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 September 30, 2011
	OR
	TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
	EXCHANGE ACT OF 1934
	For the transition period from __________ to __________
		Exact name of registrants as specified	I.R.S. Employer
Commission File		in their charters, address of principal	Identification
Number		executive offices, zip code and telephone number	Number
1-14465		IDACORP, Inc.	82-0505802
1-3198		Idaho Power Company	82-0130980
		1221 W. Idaho Street
		Boise, 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 October 28, 2011:
IDACORP, Inc.:	49,768,118
Idaho Power Company:	39,150,812, all held by IDACORP, Inc.

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

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

1

COMMONLY USED TERMS
The following select abbreviations or acronyms are commonly used in this report:
ADITC	-	Accumulated Deferred Investment Tax Credits
AFUDC	-	Allowance for Funds Used During Construction
AMI	-	Advanced Metering Infrastructure
APCU	-	Annual Power Cost Update
BCC	-	Bridger Coal Company, a joint venture of IERCo
CAA	-	Clean Air Act
CAMP	-	Comprehensive Aquifer Management Plan
DSR	-	Demand-Side Resources
EGUs	-	Electric Utility Steam Generating Units
EPA	-	United States Environmental Protection Agency
EPS	-	Earnings Per Share
ESPA	-	Eastern Snake Plain Aquifer
FASB	-	Financial Accounting Standards Board
FCA	-	Fixed Cost Adjustment Mechanism
FERC	-	Federal Energy Regulatory Commission
GHG	-	Greenhouse Gas
HAPs	-	Hazardous Air Pollutants
HCC	-	Hells Canyon Complex
Ida-West	-	Ida-West Energy, a subsidiary of IDACORP, Inc.
IE	-	IDACORP Energy, a subsidiary of IDACORP, Inc.
IERCo	-	Idaho Energy Resources Co., a subsidiary of Idaho Power Company
IFS	-	IDACORP Financial Services, a subsidiary of IDACORP, Inc.
IPUC	-	Idaho Public Utilities Commission
IRS	-	Internal Revenue Service
Joint Committee	-	U.S. Congress Joint Committee on Taxation
kW	-	Kilowatt
LCAR	-	Load Change Adjustment Rate
MD&A	-	Management’s Discussion and Analysis of Financial Condition and Results of Operations
MW	-	Megawatt
MWh	-	Megawatt-hour
NSPS	-	New Source Performance Standards
O&M	-	Operations and Maintenance
OATT	-	Open Access Transmission Tariff
OPUC	-	Oregon Public Utility Commission
PCA	-	Power Cost Adjustment
PCAM	-	Power Cost Adjustment Mechanism
PURPA	-	Public Utility Regulatory Policies Act of 1978
REC	-	Renewable Energy Certificate
RES	-	Renewable Energy Standard
SEC	-	Securities and Exchange Commission
SO2	-	Sulfur Dioxide
SRBA	-	Snake River Basin Adjudication
USBR	-	U.S. Bureau of Reclamation
Valmy	-	North Valmy Steam Electric Generating Plant
VIEs	-	Variable Interest Entities
WECC	-	Western Electricity Coordinating Council

2

TABLE OF CONTENTS
				Page
Part I.  Financial Information:
	Item 1.  Financial Statements (unaudited)
		IDACORP, Inc.:
			Condensed Consolidated Statements of Income	4
			Condensed Consolidated Balance Sheets	4
			Condensed Consolidated Statements of Cash Flows	6
			Condensed Consolidated Statements of Comprehensive Income	7
			Condensed Consolidated Statements of Equity	7
		Idaho Power Company:
			Condensed Consolidated Statements of Income	8
			Condensed Consolidated Balance Sheets	9
			Condensed Consolidated Statements of Capitalization	11
			Condensed Consolidated Statements of Cash Flows	12
			Condensed Consolidated Statements of Comprehensive Income	12
		Notes to the Condensed Consolidated Financial Statements		13
		Reports of Independent Registered Public Accounting Firm		30
	Item 2.  Management’s Discussion and Analysis of Financial Condition and Results of
			Operations	32
	Item 3.  Quantitative and Qualitative Disclosures About Market Risk			61
	Item 4.  Controls and Procedures			62
Part II.  Other Information:
	Item 1.  Legal Proceedings			62
	Item 1A.  Risk Factors			62
	Item 2.  Unregistered Sales of Equity Securities and Use of Proceeds			63
	Item 5.  Other Information			63
	Item 6.  Exhibits			64
Signatures				65
Exhibit Index				66

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 - FORWARD-LOOKING STATEMENTS,” in Part II, Item 1A - "RISK FACTORS," and in IDACORP, Inc.'s and Idaho Power Company's Annual Report on Form 10-K for the year ended December 31, 2010, at Part I, Item 1A - “RISK FACTORS” and Part II, Item 7 - “MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS.” Forward-looking statements are all statements other than statements of historical fact, including, without limitation, those that are identified by the use of the words "anticipates," "believes," "estimates," "expects," "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 September 30,						Nine months ended September 30,
	2011			2010			2011			2010
	(thousands of dollars except for per share amounts)
Operating Revenues:
Electric utility:
General business	$	252,313		$	266,270		$	649,881		$	674,293
Off-system sales	24,083			12,070			74,648			64,245
Other revenues	31,649			30,128			68,502			63,181
Total electric utility revenues	308,045			308,468			793,031			801,719
Other	1,585			889			3,076			2,354
Total operating revenues	309,630			309,357			796,107			804,073
Operating Expenses:
Electric utility:
Purchased power	66,141			62,227			127,658			113,750
Fuel expense	41,195			51,339			90,801			116,083
Power cost adjustment	(10,189		)	(20,934		)	36,618			55,461
Other operations and maintenance	84,562			71,939			240,695			219,159
Energy efficiency programs	18,504			19,549			31,011			33,348
Depreciation	30,115			29,137			89,272			86,446
Taxes other than income taxes	7,302			5,645			21,696			17,130
Total electric utility expenses	237,630			218,902			637,751			641,377
Other	607			1,462			2,573			3,051
Total operating expenses	238,237			220,364			640,324			644,428
Operating Income	71,393			88,993			155,783			159,645
Other Income, Net	6,010			3,550			15,589			11,042
Earnings (Losses) of Unconsolidated Equity-Method Investments	2,085			3,442			(3,657		)	1,444
Interest Expense:
Interest on long-term debt	19,499			20,135			59,850			59,003
Other interest, net of AFUDC	(2,053		)	(1,390		)	(5,876		)	(3,881		)
Total interest expense, net	17,446			18,745			53,974			55,122
Income Before Income Taxes	62,042			77,240			113,741			117,009
Income Tax (Benefit) Expense	(45,372		)	10,115			(44,137		)	(5,210		)
Net Income	107,414			67,125			157,878			122,219
Adjustment for (income) loss attributable to noncontrolling interests	(347		)	10			(170		)	188
Net Income Attributable to IDACORP, Inc.	$	107,067		$	67,135		$	157,708		$	122,407
Weighted Average Common Shares Outstanding - Basic (000’s)	49,520			48,086			49,411			47,917
Weighted Average Common Shares Outstanding - Diluted (000’s)	49,622			48,252			49,499			48,062
Earnings Per Share of Common Stock:
Earnings Attributable to IDACORP, Inc. - Basic	$	2.16		$	1.40		$	3.19		$	2.55
Earnings Attributable to IDACORP, Inc. - Diluted	$	2.16		$	1.39		$	3.19		$	2.55
Dividends Declared Per Share of Common Stock	$	0.30		$	0.30		$	0.90		$	0.90

The accompanying notes are an integral part of these statements.

IDACORP, Inc.

Condensed Consolidated Balance Sheets

(unaudited)

	September 30, 2011			December 31, 2010
	(thousands of dollars)
Assets
Current Assets:
Cash and cash equivalents	$	31,314		$	228,677
Receivables:
Customer (net of allowance of $1,378 and $1,499, respectively)	75,540			62,114
Other (net of allowance of $205 and $1,471, respectively)	10,693			10,157
Income taxes receivable	—			12,130
Accrued unbilled revenues	49,368			47,964
Materials and supplies (at average cost)	46,558			45,601
Fuel stock (at average cost)	49,742			27,547
Prepayments	11,245			11,063
Deferred income taxes	3,850			10,715
Current regulatory assets	26,438			6,216
Other	4,507			1,854
Total current assets	309,255			464,038
Investments	192,343			202,944
Property, Plant and Equipment:
Utility plant in service	4,451,427			4,332,054
Accumulated provision for depreciation	(1,669,123		)	(1,614,013		)
Utility plant in service - net	2,782,304			2,718,041
Construction work in progress	547,777			416,950
Utility plant held for future use	6,974			7,076
Other property, net of accumulated depreciation	18,991			19,315
Property, plant and equipment - net	3,356,046			3,161,382
Other Assets:
American Falls and Milner water rights	20,275			22,120
Company-owned life insurance	24,084			26,672
Regulatory assets	880,412			753,172
Long-term receivables (net of allowance of $3,304 and $1,861, respectively)	5,041			3,965
Other	39,479			41,762
Total other assets	969,291			847,691
Total	$	4,826,935		$	4,676,055

The accompanying notes are an integral part of these statements.

