of the Langley Gulch power plant that Idaho Power is currently constructing will increase Idaho Power's use of natural gas, and thus its exposure to volatility in natural gas prices.

Purchased power costs are impacted by the terms of contracts for purchased power, the rate of expansion of alternative energy generation sources such as wind energy, and wholesale energy market prices. Idaho Power is generally obligated to purchase power from PURPA generation projects at a specified price regardless of the then-current load demand or wholesale energy market prices. This increases the likelihood that Idaho Power will be required to reduce output from its lower-cost hydroelectric and fossil fuel-fired generation resources and may be required to sell in the wholesale power market the power it purchases from PURPA projects at a significant loss. Integration of intermittent, non-dispatchable resources into Idaho Power's portfolio also creates a number of complex operational risks and challenges, which Idaho Power is working to address, including through a comprehensive wind integration study.

The Idaho and Oregon PCA mechanisms mitigate in large part the potential adverse impacts of fluctuations in Idaho Power's power supply costs.  Idaho Power also uses 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 those policies and initiatives. In particular, 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, is scheduled to cease coal-fired operations in 2020. As legislation and regulations concerning greenhouse gas emissions develop, Idaho Power will assess the potential impact on the costs to operate its power generation facilities, as well as the willingness or ability of joint owners of power plants to fund any required pollution control equipment upgrades.

Other Notable Matters and Areas of Focus

Pension Plans:  Idaho Power contributed $34.0 million to its defined benefit pension plan in the first quarter of 2012. It contributed $18.5 million and $60.0 million to its defined benefit pension plan in 2011 and 2010, respectively. Idaho Power expects to make additional significant cash contributions to its defined benefit pension plan in the coming years. The primary

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impact of these contributions is on cash flows. In May 2011, the IPUC authorized Idaho Power to increase its annual recovery and amortization of deferred pension costs from $5.4 million to $17.1 million.

Water Management and Relicensing of Hydroelectric Projects: Because of Idaho Power's reliance on stream flow in the Snake River and its tributaries, Idaho Power participates in numerous proceedings and venues that may affect its water rights, seeking to preserve the long-term availability of its rights for use at its hydroelectric projects. Also, 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.

Transmission Projects: Idaho Power continues to focus on expansion of its transmission system in an effort to improve system reliability and resource adequacy through the proposed Boardman-to-Hemingway and Gateway West transmission projects. Construction of these projects cannot commence until all federal, state, and local regulatory requirements are met. In January 2012, Idaho Power entered into cost-sharing arrangements with third parties for the permitting phases of both projects. To further mitigate the risks associated with these projects, at least in part, Idaho Power plans to seek regulatory support for cost recovery from the IPUC and OPUC for the projects prior to construction.

Summary of First Quarter 2012 Financial Results

The following is a summary of Idaho Power's net income, net income attributable to IDACORP, Inc., and IDACORP's earnings per diluted share for the three months endedMarch 31, 2012 and 2011: 

	Three months ended March 31,
	2012		2011
Idaho Power net income	$	25,819	$	29,848
Net income attributable to IDACORP, Inc.	$	24,930	$	29,740
Average outstanding shares – diluted (000’s)	49,905		49,356
IDACORP, Inc. earnings per diluted share	$	0.50	$	0.60

The following table presents a reconciliation of net income attributable to IDACORP, Inc. for the three month period ended March 31, 2012 to the same period in 2011 (items are in millions and are before tax unless otherwise noted):

Net income attributable to IDACORP, Inc. - March 31, 2011				$	29.7
Change in Idaho Power net income before taxes:
Rate and other regulatory changes, including pension expense recovery, power cost and
fixed cost adjustment mechanisms	$	5.1
Changes in sales volumes	(2.8		)
Increased other operating and maintenance expenses:
Pension and payroll related expenses	(5.3		)
Purchased services and software-related expenses	(2.5		)
Increased depreciation expense	(1.1		)
Increased property taxes	(0.9		)
Increase in earnings at Bridger Coal Company	3.4
Increase in AFUDC	3.0
Other net increases	0.2
Change in additional amortization of ADITC	(3.0		)
Change in other income tax expense	(0.1		)
Total decrease in Idaho Power net income				(4.0		)
Other net decreases (net of tax)				(0.8		)
Net income attributable to IDACORP, Inc. - March 31, 2012				$	24.9

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Idaho Power net income decreased $4.0 million for the quarter, largely as a result of a $3 million decrease in the use of additional ADITC for the quarter. The amount of additional ADITC used is based on Idaho Power's Idaho-jurisdiction earnings projections for the full year, evenly divided by quarters. Also adding to the decrease in net income were increases in other operating and maintenance (O&M) expense, depreciation and property taxes, and lower sales volumes. The O&M increase was partially offset by revenues generated from increased rates. Also helping to offset the increases in costs were improved earnings at BCC due to increased sales volumes and coal prices, decreased interest expense on long-term debt, and increases in allowance for funds used during construction (AFUDC), which represents the cost of financing construction projects with borrowed and equity funds.

On January 1, 2012 and June 1, 2011, Idaho Power implemented rate orders increasing Idaho base rates and reducing PCA rates. These rate changes collectively reduced Idaho-jurisdiction revenues approximately $2.9 million for the quarter when compared with the same period in the prior year. The revenue impact of certain rate changes was directly offset by changes in operating expenses. For example, Idaho PCA amortization expense was reduced by $22.3 million for the quarter compared to the same period of 2011 due to the decrease in the corresponding Idaho PCA true-up rate. The rate changes, combined with changes in power supply costs and net of the PCA mechanisms, increased operating income by approximately $5.1 million for the quarter. The rate increase that took effect on January 1, 2012 in the Idaho jurisdiction is more heavily allocated to the summer months than to the winter months through the IPUC-approved rate design; therefore, Idaho Power expects that the rate increase will have a greater impact on second and third quarter revenues.

Relatively mild weather during the first quarter of 2012 reduced heating demand, lowering operating income by $2.8 million. Increased payroll-related costs of $5.3 million were primarily a result of a $3.0 million increase in pension expense for the first quarter of 2012. Costs of consultants and software-related costs increased $2.5 million during the first quarter of 2012, a significant portion of which relates to a lower reimbursement from the U.S. Department of Energy (DOE) for Smart Grid-related items in 2012 compared to 2011. Depreciation expenses and property tax costs increased by $1.1 million and $0.9 million, respectively, for the first quarter of 2012 relative to the first quarter of 2011 due to increased plant in service as well as increased property tax rates. The increased pension expense was concurrent with the regulatory authorization to recover these costs through rates.

Key Operating and Financial Metrics

IDACORP’s and Idaho Power’s outlook for 2012 full year metrics is as follows:

	2012 Estimates
	Current (3)	Previous (4)
Idaho Power Operating & Maintenance Expense (millions)	No Change	$325-$335
Idaho Power Additional Amortization of ADITC (millions)	No Change	< $5 million
Idaho Power Capital Expenditures (millions)(1)	No Change	$230-$240
Idaho Power Hydroelectric Generation (million MWh)(2)	No Change	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 (net of ongoing payments from third parties participating as joint funders in the permitting projects), excluding AFUDC.
(2) Based on reservoir storage levels and forecasted weather conditions as of March 31, 2012.
(3) As of May 3, 2012.
(4) As of February 22, 2012, the date of filing of IDACORP's and Idaho Power's Annual Report on Form 10-K for the year ended December 31, 2011.

RESULTS OF OPERATIONS

This section of MD&A takes a closer look at the significant factors that affected IDACORP’s and Idaho Power’s earnings during the three months endedMarch 31, 2012.  In this analysis, the results for the three months endedMarch 31, 2012 are compared to the same period in 2011. In MD&A, Megawatt-hours (MWh) and dollar amounts, other than earnings per share, are in thousands unless otherwise indicated.

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Utility Operations

The table below presents Idaho Power’s energy sales and supply (in thousands of MWh) for the three months endedMarch 31, 2012 and 2011. 

	Three months ended March 31,
	2012		2011
General business sales	3,178		3,241
Off-system sales	974		849
Total energy sales	4,152		4,090
Hydroelectric generation	2,568		2,699
Coal generation	1,205		1,194
Natural gas and other generation	12		18
Total system generation	3,785		3,911
Purchased power	645		471
Line losses	(278	)	(292	)
Total energy supply	4,152		4,090

The increase in volume of purchased power is largely attributable to mandated power purchases from cogeneration and small power production (CSPP) facilities pursuant to PURPA. Idaho Power seeks to resell into the wholesale electricity markets power it has purchased under PURPA agreements that it does not need or cannot use to serve loads. This contributed to the increase in off-system sales for the period. The cost of power purchases pursuant to PURPA is passed through to customers via the PCA mechanism, with the primary impact being on customer rates.

Idaho Power’s system is dual peaking, with the larger peak demand occurring in the summer.  To reduce the magnitude of peak demands, Idaho Power has implemented a demand response program and a number of energy efficiency programs. The record 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.

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General Business Revenues:  The table below presents Idaho Power’s general business revenues and MWh sales for the three months endedMarch 31, 2012 and 2011 and the number of customers as of March 31, 2012 and 2011.

	Three months ended March 31,
	2012			2011
Revenue
Residential	$	112,546		$	117,268
Commercial	53,436			56,018
Industrial	33,341			31,951
Irrigation	673			621
Total	199,996			205,858
Deferred revenue related to Hells Canyon
Complex relicensing AFUDC(1)	(2,567		)	(2,586		)
Total general business revenues	$	197,429		$	203,272
MWh
Residential	1,435			1,499
Commercial	948			964
Industrial	787			771
Irrigation	8			7
Total	3,178			3,241
Customers (period end)
Residential	412,047			408,862
Commercial	65,346			64,671
Industrial	118			126
Irrigation	18,765			18,530
Total	496,276			492,189

⁽¹⁾As part of its January 30, 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 is not yet complete and the relicensing asset has not been placed in service. Idaho Power expects to collect approximately $10.7 million annually in the Idaho jurisdiction, but will defer revenue recognition of the amounts collected until the license is issued and the asset is placed in service under the new license.

Changes in rates and changes in customer demand are the primary reasons for fluctuations in general business revenue from period to period. The table below presents the rate changes that significantly impacted the comparability of revenue for the first quarter of 2012 compared to the first quarter of 2011.

		Percentage Rate Increase (Decrease)		Annualized $ Impact (millions)
	Effective Date
Description
2011 Idaho PCA	6/1/2011	(4.8%)		(40	)
2011 Idaho pension expense recovery	6/1/2011	1.4	%	12
2011 Idaho settlement agreement	1/1/2012	4.1	%	34

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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. Boise, Idaho weather conditions for the three months endedMarch 31, 2012 and 2011 are included in the table below.

	Three months ended March 31,
	2012	2011	Normal
Heating degree-days (1)	2,240	2,486	2,574
Cooling degree-days (1)	—	—	—
(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.

General business revenue decreased $5.8 million in the first quarter of 2012 compared to the same period in 2011.  The changes in general business revenue are primarily attributable to the effects of rate changes and usage. These factors are discussed in more detail below.

•         Rates.  Rate changes combined to reduce general business revenue by $2.9 million for the quarter compared to the same period in 2011. The revenue impact of several of these changes was directly offset by associated changes in operating expenses. For example, Idaho PCA amortization expense was reduced $22.3 million for the quarter compared to the same period in 2011 due to the decrease in the corresponding Idaho PCA rate. Idaho jurisdiction pension expense recovery and FCA rate changes were fully offset by related amortizations.

•         Customers.  Changes in revenue related to a special industrial customer, along with a small increase in customer count, increased general business revenues by $2.6 million for the quarter compared to the same period in 2011.  For the quarter, customer count increased 0.3 percent compared to the same period in 2011.

•         Usage.  For the first quarter of 2012, lower usage decreased general business revenue by $5.5 million compared to the first quarter of 2011. Residential and commercial usage decreased by 5 percent and 2 percent, respectively, due primarily to relatively mild first quarter temperatures, which decreases power demand for heating purposes. This decrease was partially offset for the quarter by a 5 percent increase in industrial usage.

Off-System Sales:  Off-system sales consist primarily of long-term sales contracts and opportunity sales of surplus system energy.  The table below presents Idaho Power’s off-system sales for the three months endedMarch 31, 2012 and 2011. 

	Three months ended March 31,
	2012		2011
Revenue	$	27,708	$	29,845
MWh sold	974		849
Revenue per MWh	$	28.45	$	35.15

For the quarter, off-system sales revenue decreased $2.1 million, or 7.2 percent, as compared to the same period in 2011. Sales volumes were up 14.7 percent for the quarter, as a result of mandated power purchases from new PURPA contract wind generation being brought on-line since the first quarter of 2011 as well as decreased load. This increase in volume was more than offset by a 19.1 percent decrease in average prices due to an over supply of energy in the region.

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Other Revenues:  The table below presents the components of other revenues for the three months endedMarch 31, 2012 and 2011. 

	Three months ended March 31,
	2012		2011
Transmission services and other	$	10,869	$	11,234
Energy efficiency	4,477		6,711
Total	$	15,346	$	17,945

Other revenue decreased $2.6 million in the first quarter of 2012 compared to the same period in 2011, primarily as a result of decreases in energy efficiency revenues. The reduction in energy efficiency revenues was mostly related to a regulatory order allowing Idaho Power to move custom efficiency program payments to an amortizing regulatory asset. The remaining decrease related to less money being spent, and thus less being recognized, for energy efficiency programs during the quarter when compared to the same period in the prior year.

Energy efficiency activities are funded through a rider mechanism on customer bills.  Energy efficiency program expenditures are reported as an operating expense with an equal amount of revenues recorded in other revenues, resulting in no net impact on earnings.  The cumulative variance between expenditures and amounts collected through the rider is recorded as a regulatory asset or liability pending future collection from or obligation to customers.  A liability balance indicates that Idaho Power has collected more than it has spent and an asset balance indicates that Idaho Power has spent more than it has collected.  As of March 31, 2012, Idaho Power’s energy efficiency rider balance was a regulatory asset of $4.9 million.

Purchased power:  The table below presents Idaho Power’s purchased power expenses and volumes for the three months endedMarch 31, 2012 and 2011. 

	Three months ended March 31,
	2012		2011
Expense
PURPA contracts	$	23,757	$	14,173
Other purchased power (including wheeling)	10,520		10,921
Total purchased power expense	$	34,277	$	25,094
MWh purchased
PURPA contracts	416		244
Other purchased power	229		227
Total MWh purchased	645		471
Cost per MWh from PURPA contracts	$	57.11	$	58.09
Cost per MWh from other sources	$	45.94	$	48.11
Weighted average - all sources	$	53.14	$	53.28

Purchased power expense increased $9.2 million, or 37 percent, in the first quarter of 2012 compared to the same period in 2011. This increase was driven by the volume of power purchased from PURPA contracts, which increased 70 percent for the quarter due to new PURPA wind generation facilities coming on-line throughout the prior year. The increases in contract purchases were partially offset by a small decrease in the average price of wholesale purchased power.

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Fuel expense:  The table below presents Idaho Power’s fuel expenses and generation at its thermal generating plants for the three months endedMarch 31, 2012 and 2011. 

	Three months ended March 31,
	2012		2011
Expense
Coal	$	31,084	$	28,006
Natural gas and other	1,667		1,896
Total fuel expense	$	32,751	$	29,902
MWh generated
Coal	1,205		1,194
Natural gas and other	12		18
Total MWh generated	1,217		1,212
Cost per MWh
Coal	$	25.80	$	23.46
Natural gas and other	138.92		105.33
Weighted average, all sources	26.91		24.67

Fuel expense increased $2.8 million, or 10 percent, in the first quarter of 2012 compared to the same period in 2011 due principally to increased fuel costs at Idaho Power's Jim Bridger coal-fired thermal plant. The coal consumed was more expensive due to higher fixed costs per ton. Thermal plant output was relatively flat for the quarter compared to the first quarter of 2011.

Most fuel supply contracts are subject to changes in published indexes that are closely related to materials and supplies, labor, and diesel costs. 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 these fixed charges when generation output is substantially different between the two periods. The relatively large cost per MWh for natural gas facilities during the periods shown in the table above was the result of the allocation of fixed costs over a low volume of output.

PCA mechanisms:  Idaho Power's power supply costs (primarily purchased power and fuel, less off-system sales) 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 the Idaho and Oregon jurisdictions.  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 in a future period, resulting in fluctuations in operating cash flows from year to year.

PCA expense represents the effects of the Idaho and Oregon PCA mechanisms.  The table below presents the components of the Idaho and Oregon PCA mechanisms for the three months endedMarch 31, 2012 and 2011. 

	Three months ended March 31,
	2012			2011
Idaho power supply cost accrual	$	9,624		$	24,915
Oregon power supply cost (deferral) accrual	(138		)	465
Amortization of prior year authorized balances	(478		)	5,926
Total power cost adjustment expense	$	9,008		$	31,306

The power supply accruals or deferrals represent the portion of that periods' power supply cost fluctuations accrued or deferred under the PCA mechanisms. Accruals represent additional costs recorded because actual power supply costs were less than the amount forecasted in PCA rates. The power supply cost accrual in 2012 is less than in 2011 because actual power supply costs were closer to the amounts forecasted. If actual power supply costs are greater than the amount forecasted in PCA rates, most

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of the excess is deferred. The amortization of the prior year’s balances represents the amounts being collected (refunded) in the current PCA year that were deferred or accrued in the prior PCA year (the true-up component of the PCA).

Other operations and maintenance (O&M) expenses:  The $7.9 million increase in other O&M expense in the first quarter of 2012 as compared to the first quarter of 2011 was principally due to:

• $3.0 million of increased pension expense, which increased in June 2011 concurrent with increased recovery of deferred pension costs in rates;

• increased labor and benefits costs of $2.3 million; and

• increases in other costs of $2.5 million, related to increases in consultant costs, software licenses and maintenance, and other purchased services. A significant portion of the increase relates to a lower reimbursement from the DOE for Smart Grid-related items in 2012 compared to 2011.

Income Tax Expense

IDACORP's and Idaho Power's income tax expense for the three months endedMarch 31, 2012, compared to the same period in 2011, increased $3.4 million and $3.1 million, respectively, primarily as a result of lower utilization of additional ADITC amortization at Idaho Power. 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.

Accelerated Amortization of ADITC: Idaho Power's December 2011 settlement stipulation with the IPUC and other parties provided for additional amortization of ADITC if Idaho Power's actual Idaho ROE is below 9.5 percent in any calendar year from 2012 to 2014.  For information relating to Idaho Power's 2011 settlement stipulation, see Note 3 - “Regulatory Matters” to the condensed consolidated financial statements included in this report. In accordance with the settlement stipulation, Idaho Power has $25 million of additional ADITC amortization available for use in 2012. Idaho Power recorded $0.8 million of ADITC amortization in the first quarter of 2012.  In the first quarter of 2011, Idaho Power had accrued $3.9 million of additional ADITC under a similar previous settlement agreement with the IPUC.

As of the date of this report, Idaho Power expects to record less than $5 million of additional ADITC amortization for the full year 2012 based on itsestimate of 2012 Idaho ROE.  The amount of ADITC recorded during 2012 could change significantly depending on Idaho Power's actual 2012 results.

Bonus Depreciation: Bonus depreciation provides for the accelerated deduction of current capital expenditures from certain asset classes.  For 2012, the deduction is equal to 50 percent of a qualifying asset's cost. Idaho Power has included an estimated bonus depreciation deduction in its current federal income tax provision.

LIQUIDITY AND CAPITAL RESOURCES

Overview

IDACORP's and Idaho Power's operating cash flows are driven principally by Idaho Power's 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 and pension contributions, 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 in a period of significant 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.  Idaho Power expects that total capital expenditures will be between $720 million and $740 million over the period from 2012 through 2014. 

Idaho Power's operating cash flows usually do not fully support the amount required for utility capital expenditures during periods of significant infrastructure development.  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,

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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 to continue financing capital requirements during the remainder of 2012 with a combination of internally generated funds and externally financed capital. Idaho Power issued $150 million of first mortgage bonds, medium-term notes in April 2012, and IDACORP and Idaho Power expect a minimal need for any additional external financing in 2012. However, IDACORP plans to continue to issue common stock under the pre-existing dividend reinvestment and employee-related stock purchase plans in 2012. IDACORP may also determine to issue IDACORP common stock from time to time under its continuous equity program, depending on market conditions and capital needs. IDACORP and Idaho Power seek to maintain capital structures of approximately 50 percent debt and 50 percent equity, and maintaining this ratio influences IDACORP's and Idaho Power's debt and equity issuance decisions.