4

IDACORP, Inc.

Condensed Consolidated Balance Sheets

(unaudited)

	September 30, 2011			December 31, 2010
	(thousands of dollars)
Liabilities and Equity
Current Liabilities:
Current maturities of long-term debt	$	1,667		$	122,572
Notes payable	51,500			66,900
Accounts payable	90,088			103,100
Income taxes accrued	8,785			—
Interest accrued	23,388			23,937
Uncertain tax positions	—			74,436
Current regulatory liabilities	16,067			8,011
Other	62,966			50,103
Total current liabilities	254,461			449,059
Other Liabilities:
Deferred income taxes	750,001			566,473
Regulatory liabilities	332,675			298,094
Other	341,442			338,158
Total other liabilities	1,424,118			1,202,725
Long-Term Debt	1,487,468			1,488,287
Commitments and Contingencies
Equity:
IDACORP, Inc. shareholders’ equity:
Common stock, no par value (shares authorized 120,000,000;      49,774,042 and 49,419,452 shares issued, respectively)	820,271			807,842
Retained earnings	846,873			733,879
Accumulated other comprehensive loss	(10,268		)	(9,568		)
Treasury stock (11,675 and 14,302 shares at cost, respectively)	(29		)	(40		)
Total IDACORP, Inc. shareholders’ equity	1,656,847			1,532,113
Noncontrolling interests	4,041			3,871
Total equity	1,660,888			1,535,984
Total	$	4,826,935		$	4,676,055
The accompanying notes are an integral part of these statements.

5

IDACORP, Inc.

Condensed Consolidated Statements of Cash Flows

(unaudited)

	Nine months ended September 30,
	2011			2010
	(thousands of dollars)
Operating Activities:
Net income	$	157,878		$	122,219
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization	92,646			91,257
Deferred income taxes and investment tax credits	(54,340		)	37,095
Changes in regulatory assets and liabilities	55,044			50,338
Pension and postretirement benefit plan expense	17,279			10,474
Contributions to pension and postretirement benefit plans	(20,194		)	(64,269		)
Losses (earnings) of unconsolidated equity-method investments	3,657			(1,444		)
Distributions from unconsolidated equity-method investments	2,375			1,280
Allowance for equity funds used during construction	(18,264		)	(11,878		)
Other non-cash adjustments to net income, net	3,731			2,104
Change in:
Accounts receivable and prepayments	(12,121		)	9,652
Accounts payable and other accrued liabilities	(2,209		)	(5,786		)
Taxes accrued/receivable	31,472			(34,799		)
Other current assets	(24,556		)	2,914
Other current liabilities	1,375			21,591
Other assets	4,595			(3,443		)
Other liabilities	(3,458		)	(4,776		)
Net cash provided by operating activities	234,910			222,529
Investing Activities:
Additions to property, plant and equipment	(266,991		)	(249,437		)
Proceeds from the sale of utility assets	—			18,982
Proceeds from the sale of emission allowances and RECs	5,163			5,399
Investments in affordable housing	(955		)	(9,337		)
Other	2,435			3,826
Net cash used in investing activities	(260,348		)	(230,567		)
Financing Activities:
Issuance of long-term debt	—			200,000
Retirement of long-term debt	(121,064		)	(1,064		)
Dividends on common stock	(44,808		)	(43,213		)
Net change in short-term borrowings	(15,400		)	(49,750		)
Issuance of common stock	10,408			38,086
Acquisition of treasury stock	(1,933		)	(846		)
Other	872			(2,849		)
Net cash (used in) provided by financing activities	(171,925		)	140,364
Net (decrease) increase in cash and cash equivalents	(197,363		)	132,326
Cash and cash equivalents at beginning of the period	228,677			52,987
Cash and cash equivalents at end of the period	$	31,314		$	185,313
Supplemental Disclosure of Cash Flow Information:
Cash (received) paid during the period for:
Income taxes	$	(11,543	)	$	836
Interest (net of amount capitalized)	$	52,505		$	47,356
Non-cash investing activities:
Additions to property, plant and equipment in accounts payable	$	22,715		$	21,551
Investments in affordable housing	$	—		$	1,509

The accompanying notes are an integral part of these statements.

6

IDACORP, Inc.

Condensed Consolidated Statements of Comprehensive Income

(unaudited)

	Three months ended September 30,					Nine months ended September 30,
	2011			2010		2011			2010
	(thousands of dollars)
Net Income	$	107,414		$	67,125	$	157,878		$	122,219
Other Comprehensive Income:
Net unrealized holding (losses) gains arising during the period,   net of tax of ($1,259), $632, ($900), and $140	(1,961		)	984		(1,401		)	218
Unfunded pension liability adjustment, net of tax   of $150, $114, $450, and $341	234			177		701			532
Total Comprehensive Income	105,687			68,286		157,178			122,969
Comprehensive (income) loss attributable to noncontrolling interests	(347		)	10		(170		)	188
Comprehensive Income Attributable to IDACORP, Inc.	$	105,340		$	68,296	$	157,008		$	123,157

The accompanying notes are an integral part of these statements.

IDACORP, Inc.

Condensed Consolidated Statements of Equity

(unaudited)

	Nine months ended September 30,
	2011			2010
	(thousands of dollars)
Common Stock
Balance at beginning of period	$	807,842		$	756,475
Issued	10,408			38,086
Other	2,021			1,954
Balance at end of period	820,271			796,515
Retained Earnings
Balance at beginning of period	733,879			649,180
Net income attributable to IDACORP, Inc.	157,708			122,407
Common stock dividends ($0.90 per share)	(44,714		)	(43,321		)
Balance at end of period	846,873			728,266
Accumulated Other Comprehensive (Loss) Income
Balance at beginning of period	(9,568		)	(8,267		)
Unrealized (loss) gain on securities (net of tax)	(1,401		)	218
Unfunded pension liability adjustment (net of tax)	701			532
Balance at end of period	(10,268		)	(7,517		)
Treasury Stock
Balance at beginning of period	(40		)	(53		)
Issued	1,944			882
Acquired	(1,933		)	(846		)
Balance at end of period	(29		)	(17		)
Total IDACORP, Inc. shareholders’ equity at end of period	1,656,847			1,517,247
Noncontrolling Interests
Balance at beginning of period	3,871			4,209
Net income (loss) attributable to noncontrolling interests	170			(188		)
Balance at end of period	4,041			4,021
Total equity at end of period	$	1,660,888		$	1,521,268

The accompanying notes are an integral part of these statements.

7

Idaho Power Company

Condensed Consolidated Statements of Income

(unaudited)

	Three months ended September 30,						Nine months ended September 30,
	2011			2010			2011			2010
	(thousands of dollars)
Operating Revenues:
General business	$	252,313		$	266,270		$	649,881		$	674,293
Off-system sales	24,083			12,070			74,648			64,245
Other revenues	31,649			30,128			68,502			63,181
Total operating revenues	308,045			308,468			793,031			801,719
Operating Expenses:
Operation:
Purchased power	66,141			62,227			127,658			113,750
Fuel expense	41,195			51,339			90,801			116,083
Power cost adjustment	(10,189		)	(20,934		)	36,618			55,461
Other operations and maintenance	84,562			71,939			240,695			219,159
Energy efficiency programs	18,504			19,549			31,011			33,348
Depreciation	30,115			29,137			89,272			86,446
Taxes other than income taxes	7,302			5,645			21,696			17,130
Total operating expenses	237,630			218,902			637,751			641,377
Income from Operations	70,415			89,566			155,280			160,342
Other Income (Expense):
Allowance for equity funds used during construction	6,570			3,858			18,264			11,878
Earnings of unconsolidated equity-method investments	3,741			5,402			1,172			7,738
Other expense, net	(293		)	(766		)	(2,669		)	(1,937		)
Total other income	10,018			8,494			16,767			17,679
Interest Charges:
Interest on long-term debt	19,499			20,135			59,850			59,003
Other interest	1,026			852			3,551			2,883
Allowance for borrowed funds used during construction	(3,188		)	(2,303		)	(9,777		)	(7,781		)
Total interest charges	17,337			18,684			53,624			54,105
Income Before Income Taxes	63,096			79,376			118,423			123,916
Income Tax (Benefit) Expense	(41,776		)	14,726			(36,997		)	2,216
Net Income	$	104,872		$	64,650		$	155,420		$	121,700

The accompanying notes are an integral part of these statements.

8

Idaho Power Company

Condensed Consolidated Balance Sheets

(unaudited)

	September 30, 2011			December 31, 2010
	(thousands of dollars)
Assets
Electric Plant:
In service (at original cost)	$	4,451,427		$	4,332,054
Accumulated provision for depreciation	(1,669,123		)	(1,614,013		)
In service - net	2,782,304			2,718,041
Construction work in progress	547,777			416,950
Held for future use	6,974			7,076
Electric plant - net	3,337,055			3,142,067
Investments and Other Property	116,124			120,641
Current Assets:
Cash and cash equivalents	24,993			224,233
Receivables:
Customer (net of allowance of $1,378 and $1,499, respectively)	75,540			62,114
Other (net of allowance of $205 and $142, respectively)	10,577			8,835
Income taxes receivable	—			21,063
Accrued unbilled revenues	49,368			47,964
Materials and supplies (at average cost)	46,558			45,601
Fuel stock (at average cost)	49,742			27,547
Prepayments	11,132			10,910
Deferred income taxes	3,837			7,334
Current regulatory assets	26,438			6,216
Other	4,507			1,238
Total current assets	302,692			463,055
Deferred Debits:
American Falls and Milner water rights	20,275			22,120
Company-owned life insurance	24,084			26,672
Regulatory assets	880,412			753,172
Other	38,531			40,666
Total deferred debits	963,302			842,630
Total	$	4,719,173		$	4,568,393

The accompanying notes are an integral part of these statements.

9

Idaho Power Company

Condensed Consolidated Balance Sheets

(unaudited)

	September 30, 2011			December 31, 2010
	(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	688,758			688,758
Capital stock expense	(2,097		)	(2,097		)
Retained earnings	740,911			630,259
Accumulated other comprehensive loss	(10,268		)	(9,568		)
Total common stock equity	1,515,181			1,405,229
Long-term debt	1,487,468			1,488,287
Total capitalization	3,002,649			2,893,516
Current Liabilities:
Long-term debt due within one year	1,064			121,064
Accounts payable	89,615			102,474
Accounts payable to related parties	1,812			1,110
Income taxes accrued	3,986			—
Interest accrued	23,388			23,930
Uncertain tax positions	—			74,436
Current regulatory liabilities	16,067			8,011
Other	62,316			48,733
Total current liabilities	198,248			379,758
Deferred Credits:
Deferred income taxes	846,324			661,165
Regulatory liabilities	332,675			298,094
Other	339,277			335,860
Total deferred credits	1,518,276			1,295,119
Commitments and Contingencies
Total	$	4,719,173		$	4,568,393
The accompanying notes are an integral part of these statements.

10

Idaho Power Company

Condensed Consolidated Statements of Capitalization

(unaudited)

	September 30, 2011			December 31, 2010
	(thousands of dollars)
Common Stock Equity:
Common stock	$	97,877		$	97,877
Premium on capital stock	688,758			688,758
Capital stock expense	(2,097		)	(2,097		)
Retained earnings	740,911			630,259
Accumulated other comprehensive loss	(10,268		)	(9,568		)
Total common stock equity	1,515,181			1,405,229
Long-Term Debt:
First mortgage bonds:
6.60% Series due 2011	—			120,000
4.75% Series due 2012	100,000			100,000
4.25% Series due 2013	70,000			70,000
6.025% Series due 2018	120,000			120,000
6.15% Series due 2019	100,000			100,000
4.50 % Series due 2020	130,000			130,000
3.40% Series due 2020	100,000			100,000
6    % Series due 2032	100,000			100,000
5.50% Series due 2033	70,000			70,000
5.50% Series due 2034	50,000			50,000
5.875% Series due 2034	55,000			55,000
5.30% Series due 2035	60,000			60,000
6.30% Series due 2037	140,000			140,000
6.25% Series due 2037	100,000			100,000
4.85% Series due 2040	100,000			100,000
Total first mortgage bonds	1,295,000			1,415,000
Amount due within one year	—			(120,000		)
Net first mortgage bonds	1,295,000			1,295,000
Pollution control revenue bonds:
5.15% Series due 2024	49,800			49,800
5.25% Series due 2026	116,300			116,300
Variable Rate Series 2000 due 2027	4,360			4,360
Total pollution control revenue bonds	170,460			170,460
American Falls bond guarantee	19,885			19,885
Milner Dam note guarantee	6,382			7,446
Note guarantee due within one year	(1,064		)	(1,064		)
Unamortized premium/discount - net	(3,195		)	(3,440		)
Total long-term debt	1,487,468			1,488,287
Total Capitalization	$	3,002,649		$	2,893,516

The accompanying notes are an integral part of these statements.

11

Idaho Power Company

Condensed Consolidated Statements of Cash Flows

(unaudited)

	Nine months ended September 30,
	2011			2010
	(thousands of dollars)
Operating Activities:
Net income	$	155,420		$	121,700
Adjustments to reconcile net income to net cash provided by
operating activities:
Depreciation and amortization	92,232			90,785
Deferred income taxes and investment tax credits	(56,078		)	67,516
Changes in regulatory assets and liabilities	55,044			50,338
Pension and postretirement benefit plan expense	17,279			10,474
Contributions to pension and postretirement benefit plans	(20,194		)	(64,269		)
Earnings of unconsolidated equity-method investments	(1,172		)	(7,738		)
Distributions from unconsolidated equity-method investments	1,075			455
Allowance for equity funds used during construction	(18,264		)	(11,878		)
Other non-cash adjustments to net income	1,383			(729		)
Change in:
Accounts receivables and prepayments	(12,213		)	8,830
Accounts payable	(2,120		)	(5,652		)
Taxes accrued/receivable	35,496			(80,853		)
Other current assets	(24,556		)	2,914
Other current liabilities	1,375			21,590
Other assets	4,595			(3,443		)
Other liabilities	(2,702		)	(4,206		)
Net cash provided by operating activities	226,600			195,834
Investing Activities:
Additions to utility plant	(266,991		)	(249,437		)
Proceeds from the sale of utility assets	—			18,982
Proceeds from the sale of emission allowances and RECs	5,163			5,399
Other	1,820			3,274
Net cash used in investing activities	(260,008		)	(221,782		)
Financing Activities:
Issuance of long-term debt	—			200,000
Retirement of long-term debt	(121,064		)	(1,064		)
Dividends on common stock	(44,768		)	(43,325		)
Capital contribution from parent	—			30,000
Other	—			(2,746		)
Net cash (used in) provided by financing activities	(165,832		)	182,865
Net (decrease) increase in cash and cash equivalents	(199,240		)	156,917
Cash and cash equivalents at beginning of the period	224,233			21,625
Cash and cash equivalents at end of the period	$	24,993		$	178,542
Supplemental Disclosure of Cash Flow Information:
Cash (received) paid during the period for:
Income taxes	$	(6,689	)	$	21,815
Interest (net of amount capitalized)	$	52,148		$	46,338
Non-cash investing activities:
Additions to property, plant and equipment in accounts payable	$	22,715		$	21,551

The accompanying notes are an integral part of these statements.

Idaho Power Company

Condensed Consolidated Statements of Comprehensive Income

(unaudited)

	Three months ended September 30,					Nine months ended September 30,
	2011			2010		2011			2010
	(thousands of dollars)
Net Income	$	104,872		$	64,650	$	155,420		$	121,700
Other Comprehensive Income:
Net unrealized holding (losses) gains arising during the period,   net of tax of ($1,259), $632, ($900), and $140	(1,961		)	984		(1,401		)	218
Unfunded pension liability adjustment, net of tax   of $150, $114, $450, and $341	234			177		701			532
Total Comprehensive Income	$	103,145		$	65,811	$	154,720		$	122,450

The accompanying notes are an integral part of these statements.

12

IDACORP, INC. AND IDAHO POWER COMPANY

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(unaudited)

1.  SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

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

Nature of Business

IDACORP is a holding company formed in 1998 whose principal operating subsidiary is Idaho Power.  Idaho Power is an electric utility with a service territory covering approximately 24,000 square miles in southern Idaho and eastern Oregon.  Idaho Power is regulated by the Federal Energy Regulatory Commission (FERC) and the state regulatory commissions of Idaho and Oregon.  Idaho Power is the parent of Idaho Energy Resources Co. (IERCo), a joint venturer in Bridger Coal Company (BCC), which mines and supplies coal to the Jim Bridger generating plant owned in part by Idaho Power.

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

Principles of Consolidation

IDACORP’s and Idaho Power’s consolidated financial statements include the accounts of each company, the subsidiaries that the companies control, and any variable interest entities (VIEs) for which the companies are the primary beneficiaries.  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 $16 million of intercompany long-term debt, which is eliminated in consolidation.  EEC has borrowed amounts from Ida-West to fund a portion of its required capital contributions to Marysville.  The loans are payable from EEC’s share of distributions and are secured by the stock of EEC and EEC’s interest in Marysville.  Ida-West is the primary beneficiary because the ownership of the intercompany note and the EEC note result in it controlling the entity.  Creditors of Marysville have no recourse to the general credit of IDACORP and there are no other arrangements that could require IDACORP to provide financial support to Marysville or expose IDACORP to losses.

Through IERCo, Idaho Power holds a variable interest in BCC, a VIE for which it is not the primary beneficiary.  IERCo is not the primary beneficiary because the power to direct the activities that most significantly impact the economic performance of BCC is shared with the joint venture partner.  The carrying value of BCC is $91 million at September 30, 2011, 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 – “Commitments.”

Through IFS, IDACORP also holds variable interests in VIEs for which it is not the primary beneficiary.  These VIEs are affordable housing developments and other real estate investments in which IFS holds limited partnership interests ranging from 5 to 99 percent.  As a limited partner, IFS does not control these entities and they are not consolidated.  These investments were acquired between 1996 and 2010.  IFS’s maximum exposure to loss in these developments is limited to its net carrying value, which was $66 million at September 30, 2011.