As of April 27, 2012, IDACORP's and Idaho Power's access to debt, equity, and credit arrangements included:

• their respective $125 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 up to 3.0 million shares of IDACORP common stock available for issuance under its continuous equity program. Approximately $539 million of debt and equity securities issuances remained available under the shelf registration statement;

• Idaho Power's shelf registration statement, which can be used for the issuance of first mortgage bonds and debt securities; $150 million remained available under the shelf registration statement; 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 and the weak economy have in recent years caused a general concern regarding access to sufficient capital at a reasonable cost.  Notwithstanding these concerns, IDACORP and Idaho Power have not been significantly affected 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 anticipated short- and long-term borrowing needs.

Operating Cash Flows

IDACORP’s and Idaho Power’s operating cash inflows for the three months endedMarch 31, 2012 were $38 million and $41 million, respectively.  IDACORP's and Idaho Power's operating cash flows decreased by $56 million and $62 million, respectively, compared to the three months endedMarch 31, 2011.  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 2012 relative to the same period in 2011 are as follows:

• Idaho Power made contributions of $34 million to its defined benefit pension plan during the first three months of 2012. No cash contributions were made during the first three months of 2011;

•      cash inflows related to income taxes decreased by $13 million and $19 million for IDACORP and Idaho Power, respectively. IDACORP had net income tax payments of $0.2 million in 2012 compared with net refunds of nearly $13 million in 2011. Idaho Power’s net refunds from IDACORP for income tax were $3 million for the three months endedMarch 31, 2012, compared with net refunds of $22 million for the same period in 2011;

• changes in regulatory assets associated with the Idaho and Oregon PCA mechanisms reduced cash flows by $22 million, as Idaho Power collected $6 million less of previously deferred costs and incurred $15 million less in the current year accrual, as compared with the first three months of 2011; and

• the company's investment in BCC resulted in a net distribution to Idaho Power of $9.1 million for the first three months of 2012, as compared to a net contribution of $0.3 million for the first three months of 2011.

Investing Cash Flows

Cash flows from investing activities consist primarily of capital expenditures related to new construction and improvements to Idaho Power’s generation, transmission, and distribution facilities.  IDACORP’s and Idaho Power’s investing cash outflows were $49 million for the three months endedMarch 31, 2012, a decrease of $51 million for IDACORP and Idaho Power from the three months endedMarch 31, 2011.  Investing cash outflows for 2012 and 2011 were primarily for construction of utility

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infrastructure needed to address Idaho Power’s peak demand growth, aging plant and equipment, and forecasted customer growth. The first quarter 2012 expenditures for additions to property, plant and equipment were less than the first quarter 2011 largely as a result of reduced activity related to the Langley Gulch Power Plant during 2012 as construction nears completion.

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 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 endedMarch 31, 2012 were $8 million and $9 million, respectively.  The following are significant items that affected financing cash flows in the first quarter of 2012:

•      IDACORP and Idaho Power paid cash dividends of approximately $17 million;

•      IDACORP had net borrowings of $9 million of commercial paper; and

•      IDACORP made a capital contribution of $7.5 million to Idaho Power.

On June 17, 2010, Idaho Power entered into a Selling Agency Agreement with Banc of America Securities LLC; BNY Mellon Capital Markets, LLC; J.P. Morgan Securities Inc.; KeyBanc Capital Markets Inc.; Merrill Lynch, Pierce, Fenner & Smith Incorporated; Mitsubishi UFJ Securities (USA), Inc.; RBC Capital Markets Corporation; SunTrust Robinson Humphrey, Inc.; U.S. Bancorp Investments, Inc.; and Wells Fargo Securities, LLC in connection with the potential issuance and sale from time to time of up to $500 million aggregate principal amount of first mortgage bonds under a shelf registration statement. In August 2010, Idaho Power issued $200 million of first mortgage bonds, medium-term notes, Series I, under the shelf registration statement. On April 13, 2012, Idaho Power issued $75 million of 2.95% first mortgage bonds, medium-term notes, Series I, maturing on April 1, 2022 and $75 million of 4.30% first mortgage bonds, medium-term notes, Series I, maturing on April 1, 2042, under the Selling Agency Agreement and shelf registration statement. In April 2012, Idaho Power issued an irrevocable notice of redemption to redeem, prior to maturity, its $100 million in principal amount of 4.75% first mortgage bonds, medium-term notes due November 2012. Idaho Power intends to use a portion of the net proceeds of the April 2012 issuance of first mortgage bonds, medium-term notes to effect the redemption, which Idaho Power expects to be completed during May 2012. As a result, the $100 million of 4.75% first mortgage bonds, medium-term notes due November 2012 are reported as long-term debt in the condensed consolidated balance sheets, instead of as current maturities of long-term debt. Idaho Power expects to use the remaining net proceeds to fund a portion of its capital requirements.

Financing Programs

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 $150 million of first mortgage bonds and unsecured debt. Refer to Note 4 - “Long-Term Debt” to the 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 defined in the Indenture of Mortgage and Deed of Trust. As of March 31, 2012, Idaho Power could issue approximately $1.3 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, 2012 was limited to approximately $539 million. As a result of the issuance of additional first mortgage bonds in April 2012, described above, as of the date of this report the maximum amount of first mortgage bonds Idaho Power could issue was limited to approximately $389 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.

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Credit Facilities: IDACORP and Idaho Power have $125 million and $300 million credit facilities, respectively. Each of the credit facilities terminate on October26,2016, and may be used for general corporate purposes and commercial paper back-up. IDACORP's facility permits borrowings under a revolving line of credit of up to $125 million at any one time outstanding, including swingline loans not to exceed $15 million at any time and letters of credit not to exceed $50 million at any time. IDACORP's facility may be increased, subject to specified conditions, to $150 million. Idaho Power's facility permits borrowings through the issuance of loans and standby letters of credit of up to $300 million at any one time outstanding, including swingline loans not to exceed $30 million at any one time. Idaho Power's facility may be increased, subject to specified conditions, to $450 million. Each company may request up to two one-year extensions of the then-existing maturity date. The interest rates for any borrowings under the facilities are based on either (1) a floating rate that is equal to the highest of the prime rate, federal funds rate plus 0.5 percent, or LIBOR rate plus 1.0 percent, or (2) the LIBOR rate, plus, in each case, an applicable margin. The applicable margin is based on IDACORP's or Idaho Power's, as applicable, senior unsecured long-term indebtedness credit rating by Moody's Investors Service, Inc., Standard and Poor's Ratings Services, and Fitch Rating Services, Inc., as set forth on a schedule to the credit agreements. The companies also pay a facility fee based on the respective company's credit rating for senior unsecured long-term debt securities.

Each facility contains a covenant requiring each company to maintain a leverage ratio of consolidated indebtedness to consolidated total capitalization equal to or less 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, including, in some instances, 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, 2012, the leverage ratios for IDACORP and Idaho Power were 48 percent and 49 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 certain mergers, acquisitions, and investments, restrict the creation of certain liens, and prohibit entering into any agreements restricting dividend payments from any material subsidiary. At March 31, 2012, IDACORP and Idaho Power were in compliance with all facility covenants.

The events of default under both facilities include, without limitation, non-payment of principal, interest, or fees; materially false representations or warranties; breach of covenants; bankruptcy or insolvency events; condemnation of property; cross-default to certain other indebtedness; failure to pay certain judgments; change of control; failure of IDACORP to own free and clear of liens the voting stock of Idaho Power; the occurrence of specified events or the incurring of specified liabilities relating to benefit plans; and the incurrence of certain environmental liabilities, subject, in certain instances, to cure periods.

Upon any event of default relating to the voluntary or involuntary bankruptcy of IDACORP or Idaho Power or the appointment of a receiver, the obligations of the lenders to make loans under the applicable facility and to issue letters of credit will automatically terminate and all unpaid obligations will become due and payable. Upon any other event of default, the lenders holding greater than 50 percent of the outstanding loans or greater than 50 percent of the aggregate commitments (required lenders) or the administrative agent with the consent of the required lenders may terminate or suspend the obligations of the lenders to make loans under the facility and to issue letters of credit under the facility and/or declare the obligations to be due and payable. During an event of default under the facilities, the lenders may, at their option, increase the applicable interest rates then in effect and the letter of credit fee by 2.0 percent per annum. 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.

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.

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The table below outlines available short-term borrowing liquidity as of the dates specified.

	March 31, 2012						December 31, 2011
				Idaho						Idaho
	IDACORP(2)			Power			IDACORP(2)			Power
Revolving credit facility	$	125,000		$	300,000		$	125,000		$	300,000
Commercial paper outstanding	(61,500		)	(1,500		)	(54,200		)	—
Identified for other use (1)	—			(24,245		)	—			(24,245		)
Net balance available	$	63,500		$	274,255		$	70,800		$	275,755
(1)  Port of Morrow and American Falls bonds that holders may put to Idaho Power.
(2)  Holding company only.

At April 27, 2012, IDACORP had no loans outstanding under its credit facility and $61.6 million of commercial paper outstanding, and Idaho Power had no loans outstanding under its credit facility and no commercial paper outstanding.

The table below presents additional information about short-term borrowing during the three-month period ended March 31, 2012 and 2011:

	March 31, 2012						March 31, 2011
	IDACORP (1)			Idaho Power			IDACORP (1)			Idaho Power
Commercial paper:
Period end:
Amount outstanding	$	61,500		$	1,500		$	74,100		$	—
Weighted average interest rate	0.46		%	0.41		%	0.40		%	—		%
Daily average amount outstanding during the period	$	51,898		$	3,143		$	69,850		$	—
Weighted average interest rate during the period	0.45		%	0.42		%	0.40		%	—		%
Maximum month-end balance	$	61,500		$	1,500		$	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 their respective credit ratings.  The table below outlines the ratings of Idaho Power’s and IDACORP’s securities, and the ratings outlook, by Standard & Poor’s Ratings Services and Moody’s Investors Service as of the date of this report. 

	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.

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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, 2012, Idaho Power had posted no performance assurance collateral.  Should Idaho Power experience a reduction in its credit rating on its unsecured debt to below investment grade Idaho Power could be subject to requests by its wholesale counterparties to post 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, 2012, the amount of additional collateral that could be requested upon a downgrade to below investment grade is approximately $11 million.  To minimize capital requirements, Idaho Power actively monitors its portfolio exposure and the potential exposure to additional requests for performance assurance collateral through sensitivity analysis.

Capital Requirements

Idaho Power's construction expenditureswere $48 million and $102 million during the three months endedMarch 31, 2012 and 2011, respectively.  The table below presents Idaho Power's estimated cash requirements for construction, excluding AFUDC, for 2012 through 2014 (in millions of dollars).

	2012	2013-2014
Ongoing capital expenditures	$200-205	$490-500
Langley Gulch Power Plant (detailed below)	30-35	—
Total	$230-240	$490-500

Major Infrastructure Projects:

Idaho Power is engaged in the development of a number of significant projects and has entered into arrangements with third parties concerning joint infrastructure development. The discussion below provides a summary of certain of these projects and notable developments during the three months endedMarch 31, 2012 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, 2011. The discussion below should be read in conjunction with that report.

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. Idaho Power estimates that the plant will be in service by July 1, 2012. Idaho Power has incurred $375 million, including AFUDC, of capital expenditures associated with the project from inception in 2009 through March 31, 2012.

Boardman-to-Hemingway Line:The Boardman-to-Hemingway line, a proposed 300-mile, 500-kV transmission project between a station near Boardman, Oregon and the Hemingway station near Boise, Idaho, will provide transmission service to meet needs identified in the 2011 Integrated Resource Plan (IRP) and other requests pursuant to Idaho Power's OATT. In January 2012, Idaho Power entered into a joint funding agreement with PacifiCorp and BPA to jointly pursue permitting of the project. The joint funding agreement provides that Idaho Power's interest in the permitting phase of the project would be 21.21 percent, and that during future negotiations relating to construction of the transmission line Idaho Power would seek to retain that percentage interest in the completed project. Idaho Power's estimated share of the cost of the permitting phase of the project is $11 million, including AFUDC. Total cost estimates for the project are approximately $820 million, including AFUDC. This cost estimate excludes the impacts of inflation and price changes of materials and labor resources that may occur following the date of the estimate. Idaho Power's share of the permitting phase of the project (excluding AFUDC) is included in the capital requirements table above. Construction costs beyond the permitting phase are not included in the table above. The preferred portfolio in Idaho Power's 2011 IRP provides for a 2016 in-service date for the transmission line, as immediate system reliability benefits could be realized by construction of the transmission line by that date. However, the actual completion date of the project is subject to siting, permitting, regulatory approvals, individual participant's in-service requirements, the terms of any resulting joint construction agreements, and other conditions.

Gateway West Line: Idaho Power and PacifiCorp are pursuing the joint development of the Gateway West project, a transmission project between a station located near Douglas, Wyoming and the Hemingway station. In January 2012, Idaho Power and PacifiCorp entered a new joint funding agreement for permitting of the project. Idaho Power's estimated cost for the permitting phase of the Gateway West project is approximately $24 million, including AFUDC. As of the date of this report, Idaho Power estimates the total cost for its share of the project (including both permitting and construction) to be between $150 million and $300 million, including AFUDC. Idaho Power's share of the permitting phase of the project (excluding AFUDC) is included in the capital requirements table above. Construction costs are not included in the table above. Timing of the

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construction of each segment of the project is subject to siting, permitting, regulatory approvals, each participant's in-service requirements, the terms of any resulting joint construction agreements, and other conditions.

Memorandum of Understanding, dated January 12, 2012, among Idaho Power, PacifiCorp, and BPA (2012 MOU): The 2012 MOU provides that the parties will negotiate in good faith the terms of mutually satisfactory definitive agreements that would allow BPA to meet its load service obligations in southeast Idaho. It provides that the parties will explore opportunities to establish eastern Idaho load service from the Hemingway substation in exchange for similar service from the Federal Columbia River Transmission System, and will consider whether to replace certain transmission arrangements involving existing assets with joint ownership transmission or other arrangements. The 2012 MOU outlines at least two potential alternatives for further negotiation, including a network service option and an asset ownership rights option on certain of Idaho Power's and PacifiCorp's transmission systems. Any party may terminate the 2012 MOU at any time, without penalty, and the 2012 MOU automatically expires on December 31, 2014.

AMI/Smart Grid and American Recovery and Reinvestment Act of 2009 (ARRA): The advanced metering infrastructure project provides the means to automatically retrieve energy consumption information, eliminating manual meter reading expense. In December 2011, Idaho Power completed the installation of its advanced metering technology at a cost of $71.8 million. Under the ARRA, Idaho Power was awarded a grant of $47 million from the DOE. The grant was signed by the DOE in April 2010 and applies to project costs, including those associated with the AMI project, incurred beginning in August 2009 for a three-year term. As of March 31, 2012, Idaho Power had invoiced approximately $34.3 million to the DOE, of which $34.0 million had been received, and expects to continue billing and collecting monthly over the remaining term of the award. The costs to be reimbursed by the grant are not included in the Capital Requirements table above.

Retirement Benefit Plan Contribution:During the first quarter of 2012, Idaho Power contributed $34 million to its defined benefit pension plan. Idaho Power contributed $18.5 million to its defined benefit pension plan in 2011. As reported in more detail in IDACORP's and Idaho Power's Annual Report on Form 10-K for the year ended December 31, 2011, Idaho Power expects to make additional significant cash contributions to its defined benefit pension plan in coming years.

Contractual Obligations

The only material change to contractual obligations, outside of the ordinary course of business, during the three months endedMarch 31, 2012 related to a power purchase agreement with a solar energy project that was terminated, which reduced Idaho Power's contractual payment obligations by approximately $90 million over the 25-year life of the contract.

Dividends

The amount and timing of dividends paid on IDACORP’s common stock are within the discretion of IDACORP’s board of directors.  IDACORP's board of directors reviews the dividend rate periodically to determine its appropriateness in light of IDACORP’s current and long-term financial position and results of operations, capital requirements, rating agency requirements, contractual and regulatory restrictions, 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. IDACORP has a dividend policy that provides for a target long-term dividend payout ratio of between 50 and 60 percent of sustainable IDACORP earnings, with the flexibility to achieve that payout ratio over time and to adjust the payout ratio or to deviate from the target payout ratio from time to time based on the various factors that drive the IDACORP board of directors' dividend decisions. Notwithstanding the dividend policy adopted by the IDACORP board, the dividends IDACORP pays remain in the discretion of the board of directors who, when evaluating the dividend amount, will continue to take into account the foregoing factors, among others. On January 19, 2012, IDACORP's board of directors voted to increase the quarterly dividend, commencing with the dividend paid on February 29, 2012, to $0.33 per share of IDACORP common stock, from the prior quarterly dividend amount of $0.30 per share of IDACORP common stock. For additional information relating to IDACORP and Idaho Power dividends, including additional 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.

Contingencies and Proceedings

IDACORP and Idaho Power are involved in a number of litigation, alternative dispute resolution, and administrative 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. Certain legal proceedings to which IDACORP or Idaho Power are parties or are otherwise involved are described in Note 9 - "Contingencies" to the condensed consolidated financial statements included in this report.

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Except where noted in Note 9, in many instances IDACORP and Idaho Power are unable to predict the outcomes of the matters or estimate the impact the proceedings may have on their financial positions, results of operations, or cash flows.

Off-Balance Sheet Arrangements

IDACORP’s and Idaho Power’s off-balance sheet arrangements have not changed materially from those reported in MD&A in IDACORP's and Idaho Power's Annual Report on Form 10-K for the year ended December 31, 2011.

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 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 since the discussion of these matters in Item 7 - MD&A and in Note 3 - "Regulatory Matters" in IDACORP's and Idaho Power's Annual Report on Form 10-K for the year ended December 31, 2011, 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 and orders.

Change in Deferred Net Power Supply Costs

Deferred power supply costs represent certain differences between Idaho Power's actual net power supply costs and the costs included in its retail rates, the latter being based on annual estimates of power supply costs. Deferred power supply costs are recorded on the balance sheets for future recovery or refund through customer rates. The table below summarizes the change in deferred net power supply costs during the three months endedMarch 31, 2012.

	Idaho			Oregon(1)			Total
Balance at December 31, 2011	$	(13,121	)	$	8,490		$	(4,631	)
Current period net power supply costs accrued	(9,624		)	138			(9,486		)
Prior costs expensed and recovered through rates	1,014			(536		)	478
SO2 allowance and renewable energy certificate (REC) sales	(806		)	(43		)	(849		)
Interest and other	(80		)	143			63
Balance at March 31, 2012	$	(22,617	)	$	8,192		$	(14,425	)
(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.

Recent Regulatory Developments

Regulatory developments involving the rates that Idaho Power charges its retail customers have been described in Note 3 - "Regulatory Matters" to the condensed consolidated financial statements included in this report, as well as in IDACORP's and Idaho Power's Annual Report on Form 10-K, as noted above. Certain of these developments include the following:

• Idaho General Rate Case Settlement: In December 2011, the IPUC approved a settlement stipulation in Idaho Power's general rate case, which provides for a 7.86 percent authorized rate of return on an Idaho-jurisdictional rate base of approximately $2.36 billion. The approved settlement stipulation resulted in a 4.07 percent, or $34.0 million, overall increase in Idaho Power's annual Idaho jurisdictional base rate revenues. New rates in conformity with the settlement became effective on January 1, 2012.

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• ADITC and Revenue Sharing Mechanism: In December 2011, the IPUC issued an order, separate from the then-pending Idaho general rate case proceeding, approving a settlement stipulation that provides as follows:

◦ if Idaho Power's actual Idaho ROE for 2012, 2013, or 2014 is less than 9.5 percent, then Idaho Power may amortize additional ADITC to help achieve a minimum 9.5 percent Idaho ROE in the applicable year. Idaho Power would be permitted to amortize additional ADITC in an aggregate amount up to $45 million over the three-year period, but could use no more than $25 million in 2012;

◦ if Idaho Power's actual Idaho ROE for 2012, 2013, or 2014 exceeds 10.0 percent, the amount of Idaho Power's Idaho jurisdictional earnings exceeding a 10.0 percent, but less than a 10.5 percent, Idaho ROE for the applicable year would be shared equally between Idaho Power and its Idaho customers; and

◦ if Idaho Power's actual Idaho ROE for 2012, 2013, or 2014 exceeds 10.5 percent, the amount of Idaho Power's Idaho jurisdictional earnings exceeding a 10.5 percent Idaho ROE for the applicable year would be allocated 75 percent to benefit Idaho customer rates through an offset in the pension balancing account and 25 percent to Idaho Power.