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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 positions as of September 30, 2011, consolidated results of operations for the three and nine months endedSeptember 30, 2011 and 2010, and consolidated cash flows for the nine months endedSeptember 30, 2011 and 2010.  These adjustments are of a normal and recurring nature.  These financial statements do not contain the complete detail or footnote disclosure concerning accounting policies and other matters that would be included in full-year financial statements and should be read in conjunction with the audited consolidated financial statements included in IDACORP’s and Idaho Power’s Annual Report on Form 10-K for the year ended December 31, 2010.  The results of operations for the interim periods are not necessarily indicative of the results to be expected for the full year.

Use of Estimates

The preparation of condensed consolidated financial statements in accordance with generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and 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.

Reclassifications

Certain prior year amounts have been reclassified to conform to the current year presentation, including amounts related to regulatory assets and liabilities in the condensed consolidated balance sheets.  Net income, cash flows, and shareholders' equity were not affected by these reclassifications.

New Accounting Pronouncements

The Financial Accounting Standards Board (FASB) has issued the following accounting guidance, which is effective for periods beginning after December 15, 2011:

• In May 2011, the FASB issued guidance to provide a consistent definition of fair value and ensure that the fair value measurement and disclosure requirements are similar between generally accepted accounting principles in the United States and International Financial Reporting Standards. The guidance changes certain fair value measurement principles and enhances the disclosure requirements, particularly for Level 3 fair value measurements. IDACORP and Idaho Power are currently assessing the impact of the guidance but do not believe that the adoption of this guidance will have a material effect on their consolidated financial statements.

• In June 2011, the FASB issued guidance on the presentation of comprehensive income in an entity's financial statements. The guidance requires that comprehensive income be presented either in one continuous statement or in two separate but consecutive statements presenting the components of net income and its total, the components of other comprehensive income and its total, and total comprehensive income. The guidance also requires that reclassification adjustments from other comprehensive income to net income be presented in both the components of net income and the components of other comprehensive income. IDACORP and Idaho Power do not expect the adoption of this guidance to have a material effect on their consolidated financial statements.

2.  INCOME TAXES

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

14

Income Tax Expense

An analysis of income tax expense (benefit) for the three and nine months endedSeptember 30 is as follows (in thousands of dollars):

	IDACORP						Idaho Power
	2011			2010			2011			2010
Three months ended September 30,
Income tax at statutory rates (federal and state)	$	24,123		$	30,204		$	24,671		$	31,036
Additional ADITC amortization reversal	6,750			—			6,750			—
Accounting method change	—			(7,374		)	—			(7,374		)
Examination settlement - uniform capitalization	(56,898		)	—			(56,898		)	—
Other	(19,347		)	(12,715		)	(16,299		)	(8,936		)
Income tax (benefit) expense	$	(45,372	)	$	10,115		$	(41,776	)	$	14,726
Effective tax rate	(73.5		)%	13.1		%	(66.2		)%	18.6		%
Nine months ended September 30,
Income tax at statutory rates (federal and state)	$	44,407		$	45,824		$	46,303		$	48,451
Accounting method change	—			(32,561		)	—			(32,561		)
Examination settlement - capitalized repairs	(3,428		)	—			(3,428		)	—
Examination settlement - uniform capitalization	(56,898		)	—			(56,898		)	—
Other	(28,218		)	(18,473		)	(22,974		)	(13,674		)
Income tax (benefit) expense	$	(44,137	)	$	(5,210	)	$	(36,997	)	$	2,216
Effective tax rate	(38.9		)%	(4.4		)%	(31.2		)%	1.8		%

The changes in year-to-date 2011 income tax expense as compared to the same period in 2010 were primarily due to an income tax benefit in 2010 related to Idaho Power's tax accounting method change for capitalized repair expenditures, an income tax benefit in 2011 related to the examination settlement of Idaho Power's uniform capitalization method, increased 2011 flow-through tax adjustments related to both methods, and lower 2011 pre-tax earnings. Other net regulatory flow-through tax adjustments at Idaho Power and tax credits at IFS for the nine months endedSeptember 30, 2011 were comparable to the same period in 2010.

Idaho Power's January 2010 settlement agreement with the Idaho Public Utilities Commission (IPUC) and other parties 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 2009 to 2011.  Idaho Power has up to $25 million of additional ADITC amortization available for use in 2011 under the settlement agreement. In the third quarter of 2011, Idaho Power reversed $6.8 million of additional ADITC amortization previously recorded in the first six months of 2011, based on itsestimate that 2011 Idaho jurisdictional return on year-end equity will exceed 9.5 percent.

Status of Audit Proceedings and Tax Method Changes

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

In April 2011, IDACORP and the IRS reached an agreement on Idaho Power's tax accounting method change for capitalized repairs. Accordingly, the IRS finalized the 2009 examination and submitted its report on the 2009 tax year to the Joint Committee for review. Idaho Power considers the capitalized repairs method effectively settled and believes that no material income tax uncertainties remain for the method. As such, Idaho Power recognized $3.4 million of its previously unrecognized tax benefits for this method in the second quarter of 2011.

15

In September 2011, the IRS notified IDACORP that the Joint Committee had completed its review and approved the uniform capitalization method agreement. Idaho Power considers the uniform capitalization method effectively settled and believes that no material income tax uncertainties remain for the method. Accordingly, Idaho Power recognized $56.9 million of its previously unrecognized tax benefits for tax years 2009 and prior in the third quarter of 2011. Idaho Power also increased its uniform capitalization tax deduction estimate in its current year tax provision, which resulted in an additional $2.0 million income tax benefit for the nine months ended September 30, 2011.

Completion of the Joint Committee review allowed the IRS to finalize its 2009 examination, process the income tax changes, and close the case prior to September 30, 2011. In the fourth quarter of 2011, IDACORP and Idaho Power will pay previously accrued income tax liabilities of $3.9 million and $8.1 million, respectively, related to the capitalized repairs examination agreement. The difference in liabilities is due to IDACORP's utilization of deferred federal general business tax credits and Idaho investment tax credits. There are no 2011 cash impacts related to the uniform capitalization method settlement as income tax refunds for the method change were received in 2010. In early 2011, IDACORP requested and received the return of $13 million of previously made estimated tax payments for the 2010 tax year.

3.  REGULATORY MATTERS

Recent and Pending Idaho Regulatory Matters

Idaho General Rate Case

On June 1, 2011, Idaho Power filed with the IPUC a general rate case and proposed rate schedules for its Idaho jurisdiction, Case No. IPC-E-11-08. The filing was based on a 2011 test year and requested approximately $82.6 million in additional Idaho jurisdiction annual revenues in base rates, a 9.9 percent overall average rate increase for Idaho customers. The filing requested an authorized rate of return on equity of 10.5 percent (an overall 8.17 percent rate of return in the Idaho jurisdiction) on an Idaho retail rate base of approximately $2.4 billion, and the following additional items:

• Authority to treat demand response incentive payments (payments Idaho Power has made in connection with certain energy efficiency activities) as power supply expenses and establish a base or "normal" level of cost recovery for those payments in base rates. Idaho Power included approximately $11.3 million associated with forecasted fixed demand response incentive payments for 2011 in the Idaho jurisdictional revenue requirement calculations included in the general rate case application, which would be subject to true-up under the Idaho PCA mechanism.

• Approval of the current fixed cost adjustment (FCA) mechanism pilot program as a permanent rate mechanism for residential and small commercial class customers. The FCA allows Idaho Power to recover the difference between certain fixed costs recovered and the fixed costs authorized for recovery in Idaho Power's most recent rate case.  

• An updated load change adjustment rate (LCAR) of $19.28 per megawatt-hour (MWh). The LCAR adjusts power supply cost recovery within the Idaho power cost adjustment (PCA) formula by adjusting recovery upwards or downwards for differences between actual load and the load used in calculating base rates.

On September 23, 2011, Idaho Power, the Staff of the IPUC, 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. The settlement stipulation is subject to approval by the IPUC.

The settlement stipulation provides that Idaho Power would implement revised tariff schedules designed to recover $34.0 million in additional annual revenue from Idaho jurisdictional base rates effective January 1, 2012, representing a 4.07 percent overall average increase in Idaho Power's annual Idaho jurisdictional base rate revenues. The $34.0 million of additional annual revenue is inclusive of approximately $11.3 million of base level demand response incentive payments (made in connection with certain energy efficiency activities) to be tracked as part of the Idaho PCA mechanism. The settlement stipulation also provides that approximately $23 million of Idaho jurisdictional revenue associated with the recovery of power supply expenses from PURPA projects would not be included in base rates, but would instead be eligible for 100 percent recovery through the PCA mechanism. The settlement stipulation also provides for a 7.86 percent authorized rate of return on an Idaho jurisdictional rate base of approximately $2.4 billion, and for the IPUC to allow Idaho Power to earn an authorized rate of return of 7.86 percent in any Idaho Power regulatory matter until subsequently changed by IPUC order.

16

The settlement stipulation provides for an LCAR of $18.16 per MWh, compared to the rate of $19.67 per MWh in effect on the date of filing of the general rate case, to become effective on the date that Idaho Power's new base rates become effective. The settlement stipulation provides that the determination of whether the FCA pilot program should be made permanent and the appropriate percentage amount for Idaho Power's energy efficiency rider would be examined in subsequent proceedings.

The parties to the settlement stipulation have requested that the IPUC issue an order approving the agreed-upon rates effective January 1, 2012. If the IPUC were to deny the settlement stipulation or materially change its terms, no party would be bound by the terms of the stipulation. Idaho Power is unable to predict whether the IPUC will approve the settlement stipulation or the ultimate outcome of the general rate case proceedings.

January 2010 Idaho Settlement Agreement and 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 of any Idaho jurisdiction earnings exceeding a return on year-end equity of 10.5 percent in the Idaho jurisdiction.  Recognition of tax benefits in the third quarter of 2011, discussed in further detail in Note 2, had a significant impact on Idaho Power's estimate of return on 2011 year-end equity and contributed to triggering of the sharing mechanism under the January 2010 settlement agreement. As a result of the terms of the settlement agreement, Idaho Power also recorded an $18.1 million regulatory liability, reflecting 50 percent of Idaho Power's estimated Idaho jurisdictional earnings over a 10.5 percent return on year-end equity required to be shared with customers.

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, with the following terms:

• If Idaho Power's Idaho jurisdiction return on year-end equity for 2012 or 2013 is less than 9.5 percent, then Idaho Power may continue to use up to $45 million of deferred investment tax credits to help achieve a minimum 9.5 percent return on year-end equity in the Idaho jurisdiction in those years. Idaho Power may use an aggregate of $45 million of additional ADITC in 2012 and 2013, comprised of up to a maximum of $25 million of additional ADITC in 2012 and any unused portion carried forward to 2013.

• If Idaho Power's Idaho jurisdictional return on year-end equity for 2012 or 2013 exceeds 10.0 percent, the amount exceeding 10.0 percent would be shared equally between Idaho Power and its customers in the applicable year.

• Idaho Power would allocate to customers 50 percent of Idaho Power's share of estimated 2011 Idaho jurisdictional earnings over a 10.5 percent return on year-end equity, reflected as a reduction in customer rates or an offset to amounts that would otherwise be collected from rates.

The application provides that it is independent and separate from the 2011 general rate case proceeding and the associated settlement stipulation, and further provides that Idaho Power will withdraw the application in the event Idaho Power's base rate revenues are not increased in accordance with the terms of the general rate case settlement stipulation. The application also states that Idaho Power's proposal to apply a one-time adjustment to the 2011 sharing calculation is contingent on the completion of a signed settlement stipulation agreeing to the extension and modification of the ADITC amortization and sharing mechanisms, as described above, on or before December 31, 2011.

Idaho Power Cost Adjustment Order

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

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

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

17

On May 31, 2011, the IPUC issued an order approving Idaho Power's requested $40.4 million Idaho PCA rate decrease, with the new PCA rates effective for the period from June 1, 2011 to May 31, 2012. The reduction to Idaho PCA rates was net of $10.0 million of Idaho Power’s energy efficiency rider deferral balance that the IPUC had previously authorized for recovery in Idaho Power’s Idaho PCA rates.

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

On May 31, 2011, the IPUC issued an order revising the LCAR used in PCA calculations to $19.67 per MWh (through a June 1, 2011 errata), effective as of April 1, 2011. The September 23, 2011 general rate case settlement stipulation, if approved, would result in an LCAR of $18.16 per MWh, effective January 1, 2012.

Fixed Cost Adjustment Mechanism

On March 15, 2011, Idaho Power filed an application with the IPUC requesting authorization to implement revised FCA rates for electric service from June 1, 2011 through May 31, 2012.  Idaho Power's application requested an aggregate increase of $3.0 million in FCA rates for the residential and small general service customer classes in its Idaho jurisdiction. On May 31, 2011, the IPUC issued an order approving Idaho Power's application, with the $3.0 million FCA rate increase to be effective for the period from June 1, 2011 to May 31, 2012. On October 19, 2011, Idaho Power filed an application with the IPUC requesting that the FCA pilot program become a permanent rate mechanism for residential and small general service customer classes. The FCA pilot program is set to expire on December 31, 2011.

Recovery of Defined Benefit Pension Plan Contributions

In September 2010, Idaho Power elected to make a $60 million contribution to its defined benefit pension plan, rather than the minimum required funding amount, to bring the defined benefit pension plan to a more funded position, potentially reducing future required contributions and Pension Benefit Guaranty Corporation premiums.  On March 15, 2011, Idaho Power filed an application with the IPUC requesting an increase in the amount included in base rates for recovery of the Idaho-allocated portion of Idaho Power's cash contributions to its defined benefit pension plan from the then-current amount of $5.4 million to approximately $17.1 million annually. The requested increase was intended to recover the balance of the Idaho jurisdictional allocation of the $60 million pension contribution over a three year period.  On May 19, 2011, the IPUC approved Idaho Power’s application, with new rates effective on June 1, 2011.

Energy Efficiency and Demand Response Programs

Idaho Power has implemented and/or manages a wide range of opportunities for its customers to participate in energy efficiency and demand response programs.  On August 18, 2011, the IPUC issued an order approving Idaho Power's March 2011 application requesting that the IPUC designate Idaho Power's 2010 Idaho energy efficiency rider expenditures of approximately $42 million as prudently incurred expenses.

On October 22, 2010, Idaho Power filed an application with the IPUC requesting acceptance of the company's demand-side resources (DSR) business model, which included a request for authorization to (a) move demand response incentive payments out of the energy efficiency rider and into the Idaho PCA on a prospective basis beginning on June 1, 2011, and thus subject to a true-up under the PCA mechanism; (b) establish a regulatory asset for the direct incentive payments associated with Idaho Power's energy efficiency program for large commercial and industrial customers, beginning January 1, 2011, so that Idaho Power may capitalize the direct incentive payments associated with the program, include the costs associated with the program incentive payments in its rate base, and thus earn a rate of return on a portion of its DSR activities; and (c) change the carrying charge on the existing energy efficiency rider balancing account (from the then-current interest rate of 1.0 percent to Idaho Power's authorized rate of return). On April 1, 2011, the IPUC issued an order stating that certain issues raised in the application are more properly considered in a general rate case proceeding. However, the IPUC noted in its order that Idaho Power's energy efficiency rider balance includes approximately $10 million in expenditures that have been previously approved by the IPUC for recovery, and thus authorized recovery of $10 million of the rider balance in Idaho Power's Idaho PCA rates, beginning June 1, 2011. The IPUC did not approve a change to the energy efficiency rider balance carrying charge.

On May 17, 2011, the IPUC issued an order stating that it will allow Idaho Power to account for specified direct incentive payments associated with Idaho Power's energy efficiency program for large commercial and industrial customers as a regulatory asset beginning January 1, 2011, but with an amortization period to be determined later by the IPUC.

18

In its June 1, 2011 general rate case filing, Idaho Power requested authorization to treat demand response incentive payments as power supply costs and establish a base or "normal" level of cost recovery of approximately $11.3 million for those demand response incentive payments in rates. The Idaho general rate case settlement stipulation filed with the IPUC on September 23, 2011 provides that the $11.3 million of base level demand response incentive payments would be tracked as part of the Idaho PCA mechanism.

Transmission Rate Refunds and Shortfall Filing

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

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

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 requests a $5.8 million increase in annual Oregon jurisdictional revenues which, if approved, would result in a 14.7 percent overall average rate increase for customers in the Oregon jurisdiction. The filing requests an authorized rate of return on equity of 10.5 percent with an Oregon retail rate base of approximately $121.9 million, and a rate of return on capital of 8.17 percent. Idaho Power is unable to predict the outcome of the general rate case but anticipates that new rates, if approved by the OPUC, would not become effective until June 1, 2012.

Oregon Power Cost Adjustment Mechanism Filings

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

The APCU allows Idaho Power to reestablish its Oregon base net power supply costs annually, separate from a general rate case, and to forecast net power supply costs for the upcoming water year.  The APCU has two components:  the “October Update,” Idaho Power's calculation of estimated normalized net power supply costs for the following April through March test period, and the “March Forecast,” Idaho Power's forecast of expected net power supply costs for the same test period, updated for a number of variables including the most recent stream flow data and future wholesale electric prices. On May 31, 2011, the OPUC approved Idaho Power's March 2011 request for a $0.9 million annual decrease in amounts collected through Oregon jurisdiction customer rates, with new rates effective June 1, 2011. On October 20, 2011, Idaho Power filed the October Update portion of the APCU, requesting a $1.4 million increase in amounts collected through Oregon jurisdiction customer rates, effective June 1, 2012.

The PCAM is a true-up filed annually in February.  The filing calculates the deviation between actual net power supply costs incurred for the preceding calendar year and the net power supply costs recovered through the APCU for the same period.  Under the PCAM, Idaho Power is subject to a portion of the business risk or benefit associated with this deviation through application of an asymmetrical deadband (or range of deviations) within which Idaho Power absorbs cost increases or decreases.  On February 28, 2011, Idaho Power submitted its 2010 PCAM true-up, stating that actual net power supply costs were within the deadband, resulting in no deferral. 