The settlement stipulation provides that the Idaho ROE thresholds (9.5 percent, 10.0 percent, and 10.5 percent) will be automatically adjusted prospectively in the event the IPUC approves a change to Idaho Power's authorized return on equity as part of a general rate case proceeding seeking a rate change effective prior to January 1, 2015.

• Langley Gulch Power Plant Filings: On March 2, 2012, Idaho Power filed an application with the IPUC requesting an increase in annual Idaho-jurisdiction base rates of $59.9 million, effective July 1, 2012, for recovery of Idaho Power's investment in the Langley Gulch power plant. On March 9, 2012, Idaho Power filed an application with the OPUC requesting an annual increase in Oregon-jurisdiction revenues of $3.0 million, for inclusion of the Langley Gulch power plant in Idaho Power's rate base, also with an effective date of July 1, 2012. An April 17, 2012 IPUC order approved Idaho Power's request to process the application under modified procedure, which increases the likelihood, but does not assure, that the plant will be included in Idaho rate base by the requested date. By contrast, on March 26, 2012, the OPUC issued an order suspending Idaho Power's Oregon tariff filing for a period of up to nine months. As a result, the inclusion of costs associated with the Langley Gulch power plant in Oregon rate base by July 1, 2012 is unlikely. A scheduling order issued by the OPUC provides for an OPUC decision by January 2013 and inclusion in rates by March 2013.

• Power Cost Adjustment Filing - Idaho: On April 13, 2012, Idaho Power made its annual Idaho PCA filing with the IPUC, requesting a $43 million increase to Idaho PCA rates, effective for the period from June 1, 2012 to May 31, 2013. The requested increase reflects increased projected power supply costs relative to the prior PCA year, due largely to an increase in purchases of higher-cost, intermittent power under PURPA power purchase contracts with CSPP facilities. Previous PCA orders have resulted in a $40.4 million Idaho PCA rate decrease, effective June 1, 2011, and a $146.9 million Idaho PCA rate decrease, effective June 1, 2010. These PCA rate decreases were offset by increases in power supply costs in base rates and deferrals and amortization under the Idaho PCA mechanism, resulting in a relatively small impact on earnings.

• Idaho Fixed Cost Adjustment Filing: The fixed cost adjustment (FCA) 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.  While the FCA was initially a pilot program, in March 2012 the IPUC issued an order approving the FCA as permanent, but directed Idaho Power to file with the IPUC a proposal to adjust the FCA to address the exclusion of changes in load not related to energy efficiency programs. Also in March 2012, Idaho Power filed an application with the IPUC requesting an order authorizing Idaho Power to increase the annual FCA collection to $10.3 million, a $1.2 million increase in FCA rates, for the period from June 1, 2012 to May 31, 2013.

• Idaho Non-AMI Meter Depreciation:On April 27, 2012, the IPUC approved Idaho Power's February 15, 2012 application requesting approval of a $10.6 million decrease in rates for specified customer classes, effective June 1, 2012, as a result of the removal of accelerated depreciation expense associated with non-AMI metering equipment.

• Oregon General Rate Case Settlement: On February 23, 2012, the OPUC approved a settlement stipulation in Idaho Power's Oregon general rate case. The settlement stipulation provides for a $1.8 million base rate increase, a return on equity of 9.9 percent, and an overall rate of return of 7.757 percent in the Oregon jurisdiction. New rates in conformity with the settlement stipulation went into effect on March 1, 2012. The OPUC will conduct a second phase of the proceedings to address the prudence of Idaho Power's pollution control investments at the Jim Bridger plant.

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The table below includes a list of certain notable regulatory proceedings completed or in process during 2012, including certain matters discussed above, in Note 3 - "Regulatory Matters" to the condensed consolidated financial statements included in this report, or in IDACORP's and Idaho Power's Annual Report on Form 10-K for the year ended December 31, 2011.

Description	Docket Status	Actual / Estimated Effective Date	Estimated Annualized Revenue Impact (millions)
Idaho:
2011 general rate case settlement	In effect	1/1/2012		$34.0
Depreciation rate for non-AMI meters	Approved	6/1/2012	(10.6		)
Power cost adjustment	In process under modified procedure	6/1/2012	43.0
Depreciation update (other than non-AMI meters and Boardman plant)	In process under modified procedure	6/1/2012	2.7
Boardman power plant cost recovery	In process under modified procedure	6/1/2012	1.6
Fixed cost adjustment	In process under modified procedure	6/1/2012	1.2
Revenue sharing pursuant to January 2010 settlement agreement	In process under modified procedure	6/1/2012	(27.1		)
Langley Gulch power plant	In process under modified procedure	7/1/2012	59.9
Oregon:
Oregon general rate case settlement	In effect	3/1/2012	1.8
Oregon annual power cost update	In process	6/1/2012	1.8
Langley Gulch power plant	In process	(1)	3.0

⁽¹⁾ Idaho Power's filing requested a 7/1/2012 effective date. As noted above, based on the status of this filing and a procedural schedule established by the IPUC, the timing of inclusion of costs associated with the Langley Gulch power plant in Oregon rate base is uncertain.

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 CSPP 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 it cannot use or does not need to serve loads at above wholesale market prices.  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 addition to increasing power purchase costs, integration of intermittent, non-dispatchable resources into Idaho Power's portfolio creates a number of complex operational risks and challenges.

Idaho Power remains engaged in proceedings at the IPUC relating to the determination of appropriate power purchase prices and other terms of PURPA power purchase agreements. The IPUC has established a timeline for various informational filings by all parties to the PURPA proceedings, with hearings scheduled for August 2012. On January 31, 2012, Idaho Power submitted written testimony in the PURPA proceedings, in support of its request that the IPUC (a) change the methodology used to establish power purchase prices for PURPA projects, (b) reduce the maximum authorized PURPA power purchase agreement term from the existing 20 years to a maximum of five years, and (c) authorize a curtailment strategy that would allow Idaho Power to optimize use of its cost-effective resources. On March 12, 2012, Idaho Power filed an application with the IPUC seeking a temporary stay of its obligation to enter into new PURPA power purchase agreements. While the IPUC denied Idaho Power's request for a stay in a March 22, 2012 order, the IPUC's order provided that the PURPA pricing methodologies in effect as of that date do not produce rates that are just and reasonable or in the public interest. As a result, the IPUC's order further provided that the IPUC would individually evaluate all contracts for PURPA projects over 100 kW entered into by Idaho Power and presented to the IPUC for approval, noting that FERC regulations require that the purchase price be just and reasonable to customers and in the public interest.

Settlement With Large Industrial Customer

In March 2009, the IPUC approved a September 2008 electric service agreement between Idaho Power and Hoku Materials, Inc. (Hoku), to provide electric service to Hoku’s polysilicon production facility being constructed in Pocatello, Idaho.  The initial term of the agreement was four years beginning December 1, 2009, with a maximum demand obligation during the

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initial term of 82 MW.  Hoku was still not taking significant service as of December 2011. In December 2011, Idaho Power sent to Hoku a notice of termination of service pursuant to IPUC rules to terminate service as a result of an overdue invoice for electric service. On January 9, 2012, Hoku filed a petition with the IPUC alleging that its contract with Idaho Power was contrary to the public interest and requested that the IPUC reform the contract and sought reparations for previously paid amounts under the electric service agreement.

On February 17, 2012, Idaho Power, Hoku, and the IPUC Staff filed with the IPUC a settlement stipulation to amend the electric service agreement, and on March 15, 2012, the IPUC approved the stipulation. The stipulation revised the contract to provide for a minimum monthly charge of $0.8 million (compared to the prior minimum monthly charge of approximately $2 million) from January 2012 to July 2013 and the establishment of a balancing mechanism that will track and accrue (up to a maximum balance of approximately $16.5 million) on a monthly basis the difference between (a) the first block minimum energy charges (excluding demand charges) under the existing agreement and (b) the modified minimum billed energy charge (excluding demand charges) under the settlement stipulation. In January 2014, Idaho Power will begin invoicing Hoku for, in addition to applicable demand and energy charges, recovery of the deferred amount over a 12-month period, one-twelfth per month. Further, the stipulation provides that Hoku will pay to Idaho Power $2.0 million upon IPUC approval of the stipulation out of existing funds on deposit with Idaho Power, and $0.1 million per month in cash for 18 months commencing with its January 2012 invoice. The stipulation also extends the term of the electric service agreement through December 1, 2014. During the final year of the agreement, Hoku will pay embedded-cost based rates for service. Hoku agrees in the stipulation to cap its monthly power demand during the January 2012 to July 2013 deferral period to 20 MW, with the option to increase usage to 82 MW following a notice period and payment of applicable deposits. In the event Hoku uses more than 20 MW of energy in any given month, Hoku will be required to pay the minimum billed energy charge amounts set forth in the prior electric service agreement.

Assuming Hoku's performance in accordance with the terms of the revised agreement, Idaho Power expects to recognize approximately $5.4 million in full year 2012 revenues associated with the portion of contract payments that are not affected by the Idaho PCA. Idaho Power expects that other payments made by Hoku under the contract, which are affected by the Idaho PCA, will have a $0.3 million pre-tax impact on earnings for full year 2012.

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 $149 million and $5 million for the HCC and Swan Falls projects, respectively, were included in construction work in progress at March 31, 2012. As of the date of this report, the IPUC authorizes Idaho Power to include in its Idaho jurisdiction rates approximately $6.5 million annually ($10.7 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.

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 environmental legislation relates to, among other items, climate change, greenhouse gas emissions and air quality, renewable energy standards, mercury and other emissions, hazardous wastes, and polychlorinated biphenyls.  In addition to imposing continuing compliance obligations and associated costs, 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 U.S. Environmental Protection Agency (EPA) and state and local agencies. All such laws and regulations are subject to a range of interpretation, which may ultimately need to be resolved by the courts.  Current and future 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 result in Idaho Power discontinuing operation of certain power generation plants.  Environmental regulation continues to impact Idaho Power's operations due to the substantial 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 water discharged through turbines 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-fired combustion turbine power plants that are subject to a broad range of environmental requirements, including air quality regulation.  These regulations could

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affect IDACORP's and Idaho Power's results of operations and financial condition if the costs associated with these environmental requirements cannot be fully recovered in rates on a timely basis or at all.

Included below is a summary of notable developments in environmental, climate change, sustainability, and related issues impacting Idaho Power 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, 2011.

Final Utility MACT Rule: 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 finalize a standard to control mercury emissions from coal-fired power plants by November 2011.  In March 2011, the EPA released the proposed Utility Maximum Achievable Control Technology rule 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. Both the proposed HAPs regulation and the associated NSPS revisions were finalized on February 16, 2012. The regulation imposes maximum achievable control technology and NSPS on all coal-fired EGUs and replaces the former Clean Air Mercury Rule. Specifically, the regulation sets numeric emission limitations on coal-fired EGUs for total particulate matter (a surrogate for non-mercury HAPs), hydrogen chloride, and mercury. In addition, the regulation imposes 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 final rule, the EPA has established amended emission limitations for particulate matter, sulfur dioxide, and nitrogen oxides. Mercury continuous emission monitoring systems have been installed on all of the coal-fired units at the Jim Bridger, Boardman, and Valmy generating plants.  However, Idaho Power is reviewing the final rule and is in the process of determining how these regulations will impact the Bridger, Boardman, and Valmy generating plants, including whether those coal-fired plants can meet the HAPs limits with current and planned control technologies.

National Ambient Air Quality Standards (NAAQS): In February 2010, the EPA revised the NAAQS for NO₂, establishing a one-hour standard at a level of 100 parts per billion. In connection with the new NAAQS, in February 2012 the EPA issued a final rule designating all of the counties in Idaho, Nevada, Oregon, and Wyoming where Idaho Power owns or has an interest in a natural gas or coal-fired power plant as “unclassifiable/attainment” for NO₂. The EPA indicated that it will review the designations between 2012 and 2015, during or after which the EPA may formally designate the counties as attainment or non-attainment for NO₂. A designation of non-attainment may increase the likelihood that Idaho Power would be required to install costly pollution control technology at one or more of its plants. As the designations have not yet been finalized, as of the date of this report Idaho Power is unable to predict the impact of the NAAQS on its operations. However, the costs of installation and implementation of any additional pollution reduction technology could be substantial.

NSPS for Greenhouse Gas Emissions for New EGUs: In March 2012, the EPA proposed NSPS limiting CO₂ emissions from new fossil fuel-fired power plants. The proposed requirements, which are limited to new sources, would require new fossil fuel-fired EGUs greater than 25 MW to meet an output-based standard of 1,000 pounds of CO₂ per MWh. The EPA did not propose standards of performance for existing EGUs whose CO₂ emissions increase as a result of installation of pollution controls for conventional pollutants. While Idaho Power does not expect the new NSPS to impact its existing generation facilities, the new rules, if enacted, would impact the cost effectiveness of developing new EGUs. The Langley Gulch natural gas-fired power plant was designed to meet the new NSPS.

CSPP Contracts: Idaho Power purchases wind power from both CSPP and non-CSPP facilities, including its largest non-CSPP wind power project -- the Elkhorn Valley wind project with a 101 MW nameplate capacity. As of March 31, 2012, Idaho Power had contracts to purchase energy from 20 on-line CSPP wind power projects with a combined nameplate rating of 398 MW.  At that date, Idaho Power also had signed, public utility commission-approved contracts to purchase energy from an additional 13 CSPP wind projects with a combined nameplate rating of 294 MW.  These projects are expected to be on-line between mid-2012 and the end of 2013. 

In addition to its power purchase arrangements with wind power generators, Idaho Power has contracts for the purchase of power from other generation sources, such as biomass, solar, and small hydroelectric projects. As of March 31, 2012, Idaho Power had 20 MW of solar power generation under contract for purchase.

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As of March 31, 2012, Idaho Power had the number and nameplate capacity of signed CSPP-related agreements with terms ranging from one to 35 years set forth in the table below. 

Status	Number of CSPP Contracts	Nameplate Capacity (MW)
On-line as of March 31, 2012	96	606
Contracted and projected to come on-line by year-end 2014	23	383
Total	119	989

The majority of new facilities set forth in the table will be wind resources that will generate on an intermittent basis. During the first quarter of 2012, Idaho Power purchased approximately 416,000 MWh of power from CSPP facilities at a cost of $23.8 million, resulting in a blended price of approximately $57 per MWh.

REC Sales: Pursuant to an IPUC order, Idaho Power is selling its near-term RECs and returning to Idaho customers their share (shared 95 percent with customers in the Idaho jurisdiction) 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 the REC Management Plan, Idaho Power is selling its near-term RECs while continuing to acquire and hold long-term contractual rights to own RECs for use in meeting future renewable portfolio standards.  For the three months endedMarch 31, 2012, Idaho Power's REC sales totaled approximately $1 million. Ordinarily, Idaho Power does not receive the RECs associated with PURPA projects. However, Idaho Power is engaged in proceedings at the IPUC relating to ownership of RECs associated with PURPA projects.

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 IDACORP's and Idaho Power's Annual Report on Form 10-K for the year ended December 31, 2011.

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, 2012.

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.

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Variable Rate Debt:  As of March 31, 2012, IDACORP and Idaho Power had $87.1 million and $25.6 million, respectively, in net floating-rate debt. The fair market value of this debt was $87.1 million and $25.6 million, respectively. Assuming no change in financial structure, if variable interest rates were to average one percentage-point higher than the average rate on March 31, 2012, interest rate expense would increase and pre-tax earnings would decrease by approximately $0.9 million for IDACORP and $0.3 million for Idaho Power.

Fixed Rate Debt:  As of March 31, 2012, IDACORP and Idaho Power each had $1.5 billion in fixed rate debt, with a fair market value equal to $1.7 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 $5 million for both IDACORP and Idaho Power if market interest rates were to decline by one percentage point from their March 31, 2012 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, 2012 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, 2011.  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, 2012, Idaho Power had posted no performance 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 requests by its wholesale counterparties to post 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, 2012, the approximate amount of collateral that could be requested upon a downgrade to below investment grade is approximately $11 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, 2012 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, 2011.

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 security investments at Idaho Power. IDACORP’s and Idaho Power’s equity price risk as of March 31, 2012 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, 2011.

58

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, 2012, 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, 2012, 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, 2012, 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

Refer to Note 9 - “Contingencies” to the condensed consolidated financial statements included in this report for information regarding certain legal and administrative proceedings in which the registrants are involved.

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, 2011, 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. In addition to those risk factors, also see "Forward-Looking Statements" in this report for additional factors that could have a significant impact on IDACORP's or Idaho Power's operations, results of operations, or financial condition and could cause actual results to differ materially from those anticipated in forward-looking statements.

59

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, 2012	14,646	$	41.80	—	—
February 1 - February 29, 2012	35,316	41.05		—	—
March 1 - March 31, 2012	—	—		—	—
Total	49,962	$	41.27	—	—

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

ITEM 4.  MINE SAFETY DISCLOSURES

Information concerning mine safety violations or other regulatory matters required by Section 1503(a) of the Dodd-Frank Wall Street Reform and Consumer Protection Act and Item 104 of Regulation S-K (17 CFR 229.104) is included in Exhibit 95.1 of this report, which is incorporated herein by reference.

ITEM 5. OTHER INFORMATION

None.

60

ITEM 6.  EXHIBITS

Exhibit No.	Description
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
95.1	Mine Safety Disclosures
101.INS1	XBRL Instance Document
101.SCH1	XBRL Taxonomy Extension Schema Document
101.CAL1	XBRL Taxonomy Extension Calculation Linkbase Document
101.LAB1	XBRL Taxonomy Extension Label Linkbase Document
101.PRE1	XBRL Taxonomy Extension Presentation Linkbase Document
101.DEF1	XBRL Taxonomy Extension Definition Linkbase Document
1   Includes data files for the following materials from the quarterly report on Form 10-Q of IDACORP, Inc. for the quarter ended March 31, 2012, 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.  Also includes data files for the following materials from the quarterly report on Form 10-Q of Idaho Power Company for the quarter ended March 31, 2012, formatted in XBRL: (i) Condensed Consolidated Statements of Income; (ii) Condensed Consolidated Balance Sheets; (iii) Condensed Consolidated Statements of Capitalization; (iv) Condensed Consolidated Statements of Cash Flows; (v) Condensed Consolidated Statements of Comprehensive Income; and (vi) the Notes to Condensed Consolidated Financial Statements tagged as blocks of text. Detailed tags for information in the Notes to Condensed Consolidated Financial Statements are being furnished only by IDACORP, Inc. and not by its subsidiary, Idaho Power Company. 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.

61

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 3, 2012	By:	/s/ J. LaMont Keen
			J. LaMont Keen
			President and Chief Executive Officer
Date:	May 3, 2012	By:	/s/ Darrel T. Anderson
			Darrel T. Anderson
			Executive Vice President - Administrative
			Services and Chief Financial Officer
		IDAHO POWER COMPANY
		(Registrant)
Date:	May 3, 2012	By:	/s/ J. LaMont Keen
			J. LaMont Keen
			Chief Executive Officer
Date:	May 3, 2012	By:	/s/ Darrel T. Anderson
			Darrel T. Anderson
			President and Chief Financial Officer

62

EXHIBIT INDEX

Exhibit No.	Description
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
95.1	Mine Safety
101.INS1	XBRL Instance Document
101.SCH1	XBRL Taxonomy Extension Schema Document
101.CAL1	XBRL Taxonomy Extension Calculation Linkbase Document
101.LAB1	XBRL Taxonomy Extension Label Linkbase Document
101.PRE1	XBRL Taxonomy Extension Presentation Linkbase Document
101.DEF1	XBRL Taxonomy Extension Definition Linkbase Document
1   Includes data files for the following materials from the quarterly report on Form 10-Q of IDACORP, Inc. for the quarter ended March 31, 2012, 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.  Also includes data files for the following materials from the quarterly report on Form 10-Q of Idaho Power Company for the quarter ended March 31, 2012, formatted in XBRL: (i) Condensed Consolidated Statements of Income; (ii) Condensed Consolidated Balance Sheets; (iii) Condensed Consolidated Statements of Capitalization; (iv) Condensed Consolidated Statements of Cash Flows; (v) Condensed Consolidated Statements of Comprehensive Income; and (vi) the Notes to Condensed Consolidated Financial Statements tagged as blocks of text. Detailed tags for information in the Notes to Condensed Consolidated Financial Statements are being furnished only by IDACORP, Inc. and not by its subsidiary, Idaho Power Company. 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.

63

EX-12.1

Exhibit 12.1

IDACORP, Inc.

Consolidated Financial Information

Ratio of Earnings to Fixed Charges and Supplemental Ratio of Earnings to Fixed Charges

(Thousands of Dollars)

	Three months ended March 31,
			Twelve Months Ended
			December 31,
	2012		2011		2010		2009		2008		2007
RATIO OF EARNINGS TO FIXED CHARGES
Earnings, as defined:
Income from continuing operations before income taxes	$	33,151	$	114,729	$	141,729	$	146,737	$	117,614	$	96,003
Adjust for distributed income of equity investees	7,631		2,073		3,522		13,724		5,176		6,064
Fixed charges, as below	21,613		86,758		86,806		79,461		81,172		72,879
Total earnings, as defined	$	62,395	$	203,560	$	232,057	$	239,922	$	203,962	$	174,946
Fixed charges, as defined:
Interest charges1	$	21,154	$	85,097	$	85,840	$	78,457	$	80,282	$	71,946
Rental interest factor	459		1,661		966		1,004		890		933
Total fixed charges, as defined	$	21,613	$	86,758	$	86,806	$	79,461	$	81,172	$	72,879
Ratio of earnings to fixed charges	2.89x		2.35x		2.67x		3.02x		2.51x		2.40x
SUPPLEMENTAL RATIO OF EARNINGS TO FIXED CHARGES
Earnings, as defined:
Income from continuing operations before income taxes	$	33,151	$	114,729	$	141,729	$	146,737	$	117,614	$	96,003
Adjust for distributed income of equity investees	7,631		2,073		3,522		13,724		5,176		6,064
Supplemental fixed charges, as below	21,779		87,544		87,870		80,946		82,962		74,631
Total earnings, as defined	$	62,561	$	204,346	$	233,121	$	241,407	$	205,752	$	176,698
Supplemental fixed charges:
Interest charges1	$	21,154	$	85,097	$	85,840	$	78,457	$	80,282	$	71,946
Rental interest factor	459		1,661		966		1,004		890		933
Supplemental increment to fixed charges2	166		786		1,064		1,485		1,790		1,752
Total supplemental fixed charges	$	21,779	$	87,544	$	87,870	$	80,946	$	82,962	$	74,631
Supplemental ratio of earnings to fixed charges	2.87x		2.33x		2.65x		2.98x		2.48x		2.37x
1 FIN 48 interest is not included in interest charges.
2 Explanation of increment - Interest on the guaranty of American Falls Reservoir District bonds and Milner Dam, Inc. notes which are already included in operation expenses.

EX-12.2

Exhibit 12.2

Idaho Power Company

Consolidated Financial Information

Ratio of Earnings to Fixed Charges and Supplemental Ratio of Earnings to Fixed Charges

(Thousands of Dollars)

	Three months ended March 31,
			Twelve Months Ended
			December 31,
	2012		2011			2010			2009		2008			2007
RATIO OF EARNINGS TO FIXED CHARGES
Earnings, as defined:
Income from continuing operations before income taxes	$	36,134	$	123,351		$	151,347		$	158,080	$	131,715		$	111,965
Adjust for distributed income of equity investees	4,757		(9,018		)	(6,526		)	2,464		(6,772		)	(5,553		)
Fixed charges, as below	21,508		86,249			85,579			78,543		77,568			68,272
Total earnings, as defined	$	62,399	$	200,582		$	230,400		$	239,087	$	202,511		$	174,684
Fixed charges, as defined:
Interest charges1	$	21,059	$	84,626		$	84,651		$	77,580	$	76,711		$	67,386
Rental interest factor	449		1,623			928			963		857			886
Total fixed charges, as defined	$	21,508	$	86,249		$	85,579		$	78,543	$	77,568		$	68,272
Ratio of earnings to fixed charges	2.90x		2.33x			2.69x			3.04x		2.61x			2.56x
SUPPLEMENTAL RATIO OF EARNINGS TO FIXED CHARGES
Earnings, as defined:
Income from continuing operations before income taxes	$	36,134	$	123,351		$	151,347		$	158,080	$	131,715		$	111,965
Adjust for distributed income of equity investees	4,757		(9,018		)	(6,526		)	2,464		(6,772		)	(5,553		)
Supplemental fixed charges, as below	21,674		87,035			86,643			80,028		79,358			70,024
Total earnings, as defined	$	62,565	$	201,368		$	231,464		$	240,572	$	204,301		$	176,436
Supplemental fixed charges:
Interest charges1	$	21,059	$	84,626		$	84,651		$	77,580	$	76,711		$	67,386
Rental interest factor	449		1,623			928			963		857			886
Supplemental increment to fixed charges2	166		786			1,064			1,485		1,790			1,752
Total supplemental fixed charges	$	21,674	$	87,035		$	86,643		$	80,028	$	79,358		$	70,024
Supplemental ratio of earnings to fixed charges	2.89x		2.31x			2.67x			3.01x		2.57x			2.52x
1 FIN 48 interest is not included in interest charges.
2 Explanation of increment - Interest on the guaranty of American Falls Reservoir District bonds and Milner Dam, Inc. notes which are already included in operation expenses.

EX-15.1

Exhibit 15.1

May 3, 2012

IDACORP, Inc.

Idaho Power Company

Boise, Idaho

We have reviewed, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the unaudited interim financial information of IDACORP, Inc. and subsidiaries and Idaho Power Company and subsidiary for the three-month periods ended March 31, 2012 and 2011, as indicated in our reports dated May 3, 2012; because we did not perform audits, we expressed no opinion on that information.

We are aware that our reports referred to above, which are included in your Quarterly Report on Form 10-Q for the quarter ended March 31, 2012, are incorporated by reference in Registration Statement Nos. 333-178124 and 333-178023 on Form S-3 and Registration Statement Nos. 333-65406, 333-125259, 333-143404, and 333-159855 on Form S-8 of IDACORP, Inc. and Registration Statement No. 333-166774 on Form S-3 and Registration Statement No. 333-66496 on Form S-8 of Idaho Power Company.

We also are aware that the aforementioned reports, pursuant to Rule 436(c) under the Securities Act of 1933, are not considered a part of the Registration Statement prepared or certified by an accountant or a report prepared or certified by an accountant within the meaning of Sections 7 and 11 of that Act.

/s/ DELOITTE & TOUCHE LLP

Boise, Idaho

EX-31.1

Exhibit 31.1

CERTIFICATION

I, J. LaMont Keen, certify that:

1. I have reviewed this Quarterly Report on Form 10-Q of IDACORP, Inc.;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant's other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

c) Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d) Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and

5. The registrant's other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalent functions):

a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and

b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.

Date:	May 3, 2012	By:	/s / J. LaMont Keen
			J. LaMont Keen
			President and Chief Executive Officer

EX-31.2

Exhibit 31.2

CERTIFICATION

I, Darrel T. Anderson, certify that:

1. I have reviewed this Quarterly Report on Form 10-Q of IDACORP, Inc.;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant's other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

c) Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d) Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and

5. The registrant's other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalent functions):

a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and

b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.

Date:	May 3, 2012	By:	/s / Darrel T. Anderson
			Darrel T. Anderson
			Executive Vice President - Administrative Services
			and Chief Financial Officer

EX-31.3

Exhibit 31.3

CERTIFICATION

I, J. LaMont Keen, certify that:

1. I have reviewed this Quarterly Report on Form 10-Q of Idaho Power Company;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant's other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

c) Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d) Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and

5. The registrant's other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalent functions):

a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and

b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.

Date:	May 3, 2012	By:	/s/ J. LaMont Keen
			J. LaMont Keen
			Chief Executive Officer

EX-31.4

Exhibit 31.4

CERTIFICATION

I, Darrel T. Anderson, certify that:

1. I have reviewed this Quarterly Report on Form 10-Q of Idaho Power Company;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant's other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

c) Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d) Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and

5. The registrant's other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalent functions):

a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and

b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.

Date:	May 3, 2012	By:	/s/ Darrel T. Anderson
			Darrel T. Anderson
			President and Chief Financial Officer

EX-32.1

Exhibit 32.1

CERTIFICATION PURSUANT TO

18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO

SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

In connection with the Quarterly Report of IDACORP, Inc. (the "Company") on Form 10-Q for the quarter ended March 31, 2012 (the "Report"), I, J. LaMont Keen, President and Chief Executive Officer of the Company, certify that:

(1) The Report fully complies with the requirements of Section 13(a) of the Securities Exchange Act of 1934; and

(2) The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

/s/ J. LaMont Keen

J. LaMont Keen

President and Chief Executive Officer

May 3, 2012

EX-32.2

Exhibit 32.2

CERTIFICATION PURSUANT TO

18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO

SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

In connection with the Quarterly Report of IDACORP, Inc. (the "Company") on Form 10-Q for the quarter ended March 31, 2012 (the "Report"), I, Darrel T. Anderson, Executive Vice President - Administrative Services and Chief Financial Officer of the Company, certify that:

(1) The Report fully complies with the requirements of Section 13(a) of the Securities Exchange Act of 1934; and

(2) The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

/s/ Darrel T. Anderson

Darrel T. Anderson

Executive Vice President - Administrative Services

and Chief Financial Officer

May 3, 2012

EX-32.3

Exhibit 32.3

CERTIFICATION PURSUANT TO

18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO

SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

In connection with the Quarterly Report of Idaho Power Company (the "Company") on Form 10-Q for the quarter ended March 31, 2012 (the "Report"), I, J. LaMont Keen, Chief Executive Officer of the Company, certify that:

(1) The Report fully complies with the requirements of Section 13(a) of the Securities Exchange Act of 1934; and

(2) The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

/s/ J. LaMont Keen

J. LaMont Keen

Chief Executive Officer

May 3, 2012

EX-32.4

Exhibit 32.4

CERTIFICATION PURSUANT TO

18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO

SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

In connection with the Quarterly Report of Idaho Power Company (the "Company") on Form 10-Q for the quarter ended March 31, 2012 (the "Report"), I, Darrel T. Anderson, President and Chief Financial Officer of the Company, certify that:

(1) The Report fully complies with the requirements of Section 13(a) of the Securities Exchange Act of 1934; and

(2) The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

/s/ Darrel T. Anderson

Darrel T. Anderson

President and Chief Financial Officer

May 3, 2012

EX-95.1

Exhibit 95.1

Mine Safety Disclosures Required by the Dodd-Frank Wall Street Reform and Consumer Protection Act

The following disclosure is provided pursuant to Section 1503(a) of the Dodd-Frank Wall Street Reform and Consumer Protection Act, which requires certain disclosures by companies that operate mines regulated under the Federal Mine Safety and Health Act of 1977 (Mine Safety Act).

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 is comprised of the Bridger surface and underground operations. 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. Operation of the Mine is regulated by the Mine Safety and Health Administration (MSHA) under the 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.  The severity and assessment of penalties may be reduced or, in some cases, dismissed through the contest and appeal process. Amounts are reported regardless of whether BCC has challenged or appealed the matter.

The table below summarizes the 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 data for the Mine, during the three month period ended March 31, 2012. Legal actions pending before the Federal Mine Safety and Health Review Commission (FMSHRC) are as of March 31, 2012. Due to timing and other factors, the data may not agree with the mine data retrieval system maintained by MSHA at www.msha.gov.

			Three-month period ended March 31, 2012 (unaudited)
			Surface Mine (MSHA ID No. 4800677)		Underground Mine (MSHA ID No. 4801646)
Mine Safety Act Data:
	Section 104(a) Significant & Substantial Citations (1)		—		11
	Section 104(b) Orders (2)		—		—
	Section 104(d) Citations & Orders (3)		—		2
	Section 107(a) Imminent Danger Orders (4)		—		1
	Section 110(b)(2) Flagrant Violations (5)		—		—
	Received Notice of Pattern of Violations Under Section 104(e) (Yes/No)		No		No
	Received Notice of Potential to Have Pattern Under Section 104(e) (Yes/No)		No		No
Total Dollar Value of Proposed MSHA Assessments During the Period (in thousands)		$	—	$	17
Legal Actions Pending as of Last Day of Period (6)			1		16
Legal Actions Instituted During Period			—		4
Legal Actions Resolved During Period			3		5
Number of Mining-Related Fatalities			0		0
_______________
(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 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. The imminent danger order listed has been vacated.
(5)  Represents the total number of flagrant violations identified under Section 110(b)(2) of the Mine Safety Act.
(6)   All pending legal actions for the surface and underground mine are categorized as contests of proposed civil penalties for violations contained in a citation or order under Subpart C of the FMSHRC Procedural Rules.

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COMMON STOCK: Level 4 (Details) (USD $) In Millions, except Share data, unless otherwise specified	3 Months Ended
	Mar. 31, 2012
Shareholders' equity
Aggregate shares of common stock issued pursuant to IDACORP's share plans	128,088
Available shares remaining under current sales agency agreement	3,000,000
Shares issued under sales agency agreement during the period	128,088
Maximum leverage ratio requirement	0.65
Leverage ratio	0.48
Amount dividends were limited to based on covenant restrictions	$ 836
Continuous Equity Program
Shareholders' equity
Aggregate shares of common stock issued pursuant to IDACORP's share plans	0
Shares issued under sales agency agreement during the period	0
Idaho Power Company
Shareholders' equity
Maximum leverage ratio requirement	0.65
Leverage ratio	0.49
Amount dividends were limited to based on covenant restrictions	$ 741
Percentage of capital threshold below which Idaho Power will not pay dividends to IDACORP	0.35
Shares of preferred stock outstanding	0

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SEGMENT INFORMATION: Level 4 (Details) (USD $) In Thousands, unless otherwise specified	3 Months Ended
	Mar. 31, 2012	Mar. 31, 2011	Dec. 31, 2011
Segment Reporting Information
Revenues	$ 240,483	$ 251,062
Revenues	241,140	251,494
Income (loss) attributable to IDACORP, Inc.	24,818	29,488
Income (loss) attributable to IDACORP, Inc.	24,930	29,740
Total assets	4,990,621		4,960,609
Idaho Power Company [Member]
Segment Reporting Information
Revenues	240,483	251,062
Income (loss) attributable to IDACORP, Inc.	25,819	29,848
Total assets	4,885,800		4,856,839
Bridger Coal Company
Segment Reporting Information
IERCo's ownership percentage in Bridger Coal Company	33.00%
Idaho Power Company | Idaho Power Company [Member]
Segment Reporting Information
Revenues	240,483	251,062
Income (loss) attributable to IDACORP, Inc.	25,819	29,848
Total assets	4,885,800
All Other
Segment Reporting Information
Revenues	657	432
Income (loss) attributable to IDACORP, Inc.	(889)	(108)
Total assets	120,997
Eliminations
Segment Reporting Information
Revenues	0	0
Income (loss) attributable to IDACORP, Inc.	0	0
Total assets	$ (16,176)

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SEGMENT INFORMATION: Level 3 (Tables)

3 Months Ended

Mar. 31, 2012

Segment Information [Abstract]

Schedule of Segment Reporting Information, by Segment [Table Text Block]

The table below 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, 2012:
Revenues	$	240,483	$	657		$	—		$	241,140
Net income (loss) attributable to IDACORP, Inc.	25,819		(889		)	—			24,930
Total assets as of March 31, 2012	4,885,800		120,997			(16,176		)	4,990,621
Three months ended March 31, 2011:
Revenues	$	251,062	$	432		$	—		$	251,494
Net income (loss) attributable to IDACORP, Inc.	29,848		(108		)	—			29,740

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SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES: Organization, Consolidation, Presentation, and Significant Accounting Policies (Policies)

3 Months Ended

Mar. 31, 2012

Organization, Consolidation and Presentation of Financial Statements and Significant Accounting Policies [Abstract]

Nature of Operations

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's utility operations are regulated primarily 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.

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.  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 $20 million of assets, primarily a hydroelectric plant, and approximately $15 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 was $97 million at March 31, 2012, and Idaho Power's maximum exposure to loss is the carrying value, plus any additional future contributions to BCC and a $63 million guarantee for mine reclamation costs, which is discussed further in Note 8.

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 $60 million at March 31, 2012.

Regulatory Assets and Liabilities, Recognition Criteria

IDACORP's and Idaho Power's financial statements reflect the effects of the different ratemaking principles followed by the jurisdictions regulating Idaho Power.  The application of accounting principles related to regulated operations sometimes results in Idaho Power recording expenses and revenues in a different period than when an unregulated enterprise would otherwise record expenses and revenues.  In these instances, the amounts are deferred as regulatory assets or regulatory liabilities on the balance sheet and recorded on the income statement when recovered or returned in rates.  Additionally, regulators can impose regulatory liabilities upon a regulated company for amounts previously collected from customers and for amounts that are expected to be refunded to customers.  The effects of applying these regulatory accounting principles to Idaho Power's operations are discussed in more detail in Note 3.

Comparability of Prior Year Financial Data

In the opinion of management of IDACORP and Idaho Power, the accompanying unaudited condensed consolidated financial statements contain all adjustments necessary to present fairly each company's consolidated financial position as of March 31, 2012, consolidated results of operations and cash flows for the three months endedMarch 31, 2012 and 2011.  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, 2011.  The results of operations for the interim period 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 the 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

Income Tax, Policy

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 interim 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.

Available-for-sale 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.

Use of derivatives

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.

Derivatives not designated as hedges

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 qualify for the normal purchases and normal sales exception.

All of Idaho Power's derivative instruments have been entered into for the purpose of economically hedging forecasted purchases and sales, though none of these instruments have been designated as cash flow hedges under derivative accounting guidance. Idaho Power offsets fair value amounts recognized on its balance sheet related to derivative instruments executed with the same counterparty under the same master netting agreement.

Reporting of derivative activity

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 are recorded in other operations and maintenance expense.

Credit risk and credit-contingent features

Credit Risk

At March 31, 2012, 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.

Fair value of financial instruments

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.

An item recorded at fair value is reclassified between levels when changes in the nature of valuation inputs cause the item to no longer meet the criteria for the level in which it was previously categorized. There have been no material reclassifications between levels during the current period.

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 location basis, 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. Notes receivable are related to Ida-West and are valued based on unobservable inputs, including discounted cash flows, which are partially based on forecasted hydroelectric conditions. Long-term debt is not traded on an exchange and is valued using quoted rates for similar debt in active markets.

Segment reporting

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 in the table below.  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.

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BENEFIT PLANS: Level 4 (Details) (USD $)	3 Months Ended
	Mar. 31, 2012		Mar. 31, 2011
Defined Benefit Plan Disclosure
Net periodic benefit cost recognized for financial reporting	$ 7,673,000		$ 4,553,000
Pension Plan
Defined Benefit Plan Disclosure
Service cost	6,441,000		5,165,000
Interest cost	7,892,000		7,551,000
Expected return on plan assets	(7,712,000)		(7,951,000)
Amortization of transition obligation	0		0
Amortization of prior service cost	87,000		130,000
Amortization of net loss	3,463,000		2,094,000
Net periodic benefit cost	10,171,000		6,989,000
Costs not recognized due to the effects of regulation	(5,389,000)	[1]	(5,260,000)	[1]
Net periodic benefit cost recognized for financial reporting	4,782,000	[1]	1,729,000	[1]
Contributions made to the defined benefit pension plan	34,000,000
Senior Management Security Plan
Defined Benefit Plan Disclosure
Service cost	538,000		488,000
Interest cost	805,000		773,000
Expected return on plan assets	0		0
Amortization of transition obligation	0		0
Amortization of prior service cost	53,000		61,000
Amortization of net loss	382,000		323,000
Net periodic benefit cost	1,778,000		1,645,000
Costs not recognized due to the effects of regulation	0	[1]	0	[1]
Net periodic benefit cost recognized for financial reporting	1,778,000	[1]	1,645,000	[1]
Postretirement Benefits
Defined Benefit Plan Disclosure
Service cost	351,000		372,000
Interest cost	818,000		893,000
Expected return on plan assets	(604,000)		(667,000)
Amortization of transition obligation	510,000		510,000
Amortization of prior service cost	(105,000)		(99,000)
Amortization of net loss	143,000		171,000
Net periodic benefit cost	1,113,000		1,180,000
Costs not recognized due to the effects of regulation	0	[1]	0	[1]
Net periodic benefit cost recognized for financial reporting	$ 1,113,000	[1]	$ 1,180,000	[1]

[1] Net periodic benefit costs for the pension plan are recognized based upon the authorization of each regulatory jurisdiction Idaho Power operates within. Under IPUC order, income statement recognition of pension plan costs has been deferred until costs are recovered through rates.