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Annual OATT Update

On September 1, 2011, Idaho Power filed its 2011 Final Informational Filing (FIF) for its OATT with the FERC and posted the FIF on its Open Access Same-Time Information System (OASIS) Internet platform, for rates that became effective on October 1, 2011 for a one-year period. The FIF is the computation of Idaho Power’s transmission formula rate for service under its OATT, which is updated annually. The new rate posted by Idaho Power was $19.79 per kW/yr, reflective of a $107 million net annual transmission revenue requirement. The previous OATT rate was $19.60 per kW/yr.

4.  LONG-TERM DEBT

As of September 30, 2011, 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.  As of September 30, 2011, $300 million remained on Idaho Power’s shelf registration for the issuance of first mortgage bonds and debt securities.

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

5.  NOTES PAYABLE

Credit Facilities

On October 26, 2011, each of IDACORP and Idaho Power entered into a Second Amended and Restated Credit Agreement with Wells Fargo Bank, National Association, as administrative agent, swingline lender, and LC issuer; JPMorgan Chase Bank, N.A., as syndication agent and LC issuer; KeyBank National Association and Union Bank, N.A., as documentation agents; Wells Fargo Securities, LLC, J.P. Morgan Securities Inc., Keybanc Capital Markets, and Union Bank, N.A. as joint lead arrangers and joint book runners; and the other financial institutions party thereto, as lenders. The new credit agreements amend and restate IDACORP's and Idaho Power's existing $100 million and $300 million, respectively, credit facilities dated April 25, 2007, that were to expire on April 25, 2012. The credit facilities will be used for general corporate purposes and commercial paper backup. IDACORP's credit agreement provides for the issuance 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 agreement provides for 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 agreements mature on October 26, 2016, though 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 September 30, 2011, no loans were outstanding under either IDACORP's or Idaho Power's facilities then in effect.  At September 30, 2011, Idaho Power had regulatory authority to incur up to $450 million of short-term indebtedness.

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 Balances and interest rates of IDACORP’s short-term borrowings were as follows at September 30, 2011 and December 31, 2010 (in thousands of dollars):

	September 30, 2011			December 31, 2010
Commercial paper outstanding	$	51,500		$	66,900
Weighted-average annual interest rate	0.42		%	0.43		%

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

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6.  COMMON STOCK

IDACORP Common Stock

During the nine months endedSeptember 30, 2011, IDACORP issued an aggregate of 354,590 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, which expires in November 2011, is with BNY Mellon Capital Markets, LLC. As of September 30, 2011, there were approximately 1.2 million shares remaining available to be sold under the current sales agency agreement. No shares were issued under the sales agency agreement during the nine months endedSeptember 30, 2011.

Restrictions on Dividends

A covenant under IDACORP’s credit facility and Idaho Power’s credit facility requires IDACORP and Idaho Power to maintain leverage ratios of consolidated indebtedness to consolidated total capitalization, as defined therein, of no more than 65 percent at the end of each fiscal quarter. Idaho Power’s 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 September 30, 2011, the leverage ratios for IDACORP and Idaho Power were 48 percent and 50 percent, respectively.  Based on these restrictions, IDACORP’s and Idaho Power’s dividends were limited to $827 million and $714 million, respectively, at September 30, 2011.  There are additional facility covenants, subject to exceptions, that prohibit or restrict specified investments or acquisitions, mergers, or the sale or disposition of property without consent; the creation of specified forms of liens; and any agreements restricting dividend payments to the company from any material subsidiary.  At September 30, 2011, 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.

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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7.  EARNINGS PER SHARE

The following table presents the computation of IDACORP’s basic and diluted earnings per share (EPS) for the three and nine months endedSeptember 30, 2011 and 2010 (in thousands, except for per share amounts):

	Three months ended September 30,				Nine months ended September 30,
	2011		2010		2011		2010
Numerator:
Net income attributable to IDACORP, Inc.	$	107,067	$	67,135	$	157,708	$	122,407
Denominator:
Weighted-average common shares outstanding - basic	49,520		48,086		49,411		47,917
Effect of dilutive securities:
Options	12		30		15		37
Restricted Stock	90		136		73		108
Weighted-average common shares outstanding - diluted	49,622		48,252		49,499		48,062
Basic earnings per share	$	2.16	$	1.40	$	3.19	$	2.55
Diluted earnings per share	$	2.16	$	1.39	$	3.19	$	2.55

The diluted EPS computation excludes 134,772 and 183,840 options for the three and nine months endedSeptember 30, 2011, respectively, because the options’ exercise prices were greater than the average market price of the common stock during that period.  For the same period in 2010, the computation excludes 321,891 and 337,242 options for the same reason.  In total, 169,295 options were outstanding at September 30, 2011, with expiration dates between 2011 and 2015.

8.  COMMITMENTS

Purchase Obligations

The following items are the only material changes to long-term purchase commitments during the nine months endedSeptember 30, 2011:

• In 2011, Idaho Power entered into several power purchase agreements with wind and other alternative energy developers.  Payments pursuant to these agreements are expected to total approximately $128 million from 2011 to 2037.

• The IPUC issued orders on June 8, 2011 that disapproved 13 wind power purchase agreements. The orders were subject to a 21-day reconsideration period and reconsiderations were denied by the IPUC on July 27, 2011. At this time, Idaho Power considers all of these agreements to be terminated, though two of the projects have filed appeals with the Idaho Supreme Court. Payments pursuant to these 13 agreements were expected to total approximately $1.3 billion over the terms of the agreements and had previously been reported as purchase obligations.

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 September 30, 2011, representing IERCo's one-third share of BCC's total reclamation obligation of $189 million.  BCC has a reclamation trust fund set aside specifically for the purpose of paying these reclamation costs.  At September 30, 2011, the value of the reclamation trust fund totaled $74 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

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historical experience and the evaluation of the specific indemnities.  As of September 30, 2011, management believes the likelihood is remote that IDACORP or Idaho Power would be required to perform under such indemnification provisions or otherwise incur any significant losses with respect to such indemnification obligations.  Neither IDACORP nor Idaho Power has recorded any liability on their respective condensed consolidated balance sheets with respect to these indemnification obligations.

9.  CONTINGENCIES

IDACORP and Idaho Power have in the past and expect in the future to become involved in various claims, controversies, disputes, and other contingent matters, including the items described in this Note 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 (i) the remedies or penalties sought are indeterminate, (ii) the proceedings are in the early stages or the substantive issues have not been well developed, or (iii) 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 will change, and the estimates themselves will 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 court decisions, and the adverse party's willingness to negotiate towards a resolution, it may be months or years after the filing of a case 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.

Western Energy Proceedings at the FERC

High prices for electricity, energy shortages, and blackouts in California and in western wholesale markets during 2000 and 2001 caused numerous purchasers of electricity in those markets to initiate proceedings seeking refunds or other forms of relief and the FERC to initiate its own investigations.  Some of these proceedings remain pending before the FERC or are on appeal to the United States Court of Appeals for the Ninth Circuit (Ninth Circuit). Except as to the matters described below under “Pacific Northwest Refund,” Idaho Power and IE believe that settlement releases they have obtained will restrict potential claims that might result from the disposition of the pending Ninth Circuit review petitions and predict that these matters will not have a material adverse effect on their consolidated financial positions, results of operations, or cash flows.

Pacific Northwest Refund:  On July 25, 2001, the FERC issued an order establishing a proceeding 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 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. 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 to be appointed within fifteen days of the issuance of its order.

IE and Idaho Power intend to continue to defend their positions in the Pacific Northwest refund proceedings vigorously. As of the date of this report, it is difficult to meaningfully predict the eventual outcome of this matter given the uncertainties that attended the FERC's earlier orders in this case, the fact that specific claims conforming to the FERC's October 3, 2011 order have not yet been submitted, and that the FERC's order remains subject to rehearing and reconsideration. Idaho Power and IE are unable to predict whether the FERC will order refunds, which contracts would be subject to 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 possible loss or range of possible loss that Idaho Power or IE could incur as a result of this matter.

Sierra Club Lawsuit and EPA Notice of Violation - Boardman

In September 2008, the Sierra Club and four other non-profit corporations filed a complaint against Portland General Electric Company (PGE) in the U.S. District Court for the District of Oregon alleging opacity permit limit and Clean Air Act (CAA) violations at the Boardman coal-fired plant located in Morrow County, Oregon.  The complaint sought, in addition to injunctive remedies, civil penalties of up to $32,500 per day per violation, and reimbursement of plaintiffs' costs of litigation, including reasonable attorneys' fees.  Idaho Power was not a party to this proceeding but has a 10 percent ownership interest in the Boardman plant and may have an obligation to reimburse PGE for costs incurred and losses resulting from the proceeding.  PGE owns 65 percent of the plant and is the operator of the plant. In July 2011, the parties filed a consent decree with the court that resolves all of the plaintiffs' claims. The consent decree provides that PGE will pay $2.5 million to the Oregon Community Foundation to be used for environmentally beneficial projects and will pay $1.0 million of the plaintiff's legal expenses. Further, the consent decree imposes certain SO₂ emission caps on the Boardman coal-fired boiler and would allow continued operation of the Boardman plant through December 31, 2020. The court entered the consent decree on September 13, 2011, following the conclusion of the CAA's statutory review period. Idaho Power considers the matter resolved, and payment of the settlement amount did not have a material adverse effect on Idaho Power's financial position, results of operations, or cash flows.

In September 2010, the United States Environmental Protection Agency (EPA) issued a Notice of Violation to PGE, alleging that PGE had violated the New Source Performance Standards (NSPS) and operating permit requirements under the CAA as a result of modifications made to the Boardman plant in 1998 and 2004.  The Notice of Violation states the maximum civil penalties the EPA is authorized to impose under the CAA for violations of the NSPS (which range from $25,000 to $37,500 per day), but it does not impose any penalties or specify the amount of any proposed penalties with respect to the alleged violations. It is difficult to meaningfully predict the eventual outcome of this matter given the complexity of the environmental statutes and claims cited in the Notice of Violation and the matters at issue, the unspecified nature of the penalty or other remedy sought, and the absence of factual information given the early stage of the proceedings. As of the date of this report, based on available information and the status of this matter, Idaho Power is unable to estimate the possible loss or range of possible loss that Idaho Power could incur as a result of this matter. However, PGE, the plant operator, has stated that based on its understanding of the penalties authorized under the CAA, the maximum penalty that could be imposed for the alleged violations is approximately $60 million, with Idaho Power's share of any such penalty being limited to 10 percent of the amount ultimately assessed, if any. The projects alleged to have triggered the NSPS in the Notice of Violation were also included in the Sierra Club's claims in the litigation described immediately above.

Water Rights - Snake River Basin Adjudication

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

Over time, increased irrigation development and other consumptive uses within the Snake River watershed led to a reduction in flows of the Snake River.  In the late 1970's and early 1980's these reduced flows resulted in a conflict between the exercise of Idaho Power's water rights at certain hydroelectric projects on the Snake River and upstream consumptive diversions.  The Swan Falls Agreement, signed by Idaho Power and the State of Idaho on October 25, 1984, resolved the conflict and provided a level of protection for Idaho Power's hydropower water rights at specified projects on the Snake River through the establishment of minimum stream flows and an administrative process governing future development of water rights that may affect those minimum stream flows.  In 1987, Congress enacted legislation directing the FERC to issue an order approving the Swan Falls settlement together with a finding that the agreement was neither inconsistent with the terms and conditions of Idaho Power's project licenses nor the Federal Power Act.  The FERC entered an order implementing the legislation on March 25, 1988.

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

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

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

U.S. Bureau of Reclamation Proceedings

Idaho Power filed a complaint on October 15, 2007, and an amended complaint on September 30, 2008, in the U.S. District Court of Federal Claims in Washington, D.C. against the U.S. Bureau of Reclamation (USBR).  The complaint relates to a 1923 spaceholder contract right for storage and delivery of water to Idaho Power from American Falls Reservoir, a USBR storage reservoir on the Snake River.  In the complaint, Idaho Power alleged that the USBR breached the contract by the failure to implement certain contract provisions relating to secondary storage capacity and claimed damages for the lost generation resulting from reduced flows downstream of the reservoir, and requested a prospective declaration of the rights and obligations of the parties under the 1923 contract.  The USBR claimed that the referenced provisions of the 1923 contract were abrogated or amended by subsequent contracts associated with the 1976 rebuild of American Falls Reservoir and that the provisions of the 1923 contract no longer apply.  The water rights for, and the operation of, American Falls Reservoir are also the subject of litigation in the SRBA, described above. 

During the pendency of the proceedings, Idaho Power worked with the USBR and Idaho interests (including the State of Idaho and upstream water users) in an effort to resolve the contested contract issues that are common to both the SRBA and the pending federal case with the USBR.  These efforts were focused on a recognition in state policy and the Idaho State Water Plan that will promote more efficient operation of the upper Snake River reservoir system to optimize the use of Snake River flows for hydroelectric generation downstream while recognizing and protecting in-reservoir spaceholder contract rights.  These discussions resulted in a resolution passed by the Idaho Water Resource Board in March 2011 that established a standing committee, referred to as the Upper Snake River Advisory Committee (USRAC). The USRAC is comprised of a member of the Idaho Water Resource Board, representatives of Idaho Power, the USBR, and the Committee of Nine, a committee comprised of upstream water users that hold USBR contract rights to reservoir space that advises the State of Idaho and the USBR on reservoir operations. The USRAC is tasked with collaboratively working to identify and implement measures to optimize the operation and management of the reservoir system above Milner Dam to benefit existing and future beneficial uses, including hydropower below Milner Dam. This collaborative process will include a review of existing water bank and rental pool procedures to encourage and facilitate opportunities for the rental, acquisition, and transfer of reservoir storage water and water rights for beneficial uses, including hydropower. The passage of the resolution and establishment of the USRAC has effectively resolved the critical issues outstanding in the pending litigation pertaining to the 1923 contract. While Idaho Power is unable to predict the ultimate impact of the collaborative process, as of the date of this report it does not expect the outcome of the process will have a material adverse effect on its financial position, results of operations, or cash flows.

Other Legal Proceedings

IDACORP and Idaho Power are parties to legal claims, actions, and proceedings in addition to those discussed above.  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.

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

	Pension Plan						Senior Management Security Plan				Postretirement Benefits
	2011			2010			2011		2010		2011			2010
Service cost	$	5,120		$	4,417		$	487	$	385	$	330		$	340
Interest cost	7,581			7,279			773		751		859			898
Expected return on plan assets	(7,968		)	(7,270		)	—		—		(660		)	(641		)
Amortization of transition obligation	—			—			—		—		510			510
Amortization of prior service cost	130			163			61		59		(105		)	(133		)
Amortization of net loss	2,168			1,918			323		232		144			143
Net periodic benefit cost	7,031			6,507			1,644		1,427		1,078			1,117
Costs not recognized due to the effects of regulation (1)	(2,371		)	(4,624		)	—		—		—			—
Net periodic benefit cost recognized for financial reporting (1)	$	4,660		$	1,883		$	1,644	$	1,427	$	1,078		$	1,117
(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.  See Note 3 – “Regulatory Matters” for information on Idaho Power’s 2011 Idaho pension rate order, which increased Idaho jurisdiction recovery to $17.1 million annually, effective June 1, 2011.

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

	Pension Plan						Senior Management Security Plan				Postretirement Benefits
	2011			2010			2011		2010		2011			2010
Service cost	$	15,359		$	13,253		$	1,463	$	1,156	$	992		$	1,020
Interest cost	22,742			21,839			2,319		2,253		2,576			2,693
Expected return on plan assets	(23,903		)	(19,847		)	—		—		(1,981		)	(1,921		)
Amortization of transition obligation	—			—			—		—		1,530			1,530
Amortization of prior service cost	389			488			183		175		(316		)	(401		)
Amortization of net loss	6,505			5,756			969		698		433			430
Net periodic benefit cost	21,092			21,489			4,934		4,282		3,234			3,351
Costs not recognized due to the effects of regulation (1)	(11,981		)	(18,650		)	—		—		—			—
Net periodic benefit cost recognized for financial reporting (1)	$	9,111		$	2,839		$	4,934	$	4,282	$	3,234		$	3,351
(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.  See Note 3 – “Regulatory Matters” for information on Idaho Power’s 2011 Idaho pension rate order, which increased Idaho-jurisdiction recovery to $17.1 million annually, effective June 1, 2011.

In September 2011, Idaho Power contributed $18.5 million to its pension plan. The contribution was in excess of the $6 million minimum contribution requirement for the 2011 calendar year. Idaho Power elected to contribute more than the minimum requirement in order to bring the pension plan to a more funded position, to reduce future required contributions, and to reduce Pension Benefit Guaranty Corporation premiums.

11.  INVESTMENTS IN DEBT AND EQUITY SECURITIES

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

The following table summarizes investments in debt and equity securities by IDACORP and Idaho Power as of September 30, 2011 and December 31, 2010 (in thousands of dollars): 

	September 30, 2011						December 31, 2010
	Gross Unrealized Gain		Gross Unrealized Loss		Fair Value		Gross Unrealized Gain		Gross Unrealized Loss		Fair Value
Available-for-sale securities	$	2,612	$	37	$	21,346	$	4,876	$	—	$	24,561

At the end of each reporting period, IDACORP and Idaho Power analyze securities in loss positions to determine whether they have experienced a decline in market value that is considered other-than-temporary.  At September 30, 2011, one security was in an unrealized loss position. The following table summarizes the security that was in an unrealized loss position at September 30, 2011, but for which no other-than-temporary impairment was recognized (in thousands of dollars):

	Less than 12 months				12 months or longer
	Aggregate Unrealized Loss		Aggregate Related Fair Value		Aggregate Unrealized Loss		Aggregate Related Fair Value
Available-for-sale securities	$	37	$	1,222	$	—	$	—

No other-than-temporary impairment was recognized for the security due to the limited severity and duration of the unrealized loss position. At December 31, 2010, no securities were in an unrealized loss position.

There were no sales of available-for-sale securities during the three and nine months endedSeptember 30, 2011 or 2010.