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LONG-TERM DEBT: Level 4 (Details) (USD $)	Apr. 13, 2012	Mar. 31, 2012	Dec. 31, 2011
4.75% Series due 2012
Debt Instrument
Debt Instrument, Interest Rate, Stated Percentage		4.75%
IDACORP
Debt Instrument
Amount remaining on self registration		$ 539,000,000
Idaho Power Company
Debt Instrument
Amount of first mortgage bonds and debt securities registered with the SEC		500,000,000
Amount remaining on self registration	150,000,000	300,000,000
First mortgage bonds		1,295,000,000	1,195,000,000
Idaho Power Company | 4.75% Series due 2012
Debt Instrument
Debt Instrument, Interest Rate, Stated Percentage		4.75%
First mortgage bonds		100,000,000	100,000,000
Idaho Power Company | 2.95% Series due 2022
Debt Instrument
Debt Instrument, Face Amount	75,000,000
Debt Instrument, Interest Rate, Stated Percentage	2.95%
Idaho Power Company | 4.30% Series due 2042
Debt Instrument
Debt Instrument, Face Amount	$ 75,000,000
Debt Instrument, Interest Rate, Stated Percentage	4.30%

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Condensed Consolidated Statements of Equity (Parenthetical) (USD $)	3 Months Ended
	Mar. 31, 2012	Mar. 31, 2011
Common stock dividends, per share	$ 0.33	$ 0.30

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INVESTMENTS IN DEBT AND EQUITY SECURITIES: Level 4 (Details) (USD $)	3 Months Ended		12 Months Ended
	Mar. 31, 2012	Mar. 31, 2011	Dec. 31, 2011
Summary of investments in debt and equity securities
Available-for-sale Securities, Gross Unrealized Gain	$ 6,455,000		$ 4,220,000
Available-for-sale Securities, Gross Unrealized Loss	0		1,000
Available-for-sale Securities, Fair Value	26,687,000		22,205,000
Number of securities in an unrealized loss position (whole numbers)	0		1
Proceeds from sales	0	0
Other than Temporary Impairment Recognized			$ 0

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BENEFIT PLANS: Level 3 (Tables)

3 Months Ended

Mar. 31, 2012

Benefit plans [Abstract]

Schedule of Defined Benefit Plans Disclosures [Table Text Block]

The table below 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
	2012			2011			2012		2011		2012			2011
Service cost	$	6,441		$	5,165		$	538	$	488	$	351		$	372
Interest cost	7,892			7,551			805		773		818			893
Expected return on plan assets	(7,712		)	(7,951		)	—		—		(604		)	(667		)
Amortization of transition obligation	—			—			—		—		510			510
Amortization of prior service cost	87			130			53		61		(105		)	(99		)
Amortization of net loss	3,463			2,094			382		323		143			171
Net periodic benefit cost	10,171			6,989			1,778		1,645		1,113			1,180
Costs not recognized due to the effects of regulation (1)	(5,389		)	(5,260		)	—		—		—			—
Net periodic benefit cost recognized for financial reporting (1)	$	4,782		$	1,729		$	1,778	$	1,645	$	1,113		$	1,180

⁽¹⁾  Net periodic benefit costs for the pension plan are recognized based upon the authorization of each regulatory jurisdiction Idaho Power operates within. Under IPUC order, income statement recognition of pension plan costs has been deferred until costs are recovered through rates.

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EARNINGS PER SHARE: Level 3 (Tables)

3 Months Ended

Mar. 31, 2012

Earnings Per Share, Basic and Diluted [Abstract]

Schedule of Earnings Per Share, Diluted, by Common Class, Including Two Class Method [Table Text Block]

The table below presents the computation of IDACORP’s basic and diluted earnings per share (EPS) for the three months endedMarch 31, 2012 and 2011 (in thousands, except for per share amounts).

	Three months ended March 31,
	2012		2011
Numerator:
Net income attributable to IDACORP, Inc.	$	24,930	$	29,740
Denominator:
Weighted-average common shares outstanding - basic	49,860		49,290
Effect of dilutive securities:
Options	5		14
Restricted Stock	40		52
Weighted-average common shares outstanding - diluted	49,905		49,356
Basic earnings per share	$	0.50	$	0.60
Diluted earnings per share	$	0.50	$	0.60

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DERIVATIVE FINANCIAL INSTRUMENTS: Level 4 (Details) (USD $)			3 Months Ended
	Mar. 31, 2012	Dec. 31, 2011	Mar. 31, 2012 Financial swaps Off-system sales		Mar. 31, 2011 Financial swaps Off-system sales		Mar. 31, 2012 Financial swaps Purchased power		Mar. 31, 2011 Financial swaps Purchased power		Mar. 31, 2012 Financial swaps Fuel Expense		Mar. 31, 2011 Financial swaps Fuel Expense		Mar. 31, 2012 Financial swaps Other operating and maintenance		Mar. 31, 2011 Financial swaps Other operating and maintenance		Mar. 31, 2012 Financial swaps Other current assets	Dec. 31, 2011 Financial swaps Other current assets	Mar. 31, 2012 Financial swaps Other current liabilities	Dec. 31, 2011 Financial swaps Other current liabilities	Mar. 31, 2012 Financial swaps Other liabilities	Dec. 31, 2011 Financial swaps Other liabilities	Mar. 31, 2012 Financial swaps Other assets	Dec. 31, 2011 Financial swaps Other assets	Mar. 31, 2012 Forward contracts Other current assets	Dec. 31, 2011 Forward contracts Other current assets	Mar. 31, 2012 Forward contracts Other current liabilities	Dec. 31, 2011 Forward contracts Other current liabilities	Mar. 31, 2012 Forward contracts Other assets	Mar. 31, 2012 Electricity purchases MWh	Mar. 31, 2011 Electricity purchases MWh	Mar. 31, 2012 Electricity sales MWh	Mar. 31, 2011 Electricity sales MWh	Mar. 31, 2012 Natural gas purchases MMBTU	Mar. 31, 2011 Natural gas purchases MMBTU	Mar. 31, 2012 Natural gas sales MMBTU	Mar. 31, 2011 Natural gas sales MMBTU	Mar. 31, 2012 Diesel purchases Gallon	Mar. 31, 2011 Diesel purchases Gallon
Derivative
Derivative, Nonmonetary Notional Amount																																256,200	486,000	1,417,270	501,250	10,082,392	1,867,316	913,379	0	807,978	804,146
Fair Value
Derivative Asset, Fair Value, Gross Asset																			$ 6,374,000	$ 4,361,000					$ 13,000	$ 359,000	$ 31,000	$ 70,000			$ 248,000
Derivative Asset, Fair Value, Gross Liability																					5,379,000	1,526,000	76,000						116,000
Derivative Asset, Fair Value, Net	12,237,000	6,316,000
Derivative Liability, Fair Value, Gross Asset																			1,444,000	1,036,000
Derivative Liability, Fair Value, Gross Liability																					9,740,000	4,755,000	385,000	108,000					2,256,000	1,370,000
Derivative Liability, Fair Value, Net	13,825,000	7,269,000
Derivatives in a net liability position	14,000,000
Collateral Already Posted, Aggregate Fair Value	0
Additional Collateral, Aggregate Fair Value	7,300,000
Derivative Instruments, Gain (Loss)
Derivative Instruments, Gain Recognized in Income			4,439,000	[1]	6,721,000	[1]
Derivative Instruments, Loss Recognized in Income							$ (993,000)	[1]	$ (167,000)	[1]	$ (84,000)	[1]	$ 0	[1]	$ (45,000)	[1]	$ 0	[1]

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

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INVESTMENTS IN DEBT AND EQUITY SECURITIES: Level 3 (Tables)

3 Months Ended

Mar. 31, 2012

Investments in Debt and Equity Securities [Abstract]

Available-for-sale Securities [Table Text Block]

The table below summarizes investments in equity securities by IDACORP and Idaho Power as of March 31, 2012 and December 31, 2011 (in thousands of dollars).

	March 31, 2012						December 31, 2011
	Gross Unrealized Gain		Gross Unrealized Loss		Fair Value		Gross Unrealized Gain		Gross Unrealized Loss		Fair Value
Available-for-sale securities	$	6,455	$	—	$	26,687	$	4,220	$	1	$	22,205

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DERIVATIVE FINANCIAL INSTRUMENTS: Level 3 (Tables)

3 Months Ended

Mar. 31, 2012

Derivative Financial Instruments [Abstract]

Schedule of Derivative Instruments in Statement of Financial Position, Fair Value [Table Text Block]

The table below presents the fair values and locations of derivative instruments not designated as hedging instruments recorded on the balance sheets at March 31, 2012 and December 31, 2011 (in thousands of dollars).

	Asset Derivatives			Liability Derivatives
	Balance Sheet	Fair		Balance Sheet	Fair
	Location	Value		Location	Value
March 31, 2012
Current:
Financial swaps	Other current assets	$	6,374	Other current assets	$	1,444
Financial swaps	Other current liabilities	5,379		Other current liabilities	9,740
Forward contracts	Other current assets	31		Other current liabilities	2,256
Forward contracts	Other current liabilities	116
Long-term:
Financial swaps	Other assets	13		Other liabilities	385
Financial swaps	Other liabilities	76
Forward contracts	Other assets	248
Total		$	12,237		$	13,825
December 31, 2011
Current:
Financial swaps	Other current assets	$	4,361	Other current assets	$	1,036
Financial swaps	Other current liabilities	1,526		Other current liabilities	4,755
Forward contracts	Other current assets	70		Other current liabilities	1,370
Long-term:
Financial swaps	Other assets	359		Other liabilities	108
Total		$	6,316		$	7,269

Schedule of Derivative Instruments, Gain (Loss) in Statement of Financial Performance [Table Text Block]

The table below presents the gains and losses on derivatives not designated as hedging instruments for the three months endedMarch 31, 2012 and 2011 (in thousands of dollars).

		Gain/(Loss) on Derivatives Recognized
		in Income(1)
	Location of Gain/(Loss) on	March 31,
	Derivatives Recognized in Income	2012			2011
Financial swaps	Off-system sales	$	4,439		$	6,721
Financial swaps	Purchased power	(993		)	(167		)
Financial swaps	Fuel expense	(84		)	—
Financial swaps	Other operations and maintenance	(45		)	—

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

Schedule of Derivative Instruments [Table Text Block]

Idaho Power had volumes of derivative commodity forward contracts and swaps outstanding at March 31, 2012 and 2011 set forth in the table below.

		March 31,
Commodity	Units	2012	2011
Electricity purchases	MWh	256,200	486,000
Electricity sales	MWh	1,417,270	501,250
Natural gas purchases	MMBtu	10,082,392	1,867,316
Natural gas sales	MMBtu	913,379	—
Diesel purchases	Gallons	807,978	804,146

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Condensed Consolidated Statements of Equity (USD $) In Thousands	Total	Common Stock	Retained Earnings	Accumulated Other Comprehensive Income (Loss)	Treasury Stock	Total IDACORP, Inc. shareholders' equity	Noncontrolling Interests
Balance at beginning of period at Dec. 31, 2010							$ 3,871
Common stock issued		2,215
Other common stock changes		(83)
Net income attributable to IDACORP, Inc.	29,740		29,740
Common stock dividends			(14,855)
Unrealized (loss) gain on securities (net of tax)	553			553
Unfunded pension liability adjustment (net of tax)	234			234
Treasury stock issued					1,944
Treasury stock acquired					(1,904)
Net income (loss) attributable to noncontrolling interest	(252)						(252)
Total IDACORP, Inc. shareholders' equity		809,974	748,764	(8,781)	0	1,549,957
Total equity at end of period at Mar. 31, 2011	1,553,576						3,619
Balance at beginning of period at Dec. 31, 2011	1,661,694						4,040
Common stock issued		2,487
Other common stock changes		420
Net income attributable to IDACORP, Inc.	24,930		24,930
Common stock dividends			(16,519)
Unrealized (loss) gain on securities (net of tax)	1,362			1,362
Unfunded pension liability adjustment (net of tax)	265			265
Treasury stock issued					2,031
Treasury stock acquired					(2,062)
Net income (loss) attributable to noncontrolling interest	(112)						(112)
Total IDACORP, Inc. shareholders' equity	1,670,568	831,296	849,327	(9,995)	(60)	1,670,568
Total equity at end of period at Mar. 31, 2012	$ 1,674,496						$ 3,928

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FAIR VALUE MEASUREMENTS: Level 3 (Tables)

3 Months Ended

Mar. 31, 2012

Fair value measurements [Abstract]

Schedule of Fair Value, Assets and Liabilities Measured on Recurring Basis [Table Text Block]

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, 2012 and December 31, 2011 (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 material 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, 2012
Assets:
Derivatives	$	3,202	$	381	$	—	$	3,583
Money market funds	100		—		—		100
Trading securities:  Equity securities	2,370		—		—		2,370
Available-for-sale securities:  Equity securities	26,687		—		—		26,687
Liabilities:
Derivatives	$	275	$	6,534	$	—	$	6,809
December 31, 2011
Assets:
Derivatives	$	3,654	$	100	$	—	$	3,754
Money market funds	100		—		—		100
Trading securities:  Equity securities	3,439		—		—		3,439
Available-for-sale securities:  Equity securities	22,205		—		—		22,205
Liabilities:
Derivatives	$	405	$	4,302	$	—	$	4,707

Fair Value, by Balance Sheet Grouping [Table Text Block]

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, 2012 and December 31, 2011, 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 analysis as appropriate. 

	March 31, 2012				December 31, 2011
	Carrying		Estimated		Carrying		Estimated
	Amount		Fair Value		Amount		Fair Value
	(thousands of dollars)
IDACORP
Assets:
Notes receivable (1)	$	3,097	$	3,097	$	3,097	$	3,097
Liabilities:
Long-term debt (1)	1,490,663		1,678,075		1,491,727		1,737,912
Idaho Power
Liabilities:
Long-term debt (1)	$	1,490,663	$	1,678,075	$	1,491,727	$	1,737,912

⁽¹⁾ Notes receivable and long-term debt are categorized as Level 3 and Level 2, respectively, of the fair value hierarchy, as defined earlier in this financial statement footnote.

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EARNINGS PER SHARE: Level 4 (Details) (USD $) In Thousands, except Share data, unless otherwise specified	3 Months Ended
	Mar. 31, 2012	Mar. 31, 2011
Numerator:
Net income attributable to IDACORP, Inc.	$ 24,930	$ 29,740
Denominator:
Weighted Average Common Shares Outstanding - Basic	49,860,000	49,290,000
Effect of dilutive securities:
Options	5,000	14,000
Restricted Stock	40,000	52,000
Weighted Average Common Shares Outstanding - Diluted	49,905,000	49,356,000
Earnings Attributable to IDACORP, Inc. - Basic	$ 0.50	$ 0.60
Earnings Attributable to IDACORP, Inc. - Diluted	$ 0.50	$ 0.60
Antidilutive securities excluded from computation of earnings per share	265,089
Options outstanding	20,806

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Condensed Consolidated Statements of Income Statement (USD $) In Thousands, except Per Share data, unless otherwise specified	3 Months Ended
	Mar. 31, 2012	Mar. 31, 2011
Operating Revenues:
General business	$ 197,429	$ 203,272
Off-system sales	27,708	29,845
Other revenues	15,346	17,945
Total electric utility revenues	240,483	251,062
Other	657	432
Total operating revenues	241,140	251,494
Operating Expenses:
Purchased power	34,277	25,094
Fuel expense	32,751	29,902
Power cost adjustment	9,008	31,306
Other operations and maintenance	78,514	70,661
Energy efficiency programs	4,477	6,711
Depreciation	30,542	29,464
Taxes other than income taxes	8,100	7,211
Total electric utility expenses	197,669	200,349
Other	1,127	1,054
Total operating expenses	198,796	201,403
Operating Income	42,344	50,091
Other Income (Expense):
Other (expense) income, net	6,593	4,538
Earnings (Losses) of Unconsolidated Equity-Method Investments	1,419	(1,294)
Interest Expense:
Interest on long-term debt	19,499	20,847
Other interest, net of AFUDC	(2,294)	(1,888)
Total interest expense, net	17,205	18,959
Income Before Income Taxes	33,151	34,376
Income Tax (Benefit) Expense	8,333	4,888
Net Income	24,818	29,488
Adjustment for (income) loss attributable to noncontrolling interests	112	252
Net Income Attributable to IDACORP, Inc.	24,930	29,740
Weighted Average Common Shares Outstanding - Basic (000’s)	49,860	49,290
Weighted Average Common Shares Outstanding - Diluted (000’s)	49,905	49,356
Earnings Per Share of Common Stock:
Earnings Attributable to IDACORP, Inc. - Basic	$ 0.50	$ 0.60
Earnings Attributable to IDACORP, Inc. - Diluted	$ 0.50	$ 0.60
Dividends Declared Per Share of Common Stock	$ 0.33	$ 0.30
Idaho Power Company
Operating Revenues:
General business	197,429	203,272
Off-system sales	27,708	29,845
Other revenues	15,346	17,945
Total electric utility revenues	240,483	251,062
Operating Expenses:
Purchased power	34,277	25,094
Fuel expense	32,751	29,902
Power cost adjustment	9,008	31,306
Other operations and maintenance	78,514	70,661
Energy efficiency programs	4,477	6,711
Depreciation	30,542	29,464
Taxes other than income taxes	8,100	7,211
Total electric utility expenses	197,669	200,349
Operating Income	42,814	50,713
Other Income (Expense):
Allowance for equity funds used during construction	7,616	5,329
Other (expense) income, net	(1,479)	(1,013)
Earnings (Losses) of Unconsolidated Equity-Method Investments	4,293	858
Total other income	10,430	5,174
Interest Expense:
Interest on long-term debt	19,499	20,847
Other interest	1,560	1,213
Allowance for borrowed funds used during construction	(3,949)	(3,214)
Total interest expense, net	17,110	18,846
Income Before Income Taxes	36,134	37,041
Income Tax (Benefit) Expense	10,315	7,193
Net Income	$ 25,819	$ 29,848

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FAIR VALUE MEASUREMENTS: Level 4 (Details) (USD $) In Thousands, unless otherwise specified	Mar. 31, 2012		Dec. 31, 2011
Fair Value Disclosures
Asset derivatives	$ 3,583		$ 3,754
Money market funds	100		100
Trading securities: Equity securities	2,370		3,439
Available-for-sale securities: Equity securities	26,687		22,205
Liability derivatives	6,809		4,707
Quoted Prices in Active Markets for Identical Assets (Level 1)
Fair Value Disclosures
Asset derivatives	3,202		3,654
Money market funds	100		100
Trading securities: Equity securities	2,370		3,439
Available-for-sale securities: Equity securities	26,687		22,205
Liability derivatives	275		405
Significant Other Observable Inputs (Level 2)
Fair Value Disclosures
Asset derivatives	381		100
Money market funds	0		0
Trading securities: Equity securities	0		0
Available-for-sale securities: Equity securities	0		0
Liability derivatives	6,534		4,302
Significant Unobservable Inputs (Level 3)
Fair Value Disclosures
Asset derivatives	0		0
Money market funds	0		0
Trading securities: Equity securities	0		0
Available-for-sale securities: Equity securities	0		0
Liability derivatives	0		0
Carrying Amount
Fair Value Disclosures
Notes receivable	3,097	[1]	3,097	[1]
Long-term debt	1,490,663	[1]	1,491,727	[1]
Carrying Amount | Idaho Power Company
Fair Value Disclosures
Long-term debt	1,490,663	[1]	1,491,727	[1]
Estimated Fair Value
Fair Value Disclosures
Notes receivable	3,097	[1]	3,097	[1]
Long-term debt	1,678,075	[1]	1,737,912	[1]
Estimated Fair Value | Idaho Power Company
Fair Value Disclosures
Long-term debt	$ 1,678,075	[1]	$ 1,737,912	[1]

[1] Notes receivable and long-term debt are categorized as Level 3 and Level 2, respectively, of the fair value hierarchy, as defined earlier in this financial statement footnote.

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Condensed Consolidated Balance Sheets (Parenthetical) (USD $) In Thousands, except Share data, unless otherwise specified	Mar. 31, 2012	Dec. 31, 2011
Current Assets:
Allowance for doubtful customer receivables	$ 1,369	$ 1,239
Allowance for doubtful other receivables	187	196
Allowance for doubtful long-term receivables	2,783	2,743
Equity:
Common stock, par value	$ 0	$ 0
Common stock, shares authorized	120,000,000	120,000,000
Common stock, shares issued	50,092,260	49,964,172
Treasury stock, shares	3,362	12,177
Idaho Power Company
Current Assets:
Allowance for doubtful customer receivables	1,369	1,239
Allowance for doubtful other receivables	$ 187	$ 196
Equity:
Common stock, par value	$ 2.50	$ 2.50
Common stock, shares authorized	50,000,000	50,000,000
Common stock, shares issued	39,150,812	39,150,812

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INCOME TAXES: Level 4 (Details) (USD $)	3 Months Ended
	Mar. 31, 2012	Mar. 31, 2011
Income Tax Expense [Line Items]
Income tax at statutory rates (federal and state)	$ 13,006,000	$ 13,540,000
Additional ADITC amortization	(825,000)	(3,855,000)
Other	(3,848,000)	(4,797,000)
Income tax (benefit) expense	8,333,000	4,888,000
Effective tax rate	25.10%	14.10%
Idaho Power Company
Income Tax Expense [Line Items]
Income tax at statutory rates (federal and state)	14,128,000	14,483,000
Additional ADITC amortization	(825,000)	(3,855,000)
Other	(2,988,000)	(3,435,000)
Income tax (benefit) expense	10,315,000	7,193,000
Effective tax rate	28.50%	19.40%
Return on equity threshold below which additional amortization of ADITC is allowed	9.50%
Additional ADITC amortization available for use in the year	$ 25,000,000

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DERIVATIVE FINANCIAL INSTRUMENTS:

3 Months Ended

Mar. 31, 2012

General Discussion of Derivative Instruments and Hedging Activities [Abstract]

Derivative Financial Instruments

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 qualify for the normal purchases and normal sales exception.

All of Idaho Power's derivative instruments have been entered into for the purpose of economically hedging forecasted purchases and sales, though none of these instruments have been designated as cash flow hedges under derivative accounting guidance. Idaho Power offsets fair value amounts recognized on its balance sheet related to derivative instruments executed with the same counterparty under the same master netting agreement.

Derivative Instrument Summary

The table below presents the fair values and locations of derivative instruments not designated as hedging instruments recorded on the balance sheets at March 31, 2012 and December 31, 2011 (in thousands of dollars).

	Asset Derivatives			Liability Derivatives
	Balance Sheet	Fair		Balance Sheet	Fair
	Location	Value		Location	Value
March 31, 2012
Current:
Financial swaps	Other current assets	$	6,374	Other current assets	$	1,444
Financial swaps	Other current liabilities	5,379		Other current liabilities	9,740
Forward contracts	Other current assets	31		Other current liabilities	2,256
Forward contracts	Other current liabilities	116
Long-term:
Financial swaps	Other assets	13		Other liabilities	385
Financial swaps	Other liabilities	76
Forward contracts	Other assets	248
Total		$	12,237		$	13,825
December 31, 2011
Current:
Financial swaps	Other current assets	$	4,361	Other current assets	$	1,036
Financial swaps	Other current liabilities	1,526		Other current liabilities	4,755
Forward contracts	Other current assets	70		Other current liabilities	1,370
Long-term:
Financial swaps	Other assets	359		Other liabilities	108
Total		$	6,316		$	7,269

The table below presents the gains and losses on derivatives not designated as hedging instruments for the three months endedMarch 31, 2012 and 2011 (in thousands of dollars).

		Gain/(Loss) on Derivatives Recognized
		in Income(1)
	Location of Gain/(Loss) on	March 31,
	Derivatives Recognized in Income	2012			2011
Financial swaps	Off-system sales	$	4,439		$	6,721
Financial swaps	Purchased power	(993		)	(167		)
Financial swaps	Fuel expense	(84		)	—
Financial swaps	Other operations and maintenance	(45		)	—

⁽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 are recorded in other operations and maintenance expense.  See Note 13 for additional information concerning the determination of fair value for Idaho Power’s assets and liabilities from price risk management activities.

Idaho Power had volumes of derivative commodity forward contracts and swaps outstanding at March 31, 2012 and 2011 set forth in the table below.

		March 31,
Commodity	Units	2012	2011
Electricity purchases	MWh	256,200	486,000
Electricity sales	MWh	1,417,270	501,250
Natural gas purchases	MMBtu	10,082,392	1,867,316
Natural gas sales	MMBtu	913,379	—
Diesel purchases	Gallons	807,978	804,146

Credit Risk

At March 31, 2012, 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, 2012, was $14.0 million.  Idaho Power posted no collateral related to this amount.  If the credit-risk-related contingent features underlying these agreements were triggered on March 31, 2012, Idaho Power would have been required to post $7.3 million of additional cash collateral to its counterparties.

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REGULATORY MATTERS: Level 4 (Details) (USD $)	Dec. 30, 2011 Idaho General Rate Case Settlement	Mar. 31, 2012 Settlement Stipulation -- Investment Tax Credit and Idaho Sharing Mechanism	Dec. 27, 2011 Settlement Stipulation -- Investment Tax Credit and Idaho Sharing Mechanism	Jan. 13, 2010 Settlement Stipulation -- Investment Tax Credit and Idaho Sharing Mechanism	Apr. 13, 2012 Idaho Power Cost Adjustment	Jun. 01, 2011 Idaho Power Cost Adjustment	Mar. 31, 2012 Idaho Fixed Cost Adjustment	Mar. 30, 2012 Idaho Fixed Cost Adjustment	Mar. 02, 2012 Idaho Fixed Cost Adjustment	Mar. 02, 2012 Langley Gulch Power Plant Cost Recovery Filing - Idaho	Sep. 01, 2009 Langley Gulch Power Plant Cost Recovery Filing - Idaho	Mar. 15, 2012 Energy Efficiency and Demand Response Programs	Aug. 18, 2011 Energy Efficiency and Demand Response Programs	Mar. 31, 2012 Cost Recovery for Cessation of Boardman Coal-Fired Operations	Feb. 15, 2012 Cost Recovery for Cessation of Boardman Coal-Fired Operations	Apr. 27, 2012 Idaho Depreciation Rate Filings	Mar. 31, 2012 Idaho Depreciation Rate Filings	Feb. 15, 2012 Idaho Depreciation Rate Filings	Mar. 01, 2012 Oregon General Rate Case Filing	Jul. 29, 2011 Oregon General Rate Case Filing	Mar. 09, 2012 Langley Gulch Power Plant Cost Recovery Fiing - Oregon
Rate Case
Increase (Decrease) in Rates	$ 34,000,000				$ 43,000,000	$ 40,400,000			$ 1,200,000	$ 59,900,000	$ 396,600,000	$ 42,600,000	$ 42,000,000		$ 1,600,000	$ 10,600,000		$ 2,700,000	$ 1,800,000	$ 5,800,000	$ 3,000,000
Period of Current ADITC Stipulation		3 years
Extension period of the fixed cost adjustment pilot program							2 years
Accelerated depreciation period of metering equipment																	3 years
Percentage Increase (Decrease) in Rates	4.07%
Authorized Rate of Return in Rate Case	7.86%																		7.757%
Total Retail Rate Base	2,360,000,000																			121,900,000
Authorized Return on Equity in Rate Case, Minimum			9.50%	9.50%															9.90%
Authorized Return on Equity in Rate Case, Mid-point			10.00%
Authorized Return on Equity in Rate Case, Maximum			10.50%	10.50%																10.50%
Investment Tax Credits, Maximum, in Rate Case			45,000,000
Investment Tax Credits Maximum in one Year in Rate Case			25,000,000
Automatic adjustment of authorized return on equity in rate case, minimum			95.00%
Automatic adjustment of authorized return on equity in rate case, maximum			105.00%
Percentage to be Shared with Customers			75.00%
Percentage to be Shared with Entity			25.00%
Proposed Sharing of Costs and Benefits								50.00%
Percentage cap on the FCA adjustment								3.00%
Annual FCA Collection									10,300,000
Estimated Investment in Langley Gulch										398,000,000
Increase (Decrease) in Rate Base										336,700,000
Jointly Owned Utility Plant, Net Ownership Amount														$ 22,500,000

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SEGMENT INFORMATION:

3 Months Ended

Mar. 31, 2012

Segment Reporting, Measurement Disclosures [Abstract]

Segment Information

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 in the table below.  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 table below 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, 2012:
Revenues	$	240,483	$	657		$	—		$	241,140
Net income (loss) attributable to IDACORP, Inc.	25,819		(889		)	—			24,930
Total assets as of March 31, 2012	4,885,800		120,997			(16,176		)	4,990,621
Three months ended March 31, 2011:
Revenues	$	251,062	$	432		$	—		$	251,494
Net income (loss) attributable to IDACORP, Inc.	29,848		(108		)	—			29,740

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Condensed Consolidated Statements of Cash Flows (USD $) In Thousands, unless otherwise specified	3 Months Ended
	Mar. 31, 2012	Mar. 31, 2011
Operating Activities:
Net Income	$ 24,818	$ 29,488
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization	31,875	31,592
Deferred income taxes and investment tax credits	5,008	1,266
Changes in regulatory assets and liabilities	15,586	35,850
Pension and postretirement benefit plan expense	7,673	4,553
Contributions to pension and postretirement benefit plans	(35,203)	(593)
(Earnings) losses of unconsolidated equity-method investments	(1,419)	1,294
Distributions from unconsolidated equity-method investments	9,050	0
Allowance for equity funds used during construction	(7,616)	(5,329)
Other non-cash adjustments to net income, net	827	724
Change in:
Accounts receivable and prepayments	365	(4,774)
Accounts payable and other accrued liabilities	(23,215)	(26,910)
Taxes accrued/receivable	10,352	22,665
Other current assets	(1,242)	54
Other current liabilities	4,812	8,440
Other assets	305	(109)
Other liabilities	(4,326)	(4,992)
Net cash provided by operating activities	37,650	93,219
Investing Activities:
Additions to property, plant and equipment	(48,382)	(101,880)
Proceeds from the sale of emission allowances and RECs	785	2,055
Investments in affordable housing	(350)	(905)
Investments in unconsolidated affiliates	0	(300)
Other	(1,034)	1,026
Net cash used in investing activities	(48,981)	(100,004)
Financing Activities:
Retirement of long-term debt	(1,064)	(121,064)
Dividends on common stock	(16,800)	(15,147)
Net change in short-term borrowings	8,800	7,200
Issuance of common stock	2,487	2,215
Acquisition of treasury stock	(2,062)	(1,904)
Other	1,014	749
Net cash (used in) provided by financing activities	(7,625)	(127,951)
Net (decrease) increase in cash and cash equivalents	(18,956)	(134,736)
Cash and cash equivalents at beginning of the period	27,813	228,677
Cash and cash equivalents at end of the period	8,857	93,941
Cash paid (received) during the period for:
Income taxes	198	(12,700)
Interest (net of amount capitalized)	14,943	18,430
Non-cash investing activities:
Additions to property, plant and equipment in accounts payable	21,241	24,641
Idaho Power Company
Operating Activities:
Net Income	25,819	29,848
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization	31,723	31,435
Deferred income taxes and investment tax credits	25,114	2,259
Changes in regulatory assets and liabilities	15,586	35,850
Pension and postretirement benefit plan expense	7,673	4,553
Contributions to pension and postretirement benefit plans	(35,203)	(593)
(Earnings) losses of unconsolidated equity-method investments	(4,293)	(858)
Distributions from unconsolidated equity-method investments	9,050	0
Allowance for equity funds used during construction	(7,616)	(5,329)
Other non-cash adjustments to net income, net	559	303
Change in:
Accounts receivable and prepayments	317	(6,107)
Accounts payable and other accrued liabilities	(22,998)	(26,700)
Taxes accrued/receivable	(4,564)	33,601
Other current assets	(1,241)	54
Other current liabilities	4,813	8,443
Other assets	305	(109)
Other liabilities	(4,105)	(4,151)
Net cash provided by operating activities	40,939	102,499
Investing Activities:
Additions to property, plant and equipment	(48,382)	(101,880)
Proceeds from the sale of emission allowances and RECs	785	2,055
Investments in unconsolidated affiliates	0	(300)
Other	(1,033)	405
Net cash used in investing activities	(48,630)	99,720
Financing Activities:
Retirement of long-term debt	(1,064)	(121,064)
Dividends on common stock	(16,570)	(14,922)
Net change in short-term borrowings	1,500	0
Capital contribution from parent	7,500	0
Other	0	(8)
Net cash (used in) provided by financing activities	(8,634)	(135,994)
Net (decrease) increase in cash and cash equivalents	(16,325)	(133,215)
Cash and cash equivalents at beginning of the period	19,316	224,233
Cash and cash equivalents at end of the period	2,991	91,018
Cash paid (received) during the period for:
Income taxes	(3,008)	(22,323)
Interest (net of amount capitalized)	14,848	18,310
Non-cash investing activities:
Additions to property, plant and equipment in accounts payable	$ 21,241	$ 24,641

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Condensed Consolidated Statements of Comprehensive Income (USD $) In Thousands, unless otherwise specified	3 Months Ended
	Mar. 31, 2012	Mar. 31, 2011
Net Income	$ 24,818	$ 29,488
Other Comprehensive Income:
Net unrealized holding gains (losses) arising during the period, net of tax	1,362	553
Unfunded pension liability adjustment, net of tax	265	234
Total Comprehensive Income	26,445	30,275
Comprehensive (income) loss attributable to noncontrolling interests	112	252
Comprehensive Income Attributable to IDACORP, Inc.	26,557	30,527
Idaho Power Company
Net Income	25,819	29,848
Other Comprehensive Income:
Net unrealized holding gains (losses) arising during the period, net of tax	1,362	553
Unfunded pension liability adjustment, net of tax	265	234
Total Comprehensive Income	$ 27,446	$ 30,635

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EARNINGS PER SHARE:

3 Months Ended

Mar. 31, 2012

Earnings Per Share [Abstract]

Earnings Per Share

EARNINGS PER SHARE

The table below presents the computation of IDACORP’s basic and diluted earnings per share (EPS) for the three months endedMarch 31, 2012 and 2011 (in thousands, except for per share amounts).

	Three months ended March 31,
	2012		2011
Numerator:
Net income attributable to IDACORP, Inc.	$	24,930	$	29,740
Denominator:
Weighted-average common shares outstanding - basic	49,860		49,290
Effect of dilutive securities:
Options	5		14
Restricted Stock	40		52
Weighted-average common shares outstanding - diluted	49,905		49,356
Basic earnings per share	$	0.50	$	0.60
Diluted earnings per share	$	0.50	$	0.60

The diluted EPS computation for the three months endedMarch 31, 2011 excludes 265,089 options because the options’ exercise prices were greater than the average market price of the common stock during that period.  In total, 20,806 options were outstanding at March 31, 2012, with expiration dates between 2013 and 2015.

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Document And Entity Information	3 Months Ended
	Mar. 31, 2012	Apr. 27, 2012
Entity Information
Document Type	10-Q
Amendment Flag	false
Document Period End Date	Mar. 31, 2012
Document Fiscal Year Focus	2012
Document Fiscal Period Focus	Q1
Trading Symbol	IDA
Entity Registrant Name	IDACORP INC.
Entity Central Index Key	0001057877
Current Fiscal Year End Date	--12-31
Entity Filer Category	Large Accelerated Filer
Entity Common Stock, Shares Outstanding		50,095,905
Idaho Power Company
Entity Information
Entity Registrant Name	Idaho Power Company
Entity Central Index Key	0000049648
Entity Filer Category	Non-accelerated Filer
Entity Common Stock, Shares Outstanding		39,150,812

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COMMITMENTS:

3 Months Ended

Mar. 31, 2012

Commitments [Abstract]

Commitments

COMMITMENTS

Purchase Obligations

Only one material change to long-term purchase commitments occurred during the three months endedMarch 31, 2012. In March 2012, the power purchase agreement with a solar energy project was terminated, which reduced Idaho Power's contractual payment obligations by approximately $90 million over the 25-year life of the contract.

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, 2012, representing IERCo's one-third share of BCC's total reclamation obligation.  BCC has a reclamation trust fund set aside specifically for the purpose of paying these reclamation costs.  At March 31, 2012, the value of the reclamation trust fund totaled $88 million. BCC periodically 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 indemnification provisions 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, 2012, 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.

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Condensed Consolidated Statements of Comprehensive Income (Parenthetical) (USD $) In Thousands, unless otherwise specified	3 Months Ended
	Mar. 31, 2012	Mar. 31, 2011
Net unrealized holding gains (losses) arising during the period, tax	$ 874	$ 355
Unfunded pension liability adjustment, tax	170	150
Idaho Power Company
Net unrealized holding gains (losses) arising during the period, tax	874	355
Unfunded pension liability adjustment, tax	$ 170	$ 150

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INCOME TAXES:

3 Months Ended

Mar. 31, 2012

Income Taxes [Abstract]

Income Taxes

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 interim 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

Set forth below is a summary of income tax expense for the three months endedMarch 31 (in thousands of dollars):

	IDACORP						Idaho Power
	2012			2011			2012			2011
Income tax at statutory rates (federal and state)	$	13,006		$	13,540		$	14,128		$	14,483
Additional ADITC amortization	(825		)	(3,855		)	(825		)	(3,855		)
Other	(3,848		)	(4,797		)	(2,988		)	(3,435		)
Income tax expense	$	8,333		$	4,888		$	10,315		$	7,193
Effective tax rate	25.1		%	14.1		%	28.5		%	19.4		%

The increase in first quarter 2012 income tax expense as compared to the same period in 2011 was primarily due to lower utilization of additional ADITC amortization (discussed below) at Idaho Power. Net regulatory flow-through tax adjustments at Idaho Power and tax credits at IFS for the three months endedMarch 31, 2012 were comparable to the same period in 2011.

Idaho Power's December 2011 settlement agreement with the Idaho Public Utilities Commission (IPUC) and other parties provides 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 2012 to 2014.  Under the settlement agreement, Idaho Power has up to $25 million of additional ADITC amortization available for use in 2012. Idaho Power recorded $0.8 million of additional ADITC amortization in the first quarter of 2012 based on itsestimate of 2012 Idaho jurisdictional return on year-end equity.

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SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES:

3 Months Ended

Mar. 31, 2012

Summary of Significant Accounting Policies [Abstract]

Summary of Significant Accounting Policies

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's utility operations are regulated primarily 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.  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 $20 million of assets, primarily a hydroelectric plant, and approximately $15 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 was $97 million at March 31, 2012, and Idaho Power's maximum exposure to loss is the carrying value, plus any additional future contributions to BCC and a $63 million guarantee for mine reclamation costs, which is discussed further in Note 8.

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 $60 million at March 31, 2012.

Regulation of Utility Operations

IDACORP's and Idaho Power's financial statements reflect the effects of the different ratemaking principles followed by the jurisdictions regulating Idaho Power.  The application of accounting principles related to regulated operations sometimes results in Idaho Power recording expenses and revenues in a different period than when an unregulated enterprise would otherwise record expenses and revenues.  In these instances, the amounts are deferred as regulatory assets or regulatory liabilities on the balance sheet and recorded on the income statement when recovered or returned in rates.  Additionally, regulators can impose regulatory liabilities upon a regulated company for amounts previously collected from customers and for amounts that are expected to be refunded to customers.  The effects of applying these regulatory accounting principles to Idaho Power's operations are discussed in more detail in Note 3.

Financial Statements

In the opinion of management of IDACORP and Idaho Power, the accompanying unaudited condensed consolidated financial statements contain all adjustments necessary to present fairly each company's consolidated financial position as of March 31, 2012, consolidated results of operations and cash flows for the three months endedMarch 31, 2012 and 2011.  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, 2011.  The results of operations for the interim period 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 the 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.

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FAIR VALUE MEASUREMENTS:

3 Months Ended

Mar. 31, 2012

Fair Value, Assets and Liabilities Measured on Recurring Basis [Abstract]

Fair Value Measurements

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.

An item recorded at fair value is reclassified between levels when changes in the nature of valuation inputs cause the item to no longer meet the criteria for the level in which it was previously categorized. There have been no material reclassifications between levels during the current period.

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 location basis, 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. Notes receivable are related to Ida-West and are valued based on unobservable inputs, including discounted cash flows, which are partially based on forecasted hydroelectric conditions. Long-term debt is not traded on an exchange and is valued using quoted rates for similar debt in active markets. There were no material changes in valuation techniques or inputs during the quarter ended March 31, 2012 or the year ended December 31, 2011.

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, 2012 and December 31, 2011 (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 material 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, 2012
Assets:
Derivatives	$	3,202	$	381	$	—	$	3,583
Money market funds	100		—		—		100
Trading securities:  Equity securities	2,370		—		—		2,370
Available-for-sale securities:  Equity securities	26,687		—		—		26,687
Liabilities:
Derivatives	$	275	$	6,534	$	—	$	6,809
December 31, 2011
Assets:
Derivatives	$	3,654	$	100	$	—	$	3,754
Money market funds	100		—		—		100
Trading securities:  Equity securities	3,439		—		—		3,439
Available-for-sale securities:  Equity securities	22,205		—		—		22,205
Liabilities:
Derivatives	$	405	$	4,302	$	—	$	4,707

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, 2012 and December 31, 2011, 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 analysis as appropriate. 

	March 31, 2012				December 31, 2011
	Carrying		Estimated		Carrying		Estimated
	Amount		Fair Value		Amount		Fair Value
	(thousands of dollars)
IDACORP
Assets:
Notes receivable (1)	$	3,097	$	3,097	$	3,097	$	3,097
Liabilities:
Long-term debt (1)	1,490,663		1,678,075		1,491,727		1,737,912
Idaho Power
Liabilities:
Long-term debt (1)	$	1,490,663	$	1,678,075	$	1,491,727	$	1,737,912

⁽¹⁾ Notes receivable and long-term debt are categorized as Level 3 and Level 2, respectively, of the fair value hierarchy, as defined earlier in this financial statement footnote.

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CONTINGENCIES:

3 Months Ended

Mar. 31, 2012

Loss Contingency [Abstract]

Contingencies

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 9.  Some of these claims, controversies, disputes, and other contingent matters involve litigation and regulatory or other contested proceedings.  IDACORP and Idaho Power intend to vigorously protect and defend their interests and pursue their rights.  However, the ultimate resolution and outcome of litigation and regulatory proceedings is inherently difficult to determine, particularly where (a) the remedies or penalties sought are indeterminate, (b) the proceedings are in the early stages or the substantive issues have not been well developed, or (c) the matters involve complex or novel legal theories or a large number of parties. In accordance with applicable accounting guidance, IDACORP and Idaho Power, as applicable, establish an accrual for legal proceedings when those matters proceed to a stage where they present loss contingencies that are both probable and reasonably estimable. In such cases, there may be a possible exposure to loss in excess of any amounts accrued. IDACORP and Idaho Power monitor those matters for developments that could affect the likelihood of a loss and the accrued amount, if any, thereof, and adjust the amount as appropriate. If the loss contingency at issue is not both probable and reasonably estimable, IDACORP and Idaho Power do not establish an accrual and the matter will continue to be monitored for any developments that would make the loss contingency both probable and reasonably estimable. As of the date of this report, IDACORP's and Idaho Power's accruals for legal proceedings are not material to their financial statements as a whole; however, future accruals could be material in a given period. IDACORP's and Idaho Power's determination is based on currently available information, and estimates presented in financial statements and other financial disclosures involve significant judgment and may be subject to significant uncertainty. As available information changes, the matters for which IDACORP and Idaho Power are able to estimate the loss may change, and the estimates themselves may change.

For certain of those matters described in this report for which IDACORP or Idaho Power have determined a loss contingency may, in the future, be at least reasonably possible, IDACORP and Idaho Power have stated that they are unable to estimate the possible loss or a range of possible loss that may result from those matters. Depending on a range of factors, such as the complexity of the facts, the unique nature of the legal theories, the pace of discovery, the timing of decisions of the court or arbiter, and the adverse party's willingness to negotiate towards a resolution, it may be months or years after the filing of a case or commencement of a proceeding before IDACORP or Idaho Power may be in a position to estimate the possible loss or range of possible loss for those matters.

Given the substantial or indeterminate amounts sought in certain of the matters described below, and the inherent unpredictability of such matters, an adverse outcome in certain of these matters could have a material adverse effect on IDACORP's and Idaho Power's financial condition, results of operations, or cash flows in particular quarterly or annual periods. 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.

Pacific Northwest Refund Proceedings

On July 25, 2001, the FERC issued an order establishing a 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.  During that period, Idaho Power or IE both sold and purchased electricity in the Pacific Northwest. 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 California Department of Water Resources (CDWR) in the scope of the proceeding.  The Ninth Circuit officially returned the case to the FERC on April 16, 2009.  On October 3, 2011, the FERC issued its order on remand. The FERC ordered that the record be re-opened to permit parties seeking refunds to submit seller-specific evidence in support of their claims for sales made during the period confined to December 25, 2000 through June 20, 2001. The seller-specific claims must show that a seller engaged in unlawful market activity with a causal connection to have directly affected the negotiation of the specific contract or contracts to which the seller was a party. IE and Idaho Power understand the order to provide that neither claims of general dysfunction in the California markets nor in the Pacific Northwest market will be sufficient to support claims. While directing a trial-type hearing, the FERC also directed that the hearings be held in abeyance so that the matter may be presented to a settlement judge. On November 2, 2011, each of the City of Seattle, Washington, the City of Tacoma, Washington, the Port of Seattle, and the California Parties (consisting of the California Attorney General and the California Public Utilities Commission) filed requests for rehearing, seeking to expand the scope of the October 3, 2011 order. The designated settlement judge has met with the parties and convened a settlement conference to establish settlement procedures. The FERC's Chief Administrative Law Judge memorialized certain settlement procedures to which the parties agreed in an order issued on November 23, 2011.

IE and Idaho Power intend to continue to defend their positions in the Pacific Northwest refund proceedings vigorously. Idaho Power does not believe that claims conforming to the requirements of the FERC's October 3, 2011 order have been submitted, and the FERC's order remains subject to rehearing and reconsideration. Idaho Power and IE are unable to predict when and how the FERC will act on the rehearing requests, which contracts would be subject to refunds, whether the FERC will order refunds, or how the refunds would be calculated. As a result of these factors, as of the date of this report Idaho Power and IE are unable to estimate the reasonably possible loss or range of losses that Idaho Power or IE could incur as a result of this matter. However, in the first quarter of 2012 Idaho Power reached a tentative settlement, subject to review and approval by the FERC, with one party to the proceedings. While Idaho Power is unable to quantify or determine the outcome of claims made by parties that have not yet settled, the settlement amount agreed upon by Idaho Power and the settling party was immaterial to IDACORP's and Idaho Power's financial statements.

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 in March 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 rights 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 rights 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 continues to work with the Idaho Water Resource Board, other stakeholders, and the Idaho Legislature in exploring opportunities for implementation 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 anticipate any material modification of its water rights as a result of the SRBA process.

Other Legal Proceedings

IDACORP and Idaho Power are parties to legal claims, actions, and proceedings in addition to those discussed above.  However, as of the date of this report the companies believe that resolution of these matters will not have a material adverse effect on their consolidated financial positions, results of operations, or cash flows.

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NOTES PAYABLE:

3 Months Ended

Mar. 31, 2012

Notes Payable [Abstract]

Notes Payable

NOTES PAYABLE

Credit Facilities

IDACORP and Idaho Power have $125 million and $300 million credit facilities, respectively, which may be used for general corporate purposes and commercial paper backup. IDACORP's credit facility consists of a revolving line of credit not to exceed the aggregate principal amount at any one time outstanding of $125 million, including swingline loans in an aggregate principal amount at any time outstanding not to exceed $15 million, and letters of credit in an aggregate principal amount at any time outstanding not to exceed $50 million. Idaho Power's credit facility consists of a revolving line of credit, through the issuance of loans and standby letters of credit, not to exceed the aggregate principal amount at any one time outstanding of $300 million, including swingline loans in an aggregate principal amount at any time outstanding not to exceed $30 million. IDACORP and Idaho Power have the right to request an increase in the aggregate principal amount of the facilities to $150 million and $450 million, respectively, in each case subject to certain conditions. The credit facilities mature on October 26, 2016, although IDACORP and Idaho Power have the right to request up to two one-year extensions of the credit agreement, in each case subject to certain conditions.

The IDACORP and Idaho Power credit agreements have similar terms and conditions. The interest rates for any borrowings under the facilities are based on either (1) a floating rate that is equal to the highest of the prime rate, federal funds rate plus 0.5 percent, or LIBOR rate plus 1.0 percent, or (2) the LIBOR rate, plus, in each case, an applicable margin. The margin is based on IDACORP's or Idaho Power's, as applicable, senior unsecured long-term indebtedness credit rating by Moody's Investors Service, Inc., Standard and Poor's Ratings Services, and Fitch Rating Services, Inc., as set forth on a schedule to the credit agreements. Under their respective facilities, the companies pay a facility fee on the commitment based on the respective company's credit rating for senior unsecured long-term debt securities.

At March 31, 2012, no loans were outstanding under either IDACORP's or Idaho Power's facilities then in effect.  At March 31, 2012, Idaho Power had regulatory authority to incur up to $450 million principal amount of short-term indebtedness at any one time outstanding. Balances and interest rates of IDACORP’s and Idaho Power's short-term borrowings were as follows at March 31, 2012 and December 31, 2011 (in thousands of dollars):

	March 31, 2012									December 31, 2011
	Idaho Power			IDACORP			Total			Idaho Power			IDACORP			Total
Commercial paper outstanding	$	1,500		$	61,500		$	63,000		$	—		$	54,200		$	54,200
Weighted-average annual interest rate	0.41		%	0.46		%	0.46		%	—		%	0.47		%	0.47		%

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REGULATORY MATTERS:

3 Months Ended

Mar. 31, 2012

Regulatory Matters Disclosures [Abstract]

Regulatory Matters

REGULATORY MATTERS

Recent and Pending Idaho Regulatory Matters

Idaho General Rate Case Settlement

On June 1, 2011, Idaho Power filed a general rate case and proposed rate schedules with the IPUC, Case No. IPC-E-11-08. On September 23, 2011, Idaho Power, the IPUC Staff, and other interested parties publicly filed a settlement stipulation with the IPUC resolving most of the key contested issues in the Idaho general rate case. On December 30, 2011, the IPUC issued an order approving the settlement stipulation. The settlement stipulation provides for a 7.86 percent authorized rate of return on an Idaho-jurisdictional rate base of approximately $2.36 billion. The approved settlement stipulation resulted in a 4.07 percent, or $34.0 million, overall increase in Idaho Power's annual Idaho jurisdictional base rate revenues, effective January 1, 2012. While both are final, neither the order nor the settlement stipulation specified an authorized rate of return on equity.

Settlement Stipulation -- Investment Tax Credits and Idaho Sharing Mechanism

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 provided for (a) the use of additional ADITC to help achieve a minimum 9.5 percent return on year-end equity in the Idaho jurisdiction, and (b) an equal sharing between Idaho Power and its customers of any Idaho jurisdiction earnings exceeding a return on year-end equity of 10.5 percent in the Idaho jurisdiction.  The sharing and ADITC amortization provisions of the January 2010 settlement agreement terminated on December 31, 2011.

On November 2, 2011, Idaho Power filed an application with the IPUC requesting an extension of the two elements of the January 2010 settlement agreement described above. On December 27, 2011, the IPUC issued an order, separate from the then-pending Idaho general rate case proceeding, approving a settlement stipulation that provides as follows:

• if Idaho Power's actual rate of return on year-end equity in the Idaho jurisdiction (Idaho ROE) for 2012, 2013, or 2014 is less than 9.5 percent, then Idaho Power may amortize additional ADITC to help achieve a minimum 9.5 percent Idaho ROE in the applicable year. Idaho Power would be permitted to amortize additional ADITC in an aggregate amount up to $45 million over the three-year period, but could use no more than $25 million in 2012;

• if Idaho Power's actual Idaho ROE for 2012, 2013, or 2014 exceeds 10.0 percent, the amount of Idaho Power's Idaho jurisdictional earnings exceeding a 10.0 percent but less than a 10.5 percent Idaho ROE for the applicable year would be shared equally between Idaho Power and its Idaho customers; and

• if Idaho Power's actual Idaho ROE for 2012, 2013, or 2014 exceeds 10.5 percent, the amount of Idaho Power's Idaho jurisdictional earnings exceeding a 10.5 percent Idaho ROE for the applicable year would be allocated 25 percent to Idaho Power and 75 percent to benefit Idaho customers through an offset in the pension balancing account.

The settlement stipulation provides that the Idaho ROE thresholds (9.5 percent, 10.0 percent, and 10.5 percent) will be automatically adjusted prospectively in the event the IPUC approves a change to Idaho Power's authorized return on equity as part of a general rate case proceeding seeking a rate change effective prior to January 1, 2015. The automatic adjustments would be as follows: (a) the 9.5 percent Idaho ROE trigger in the settlement stipulation would be replaced by the percentage equal to 95 percent of the new authorized rate of return on equity; (b) the 10.0 percent Idaho ROE trigger in the settlement stipulation would be re-established at the new authorized rate of return on equity; and (c) the 10.5 percent Idaho ROE trigger in the settlement stipulation would be replaced by the percentage equal to 105 percent of the new authorized rate of return on equity.

Annual Power Cost Adjustment Mechanism Filing

Idaho Power has power cost adjustment (PCA) mechanisms in its Idaho and Oregon jurisdictions that address the volatility of power supply costs and provide for annual adjustments to the rates charged to retail customers. In the Idaho jurisdiction, the annual PCA adjustments are based on (a) a forecast component, based on a forecast of net power supply costs in the coming year as compared to net power supply costs in base rates, and (b) a true-up component, based on the difference between the previous year’s actual net power supply costs and the previous year’s forecast.  The latter component also includes a balancing mechanism so that, over time, the actual collection or refund of authorized true-up dollars matches the amounts authorized.  On April 13, 2012, Idaho Power made its annual Idaho PCA filing with the IPUC, requesting a $43.0 million increase to Idaho PCA rates, effective for the period from June 1, 2012 to May 31, 2013. The PCA rates in effect from June 1, 2011 to May 31, 2012 were based on a May 31, 2011 IPUC order approving Idaho Power's requested $40.4 million Idaho PCA rate decrease.

Fixed Cost Adjustment Filings

The fixed cost adjustment (FCA) began as a pilot program for Idaho Power’s Idaho residential and small general service customers, running from 2007 through 2009.  The FCA 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.  The FCA is adjusted each year to collect, or refund, the difference between the allowed fixed-cost recovery amount and the actual fixed costs recovered by Idaho Power during the year.

On April 29, 2010, the IPUC approved a two-year extension of the FCA pilot program, retroactively effective from January 1, 2010, through December 31, 2011. On October 19, 2011, Idaho Power filed an application with the IPUC requesting that the FCA pilot program become permanent for residential and small general service customer classes effective January 1, 2012. On March 30, 2012, the IPUC issued an order approving the FCA as a permanent program. The IPUC noted in its order, however, that the FCA does not isolate or identify changes in cost recovery associated solely with Idaho Power's energy efficiency programs, and instead responds to all changes in load reduction. While the IPUC rejected the IPUC Staff's proposal that FCA results be shared 50 percent with customers, the IPUC's order directed Idaho Power to file with the IPUC a proposal to adjust the FCA to address the exclusion of changes in load not related to energy efficiency programs. The order also maintained the existing 3 percent cap on the FCA adjustment.

On March 2, 2012, Idaho Power filed an application with the IPUC requesting an order authorizing Idaho Power to increase the annual FCA collection to $10.3 million, a $1.2 million increase in FCA rates, for the period from June 1, 2012 to May 31, 2013. As of the date of this report, a determination and order from the IPUC is pending.

Langley Gulch Power Plant Cost Recovery Filing - Idaho

On September 1, 2009, Idaho Power received pre-approval from the IPUC to include $396.6 million of construction costs in Idaho Power’s rate base when the Langley Gulch natural gas-fired power plant, currently under construction, achieves commercial operation. On March 2, 2012, Idaho Power filed an application with the IPUC requesting an increase in annual Idaho-jurisdiction base rates of $59.9 million, effective July 1, 2012, for recovery of Idaho Power's investment in the Langley Gulch power plant. Idaho Power's application stated that its estimated investment in the plant through June 2012 will be approximately $398 million. After the impact of depreciation, deferred income taxes, amounts currently included in rates, and an Idaho-jurisdictional cost allocation, Idaho Power's application requests a $336.7 million increase in Idaho jurisdiction rate base. Idaho Power's requested base rate increase is based on an overall rate of return of 7.86 percent, as authorized by a prior IPUC order. As of the date of this report, Idaho Power is unable to determine the outcome of the proceeding. The IPUC has, however, approved Idaho Power's request to process the application under modified procedure.

Energy Efficiency and Demand Response Programs

Idaho Power manages a wide range of opportunities for its customers to participate in energy efficiency and demand response programs.  On March 15, 2012, Idaho Power filed an application with the IPUC requesting an order designating Idaho Power's 2011 demand-side management expenditures of $42.6 million as prudently incurred. As of the date of this report, a determination and order from the IPUC is pending. Idaho Power's previous application filed in March 2011, which was approved by the IPUC in August 2011, designated Idaho Power's 2010 Idaho energy efficiency rider expenditures of approximately $42 million as prudently incurred expenses.

Cost Recovery for Cessation of Boardman Coal-Fired Operations

In December 2010, the Oregon Environmental Quality Commission approved a plan to cease coal-fired operations at the Boardman power plant not later than December 31, 2020. The plan for a 2020 shutdown of coal-fired operations at the Boardman plant results in increased revenue requirements for Idaho Power related to accelerated depreciation expense, additional plant investments, and decommissioning costs. As a result, in response to an application filed by Idaho Power, on February 15, 2012 the IPUC issued an order accepting Idaho Power's regulatory accounting and cost recovery plan associated with the early plant shut-down and approving the establishment of a balancing account whereby incremental costs and benefits associated with the early shut-down will be tracked for recovery in a subsequent proceeding. On February 15, 2012, Idaho Power filed an application with the IPUC requesting a $1.6 million annual increase in Idaho-jurisdiction base rates to recover the incremental Idaho jurisdictional annual revenue deficiency associated with early shut-down. As of the date of this report, a determination and order from the IPUC is pending. As of March 31, 2012, Idaho Power's net book value in the Boardman plant was approximately $22.5 million.

Idaho Depreciation Rate Filings

The advanced metering infrastructure (AMI) project provides the means to automatically retrieve energy consumption information, eliminating manual meter reading expense. On February 12, 2009, the IPUC approved Idaho Power’s application requesting a Certificate of Public Convenience and Necessity for the deployment of AMI technology and approval of accelerated depreciation of existing non-AMI metering equipment.  Commencing June 1, 2009, the IPUC approved a rate increase, allowing Idaho Power to recover the three-year accelerated depreciation of the existing non-AMI metering equipment and to begin earning a return on its AMI investment.  On April 27, 2012, the IPUC approved Idaho Power's February 15, 2012 application requesting approval of a $10.6 million decrease in rates for specified customer classes, effective June 1, 2012, as a result of the removal of accelerated depreciation expense associated with non-AMI metering equipment.

In connection with a depreciation study authorized by Idaho Power and conducted by a third party, on February 15, 2012, Idaho Power filed an application with the IPUC seeking to institute revised depreciation rates for electric plant-in-service, based upon updated service life estimates and net salvage percentages for all plant assets, and adjust Idaho-jurisdictional base rates to reflect the revised depreciation rates. Idaho Power's application requested a $2.7 million increase in Idaho-jurisdictional base rates, with new rates effective June 1, 2012. As of the date of this report, a determination and order from the IPUC is pending.

Recent and Pending Oregon Regulatory Matters

Oregon General Rate Case Filing

On July 29, 2011, Idaho Power filed a general rate case and proposed rate schedules with the OPUC, Case No. UE 233. The filing requested a $5.8 million increase in annual Oregon jurisdictional revenues and an authorized rate of return on equity of 10.5 percent, with an Oregon retail rate base of approximately $121.9 million. Idaho Power, the OPUC Staff, and other interested parties executed and filed a partial settlement stipulation with the OPUC on February 1, 2012, resolving all matters in the general rate case other than the prudence of costs associated with pollution control investments at the Jim Bridger coal-fired power plant. The settlement stipulation provided for a $1.8 million base rate increase, a return on equity of 9.9 percent, and an overall rate of return of 7.757 percent in the Oregon jurisdiction. On February 23, 2012, the OPUC issued an order adopting the settlement stipulation. New rates in conformity with the settlement stipulation went into effect on March 1, 2012. The OPUC will conduct a second phase of the proceedings to address the prudence of Idaho Power's pollution control investments at the Jim Bridger plant.

Langley Gulch Power Plant Cost Recovery Filing - Oregon

On March 9, 2012, Idaho Power filed an application with the OPUC requesting an annual increase in Oregon-jurisdictional revenues of $3.0 million, for inclusion of the Langley Gulch power plant in Idaho Power's rate base. As of the date of this report, Idaho Power is unable to determine the outcome of the proceeding. A scheduling order issued by the OPUC provides for an OPUC decision by January 2013 and inclusion in rates by March 31, 2013.

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LONG-TERM DEBT:

3 Months Ended

Mar. 31, 2012

Long-term Debt, Unclassified [Abstract]

Long-term Debt

LONG-TERM DEBT

As of March 31, 2012, IDACORP had approximately $539 million remaining on a shelf registration statement filed with the U.S. Securities and Exchange Commission (SEC) that can be used for the issuance of debt securities or IDACORP 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.  At March 31, 2012, $300 million remained on Idaho Power’s shelf registration for the issuance of first mortgage bonds and debt securities. On April 13, 2012, Idaho Power issued $75 million of 2.95% first mortgage bonds, medium-term notes, Series I, maturing on April 1, 2022, and $75 million of 4.30% first mortgage bonds, medium-term notes, Series I, maturing on April 1, 2042. The first mortgage bonds were issued under Idaho Power's shelf registration statement. As a result of this issuance, as of the date of this report $150 million remained on Idaho Power’s shelf registration for the issuance of first mortgage bonds and debt securities.

In April 2012, Idaho Power issued an irrevocable notice of redemption to redeem, prior to maturity, its $100 million in principal amount of 4.75% first mortgage bonds, medium-term notes due November 2012. Idaho Power intends to use a portion of the net proceeds of the April 2012 sale of first mortgage bonds, medium-term notes to effect the redemption. As a result, the $100 million of 4.75% first mortgage bonds, medium-term notes due November 2012 are reported as long-term debt in the condensed consolidated balance sheets, instead of as current maturities of long-term debt.

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COMMON STOCK:

3 Months Ended

Mar. 31, 2012

Common Stock, Number of Shares, Par Value and Other Disclosures [Abstract]

Common Stock

COMMON STOCK

IDACORP Common Stock

During the three months endedMarch 31, 2012, IDACORP issued an aggregate of 128,088 shares of common stock pursuant to its IDACORP, Inc. Dividend Reinvestment and Stock Purchase Plan, Idaho Power Company Employee Savings Plan, IDACORP, Inc. Restricted Stock Plan, and IDACORP, Inc. 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 pursuant to a continuous equity program.  IDACORP's current sales agency agreement is with BNY Mellon Capital Markets, LLC. As of March 31, 2012, there were approximately 3 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 endedMarch 31, 2012.

Restrictions on Dividends

A covenant in each of 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 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, 2012, the leverage ratios for IDACORP and Idaho Power were 48 percent and 49 percent, respectively.  Based on these restrictions, IDACORP’s and Idaho Power’s dividends were limited to $836 million and $741 million, respectively, at March 31, 2012.  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, 2012, IDACORP and Idaho Power were in compliance with all facility covenants.

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. 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.

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.

In addition to contractual restrictions on the amount and payment of dividends, the Federal Power Act prohibits the payment of dividends from "capital accounts." The term "capital accounts" is undefined in the Federal Power Act, but if conservatively interpreted could limit the payment of dividends by Idaho Power to the amount of Idaho Power's retained earnings.

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SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES: Level 4 (Details) (USD $) In Millions, unless otherwise specified	3 Months Ended
	Mar. 31, 2012
Marysville Hydro Partners [Member]
Significant Accounting Policies
Variable Interest Entity, Qualitative or Quantitative Information, Ownership Percentage	50.00%
Variable Interest Entity Ownership Percentage of Partner	50.00%
Variable Interest Entity, Consolidated, Carrying Amount, Assets	$ 20
Variable interest entity consolidated intercompany long term debt	15
Bridger Coal Company
Significant Accounting Policies
Variable Interest Entity, Qualitative or Quantitative Information, Ownership Percentage	33.00%
Variable Interest Entity, Nonconsolidated, Carrying Amount, Assets and Liabilities, Net	97
Guarantor Obligations, Maximum Exposure, Undiscounted	63
IDACORP Financial Services Limited Partnership Interests [Member]
Significant Accounting Policies
Variable interest entities ownership percentage minimum	5.00%
Variable interest entities ownership percentage maximum	99.00%
Variable Interest Entity, Consolidated, Carrying Amount, Assets and Liabilities, Net	$ 60

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INVESTMENTS IN DEBT AND EQUITY SECURITIES:

3 Months Ended

Mar. 31, 2012

Investments [Abstract]

Investments in Debt and Equity Securities

INVESTMENTS IN 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.

The table below summarizes investments in equity securities by IDACORP and Idaho Power as of March 31, 2012 and December 31, 2011 (in thousands of dollars).

	March 31, 2012						December 31, 2011
	Gross Unrealized Gain		Gross Unrealized Loss		Fair Value		Gross Unrealized Gain		Gross Unrealized Loss		Fair Value
Available-for-sale securities	$	6,455	$	—	$	26,687	$	4,220	$	1	$	22,205

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, 2012, no securities were in an unrealized loss position. At December 31, 2011, one security was in an immaterial unrealized loss position. No other-than-temporary impairment was recognized for this security due to the limited severity and duration of the unrealized loss position.

There were no sales of available-for-sale securities during the three months endedMarch 31, 2012 or 2011.

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INCOME TAXES: Level 3 (Tables)

3 Months Ended

Mar. 31, 2012

Income Taxes [Abstract]

Schedule of Components of Income Tax Expense (Benefit) [Table Text Block]

Set forth below is a summary of income tax expense for the three months endedMarch 31 (in thousands of dollars):

	IDACORP						Idaho Power
	2012			2011			2012			2011
Income tax at statutory rates (federal and state)	$	13,006		$	13,540		$	14,128		$	14,483
Additional ADITC amortization	(825		)	(3,855		)	(825		)	(3,855		)
Other	(3,848		)	(4,797		)	(2,988		)	(3,435		)
Income tax expense	$	8,333		$	4,888		$	10,315		$	7,193
Effective tax rate	25.1		%	14.1		%	28.5		%	19.4		%

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COMMITMENTS: Level 4 (Details) (USD $)	3 Months Ended
	Mar. 31, 2012
Bridger Coal Company
Guarantor Obligations
IERCo ownership interest in BCC	33.00%
IERCo guarantee of BCC reclamation obligation	$ 63,000,000
Guarantor Obligations Total Reclamation Trust Fund	88,000,000
Idaho Power Company
Long-term Purchase Commitment
Reduction of Long-term Purchase Commitment, Amount	$ 90,000,000
Life of Contract	25 years

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Condensed Consolidated Balance Sheets Statement (USD $) In Thousands, unless otherwise specified	Mar. 31, 2012	Dec. 31, 2011
Current Assets:
Cash and cash equivalents	$ 8,857	$ 27,813
Receivables:
Customer	68,246	66,296
Other	14,102	8,197
Income taxes receivable	786	421
Accrued unbilled revenues	37,078	46,441
Materials and supplies (at average cost)	48,428	46,490
Fuel stock (at average cost)	56,531	47,865
Prepayments	11,323	12,405
Deferred income taxes	37,359	16,159
Current regulatory assets	35,958	34,279
Other	4,617	4,606
Total current assets	323,285	310,972
Investments	195,978	199,931
Property, Plant and Equipment:
Utility plant in service	4,476,618	4,466,873
Accumulated provision for depreciation	(1,696,788)	(1,677,609)
Utility plant in service - net	2,779,830	2,789,264
Construction work in progress	614,851	591,475
Utility plant held for future use	7,107	6,974
Other property, net of accumulated depreciation	18,817	18,877
Property, plant and equipment - net	3,420,605	3,406,590
Other Assets:
American Falls and Milner water rights	18,691	20,015
Company-owned life insurance	23,678	24,060
Regulatory assets	963,055	953,068
Long-term receivables	5,621	5,621
Other	39,708	40,352
Total other assets	1,050,753	1,043,116
Total	4,990,621	4,960,609
Current Liabilities:
Current maturities of long-term debt	1,064	101,064
Notes payable	63,000	54,200
Accounts payable	71,275	100,432
Income taxes accrued	2,837	505
Interest accrued	23,434	21,797
Current regulatory liabilities	49,487	29,738
Other	72,847	60,511
Total current liabilities	283,944	368,247
Other Liabilities:
Deferred income taxes	806,495	772,047
Regulatory liabilities	332,153	332,057
Pension and other postretirement benefits	335,456	363,209
Other	71,509	75,805
Total other liabilities	1,545,613	1,543,118
Long-Term Debt	1,486,568	1,387,550
Commitments and Contingencies
Equity:
Common stock	831,296	828,389
Retained earnings	849,327	840,916
Accumulated other comprehensive loss	(9,995)	(11,622)
Treasury stock	(60)	(29)
Total IDACORP, Inc. shareholders’ equity	1,670,568	1,657,654
Noncontrolling interests	3,928	4,040
Total equity	1,674,496	1,661,694
Total	4,990,621	4,960,609
Idaho Power Company
Current Assets:
Cash and cash equivalents	2,991	19,316
Receivables:
Customer	68,246	66,296
Other	13,925	8,011
Income taxes receivable	17,555	4,644
Accrued unbilled revenues	37,078	46,441
Materials and supplies (at average cost)	48,428	46,490
Fuel stock (at average cost)	56,531	47,865
Prepayments	11,093	12,274
Deferred income taxes	16,486	14,099
Current regulatory assets	35,958	34,279
Other	4,617	4,606
Total current assets	312,908	304,321
Property, Plant and Equipment:
Utility plant in service	4,476,618	4,466,873
Accumulated provision for depreciation	(1,696,788)	(1,677,609)
Utility plant in service - net	2,779,830	2,789,264
Construction work in progress	614,851	591,475
Utility plant held for future use	7,107	6,974
Property, plant and equipment - net	3,401,788	3,387,713
Investments and Other Property	127,295	128,674
Other Assets:
American Falls and Milner water rights	18,691	20,015
Company-owned life insurance	23,678	24,060
Regulatory assets	963,055	953,068
Other	38,385	38,988
Total other assets	1,043,809	1,036,131
Total	4,885,800	4,856,839
Current Liabilities:
Current maturities of long-term debt	1,064	101,064
Notes payable	1,500	0
Accounts payable	70,796	99,716
Accounts payable to affiliates	2,479	1,512
Interest accrued	23,434	21,797
Current regulatory liabilities	49,487	29,738
Other	72,411	59,785
Total current liabilities	221,171	313,612
Other Liabilities:
Deferred income taxes	898,786	863,044
Regulatory liabilities	332,153	332,057
Pension and other postretirement benefits	335,456	363,209
Other	69,070	73,147
Total other liabilities	1,635,465	1,631,457
Long-Term Debt	1,486,568	1,387,550
Commitments and Contingencies
Equity:
Common stock	97,877	97,877
Premium on capital stock	712,258	704,758
Capital stock expense	(2,097)	(2,097)
Retained earnings	744,553	735,304
Accumulated other comprehensive loss	(9,995)	(11,622)
Total equity	1,542,596	1,524,220
Total capitalization	3,029,164	2,911,770
Total	$ 4,885,800	$ 4,856,839

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Condensed Consolidated Statements of Capitalization Statement (USD $) In Thousands, unless otherwise specified	Mar. 31, 2012	Dec. 31, 2011
Common Stock Equity:
Common stock	$ 831,296	$ 828,389
Retained earnings	849,327	840,916
Accumulated other comprehensive loss	(9,995)	(11,622)
Total equity	1,674,496	1,661,694
Pollution control revenue bonds:
Total long-term debt	1,486,568	1,387,550
4.75% Series due 2012
Pollution control revenue bonds:
Debt Instrument, Interest Rate, Stated Percentage	4.75%
4.25% Series due 2013
Pollution control revenue bonds:
Debt Instrument, Interest Rate, Stated Percentage	4.25%
6.025% Series due 2018
Pollution control revenue bonds:
Debt Instrument, Interest Rate, Stated Percentage	6.025%
6.15% Series due 2019
Pollution control revenue bonds:
Debt Instrument, Interest Rate, Stated Percentage	6.15%
4.50% Series due 2020
Pollution control revenue bonds:
Debt Instrument, Interest Rate, Stated Percentage	4.50%
3.40% Series due 2020
Pollution control revenue bonds:
Debt Instrument, Interest Rate, Stated Percentage	3.40%
6.00% Series due 2032
Pollution control revenue bonds:
Debt Instrument, Interest Rate, Stated Percentage	6.00%
5.50% Series due 2033
Pollution control revenue bonds:
Debt Instrument, Interest Rate, Stated Percentage	5.50%
5.50% Series due 2034
Pollution control revenue bonds:
Debt Instrument, Interest Rate, Stated Percentage	5.50%
5.875% Series due 2034
Pollution control revenue bonds:
Debt Instrument, Interest Rate, Stated Percentage	5.875%
5.30% Series due 2035
Pollution control revenue bonds:
Debt Instrument, Interest Rate, Stated Percentage	5.30%
6.30% Series due 2037
Pollution control revenue bonds:
Debt Instrument, Interest Rate, Stated Percentage	6.30%
6.25% Series due 2037
Pollution control revenue bonds:
Debt Instrument, Interest Rate, Stated Percentage	6.25%
4.85% Series due 2040
Pollution control revenue bonds:
Debt Instrument, Interest Rate, Stated Percentage	4.85%
5.15% Pollution Control due 2024
Pollution control revenue bonds:
Debt Instrument, Interest Rate, Stated Percentage	5.15%
5.25% Pollution Control due 2026
Pollution control revenue bonds:
Debt Instrument, Interest Rate, Stated Percentage	5.25%
Idaho Power Company
Common Stock Equity:
Common stock	97,877	97,877
Premium on capital stock	712,258	704,758
Capital stock expense	(2,097)	(2,097)
Retained earnings	744,553	735,304
Accumulated other comprehensive loss	(9,995)	(11,622)
Total equity	1,542,596	1,524,220
First mortgage bonds:
Total first mortgage bonds	1,295,000	1,295,000
Amount due within one year	0	(100,000)
First mortgage bonds	1,295,000	1,195,000
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	5,318	6,382
Note guarantee due within one year	(1,064)	(1,064)
Unamortized premium/discount - net	(3,031)	(3,113)
Total long-term debt	1,486,568	1,387,550
Total capitalization	3,029,164	2,911,770
Idaho Power Company | 4.75% Series due 2012
First mortgage bonds:
First mortgage bonds	100,000	100,000
Pollution control revenue bonds:
Debt Instrument, Interest Rate, Stated Percentage	4.75%
Idaho Power Company | 4.25% Series due 2013
First mortgage bonds:
First mortgage bonds	70,000	70,000
Idaho Power Company | 6.025% Series due 2018
First mortgage bonds:
First mortgage bonds	120,000	120,000
Idaho Power Company | 6.15% Series due 2019
First mortgage bonds:
First mortgage bonds	100,000	100,000
Idaho Power Company | 4.50% Series due 2020
First mortgage bonds:
First mortgage bonds	130,000	130,000
Idaho Power Company | 3.40% Series due 2020
First mortgage bonds:
First mortgage bonds	100,000	100,000
Idaho Power Company | 6.00% Series due 2032
First mortgage bonds:
First mortgage bonds	100,000	100,000
Idaho Power Company | 5.50% Series due 2033
First mortgage bonds:
First mortgage bonds	70,000	70,000
Idaho Power Company | 5.50% Series due 2034
First mortgage bonds:
First mortgage bonds	50,000	50,000
Idaho Power Company | 5.875% Series due 2034
First mortgage bonds:
First mortgage bonds	55,000	55,000
Idaho Power Company | 5.30% Series due 2035
First mortgage bonds:
First mortgage bonds	60,000	60,000
Idaho Power Company | 6.30% Series due 2037
First mortgage bonds:
First mortgage bonds	140,000	140,000
Idaho Power Company | 6.25% Series due 2037
First mortgage bonds:
First mortgage bonds	100,000	100,000
Idaho Power Company | 4.85% Series due 2040
First mortgage bonds:
First mortgage bonds	$ 100,000	$ 100,000

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NOTES PAYABLE: Level 3 (Tables)

3 Months Ended

Mar. 31, 2012

Shedule of short term debt [Abstract]

Schedule of Short-term Debt

Balances and interest rates of IDACORP’s and Idaho Power's short-term borrowings were as follows at March 31, 2012 and December 31, 2011 (in thousands of dollars):

	March 31, 2012									December 31, 2011
	Idaho Power			IDACORP			Total			Idaho Power			IDACORP			Total
Commercial paper outstanding	$	1,500		$	61,500		$	63,000		$	—		$	54,200		$	54,200
Weighted-average annual interest rate	0.41		%	0.46		%	0.46		%	—		%	0.47		%	0.47		%

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NOTES PAYABLE: Level 4 (Details) (USD $)	Mar. 31, 2012	Dec. 31, 2011
Short-term borrowings:
Commercial paper outstanding	$ 63,000,000	$ 54,200,000
Weighted-average annual interest rate	0.46%	0.47%
IDACORP
Short-term borrowings:
Commercial paper outstanding	61,500,000	54,200,000
Weighted-average annual interest rate	0.46%	0.47%
Credit facility:
Credit facility	125,000,000
Swingline Loan, Maximum Principal Outstanding	15,000,000
Letter of Credit, Maximum Borrowing Capacity	50,000,000
Line of Credit Facility, Right to Increase Borrowing Capacity	150,000,000
Amount outstanding on credit facility	0
IDACORP | Federal Funds Rate
Credit facility:
Interest Rate Addition to Base Rate	0.50%
IDACORP | LIBOR Rate
Credit facility:
Interest Rate Addition to Base Rate	1.00%
Idaho Power Company
Short-term borrowings:
Commercial paper outstanding	1,500,000	0
Weighted-average annual interest rate	0.41%	0.00%
Credit facility:
Credit facility	300,000,000
Swingline Loan, Maximum Principal Outstanding	30,000,000
Line of Credit Facility, Right to Increase Borrowing Capacity	450,000,000
Amount outstanding on credit facility	0
Regulatory authority to incur short-term indebtedness	$ 450,000,000

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BENEFIT PLANS:

3 Months Ended

Mar. 31, 2012

General Discussion of Pension and Other Postretirement Benefits [Abstract]

Benefit Plans

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 defined benefit 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 table below 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
	2012			2011			2012		2011		2012			2011
Service cost	$	6,441		$	5,165		$	538	$	488	$	351		$	372
Interest cost	7,892			7,551			805		773		818			893
Expected return on plan assets	(7,712		)	(7,951		)	—		—		(604		)	(667		)
Amortization of transition obligation	—			—			—		—		510			510
Amortization of prior service cost	87			130			53		61		(105		)	(99		)
Amortization of net loss	3,463			2,094			382		323		143			171
Net periodic benefit cost	10,171			6,989			1,778		1,645		1,113			1,180
Costs not recognized due to the effects of regulation (1)	(5,389		)	(5,260		)	—		—		—			—
Net periodic benefit cost recognized for financial reporting (1)	$	4,782		$	1,729		$	1,778	$	1,645	$	1,113		$	1,180

⁽¹⁾  Net periodic benefit costs for the pension plan are recognized based upon the authorization of each regulatory jurisdiction Idaho Power operates within. Under IPUC order, income statement recognition of pension plan costs has been deferred until costs are recovered through rates. 

During the three months endedMarch 31, 2012, Idaho Power contributed $34 million to its pension plan, which is consistent with its total estimated pension contribution requirements for 2012.