12.  DERIVATIVE FINANCIAL INSTRUMENTS

Commodity Price Risk

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

All commodity-related derivative instruments not meeting the normal purchases and normal sales exception to derivative accounting are recorded at fair value on the balance sheet.  Because of Idaho Power's PCA mechanisms, unrealized gains and losses associated with the changes in fair value of these derivative instruments are recorded as regulatory assets or liabilities. With the exception of forward contracts for the purchase of natural gas for use at Idaho Power’s natural gas generation facilities, Idaho Power’s physical forward contracts 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.

The following tables present the fair values and locations of derivative instruments not designated as hedging instruments recorded on the balance sheets at September 30, 2011 and December 31, 2010 (in thousands of dollars):

	Asset Derivatives			Liability Derivatives
	Balance Sheet	Fair		Balance Sheet	Fair
	Location	Value		Location	Value
September 30, 2011
Current:
Financial swaps	Other current assets	$	4,192	Other current assets	$	900
Financial swaps	Other current liabilities	—		Other current liabilities	356
Forward contracts	Other current assets	80		Other current liabilities	406
Long-term:
Financial swaps	Other assets	559		Other assets	25
Financial swaps				Other liabilities	344
Total		$	4,831		$	2,031
December 31, 2010
Current:
Financial swaps	Other current assets	$	930	Other current assets	$	356
Financial swaps	Other current liabilities	2,440		Other current liabilities	4,172
Forward contracts				Other current liabilities	508
Long-term:
Financial swaps	Other liabilities	100		Other liabilities	138
Total		$	3,470		$	5,174

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The following table presents the gains and losses on derivatives not designated as hedging instruments for the three and nine months endedSeptember 30, 2011 and 2010 (in thousands of dollars):

	Location of Gain/(Loss)	Gain/(Loss)
	on Derivatives	on Derivatives
Commodity Derivatives	Recognized in Income	Recognized in Income(1)
Three months ended September 30, 2011:
Financial swaps	Off-system sales	$	441
Financial swaps	Purchased power	(6,982		)
Financial swaps	Fuel expense	115
Financial swaps	Other operations and maintenance	120
Three months ended September 30, 2010:
Financial swaps	Off-system sales	$	2,332
Financial swaps	Purchased power	(6,749		)
Financial swaps	Fuel expense	(101		)
Forward contracts	Fuel expense	(721		)
Nine months ended September 30, 2011:
Financial swaps	Off-system sales	$	6,947
Financial swaps	Purchased power	(6,954		)
Financial swaps	Fuel expense	501
Financial swaps	Other operations and maintenance	347
Nine months ended September 30, 2010:
Financial swaps	Off-system sales	$	3,284
Financial swaps	Purchased power	(9,135		)
Financial swaps	Fuel expense	(101		)
Forward contracts	Fuel expense	(721		)
(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 - “Fair Value Measurements” for additional information concerning the determination of fair value for Idaho Power’s assets and liabilities from price risk management activities.

Idaho Power had the following volumes of derivative commodity forward contracts and swaps outstanding at September 30, 2011 and 2010:

		September 30,
Commodity	Units	2011	2010
Electricity purchases	MWh	197,800	443,250
Electricity sales	MWh	1,038,095	237,000
Natural gas purchases	MMBtu	2,292,738	325,500
Natural gas sales	MMBtu	77,500	—
Diesel purchases	Gallons	266,375	208,980

Credit Risk

At September 30, 2011, Idaho Power did not have material credit exposure from financial instruments, including derivatives.  Idaho Power monitors credit risk exposure through reviews of counterparty credit quality, corporate-wide counterparty credit exposure, and corporate-wide counterparty concentration levels.  Idaho Power manages these risks by establishing appropriate credit and concentration limits on transactions with counterparties and requiring contractual guarantees, cash deposits, or letters of credit from counterparties or their affiliates, as deemed necessary.  Idaho Power’s physical power contracts are under Western Systems Power Pool agreements, physical gas contracts are under North American Energy Standards Board contracts, and financial transactions are under International Swaps and Derivatives Association, Inc. contracts. These contracts all contain adequate assurance clauses requiring collateralization if a counterparty has debt that is downgraded below investment grade by at least one rating agency. 

Credit-Contingent Features

Certain of Idaho Power's derivative instruments contain provisions that require Idaho Power's unsecured debt to maintain an investment grade credit rating from Moody's Investors Service and Standard & Poor's Ratings Services.  If Idaho Power's unsecured debt were to fall below investment grade, it would be in violation of these provisions, and the counterparties to the derivative instruments could request immediate payment or demand immediate and ongoing full overnight collateralization on derivative instruments in net liability positions.  The aggregate fair value of all derivative instruments with credit-risk-related contingent features that were in a liability position at September 30, 2011, was $2.0 million.  Idaho Power posted $1.6 million of collateral related to this amount.  If the credit-risk-related contingent features underlying these agreements were triggered on September 30, 2011, Idaho Power would have been required to post $0.9 million of additional cash collateral to its counterparties.

13.  FAIR VALUE MEASUREMENTS

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

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

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

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

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

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

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

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

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

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

Idaho Power’s derivatives are contracts entered into as part of its management of loads and resources.  Electricity swaps are valued on the Intercontinental Exchange with quoted prices in an active market.  Natural gas and diesel derivative valuations are performed using New York Mercantile Exchange (NYMEX) pricing, adjusted for 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.

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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 September 30, 2011 and December 31, 2010 (in thousands of dollars).  IDACORP’s and Idaho Power’s assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy.  There were no transfers between levels for the periods presented. 

	Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)		Total
September 30, 2011
IDACORP
Assets:
Derivatives	$	3,826	$	80	$	—	$	3,906
Money market funds	100		—		—		100
Trading securities:  Equity securities	3,239		—		—		3,239
Available-for-sale securities:  Equity securities	21,346		—		—		21,346
Liabilities:
Derivatives	$	130	$	977	$	—	$	1,107
Idaho Power
Assets:
Derivatives	$	3,826	$	80	$	—	$	3,906
Money market funds	100		—		—		100
Trading securities:  Equity securities	3,239		—		—		3,239
Available-for-sale securities:  Equity securities	21,346		—		—		21,346
Liabilities:
Derivatives	$	130	$	977	$	—	$	1,107
December 31, 2010
IDACORP
Assets:
Derivatives	$	573	$	—	$	—	$	573
Money market funds	151,975		—		—		151,975
Trading securities:  Equity securities	5,361		—		—		5,361
Available-for-sale securities:  Equity securities	24,561		—		—		24,561
Liabilities:
Derivatives	$	—	$	508	$	—	$	508
Idaho Power
Assets:
Derivatives	$	573	$	—	$	—	$	573
Money market funds	151,173		—		—		151,173
Trading securities:  Equity securities	4,746		—		—		4,746
Available-for-sale securities:  Equity securities	24,561		—		—		24,561
Liabilities:
Derivatives	$	—	$	508	$	—	$	508

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The table below presents the carrying value and estimated fair value of financial instruments that are not reported at fair value, as of September 30, 2011 and December 31, 2010, using available market information and appropriate valuation methodologies.  The use of different market assumptions and/or estimation methodologies may have a material effect on the estimated fair value amounts.  Cash and cash equivalents, deposits, customer and other receivables, notes payable, accounts payable, interest accrued, and taxes accrued are reported at their carrying value as these are a reasonable estimate of their fair value.  The estimated fair values for notes receivable and long-term debt are based upon quoted market prices of the same or similar issues or discounted cash flow analysis as appropriate. 

	September 30, 2011				December 31, 2010
	Carrying		Estimated		Carrying		Estimated
	Amount		Fair Value		Amount		Fair Value
	(thousands of dollars)
IDACORP
Assets:
Notes receivable	$	2,946	$	2,946	$	2,946	$	2,946
Liabilities:
Long-term debt	1,492,330		1,729,623		1,614,299		1,622,924
Idaho Power
Liabilities:
Long-term debt	$	1,491,727	$	1,729,022	$	1,612,790	$	1,621,425

14.  SEGMENT INFORMATION

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

IDACORP’s other operating segments are below the quantitative and qualitative thresholds for reportable segments and are included in the “All Other” category 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 following table summarizes the segment information for IDACORP’s utility operations and the total of all other segments, and reconciles this information to total enterprise amounts (in thousands of dollars): 

	Utility Operations		All Other		Eliminations			Consolidated Total
Three months ended September 30, 2011:
Revenues	$	308,045	$	1,585	$	—		$	309,630
Net income attributable to IDACORP, Inc.	104,872		2,195		—			107,067
Total assets as of September 30, 2011	4,719,173		124,273		(16,511		)	4,826,935
Three months ended September 30, 2010:
Revenues	$	308,468	$	889	$	—		$	309,357
Net income attributable to IDACORP, Inc.	64,650		2,485		—			67,135
Nine months ended September 30, 2011:
Revenues	$	793,031	$	3,076	$	—		$	796,107
Net income attributable to IDACORP, Inc.	155,420		2,288		—			157,708
Nine months ended September 30, 2010:
Revenues	$	801,719	$	2,354	$	—		$	804,073
Net income attributable to IDACORP, Inc.	121,700		707		—			122,407

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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 September 30, 2011, and the related condensed consolidated statements of income and comprehensive income for the three-month and nine-month periods ended September 30, 2011 and 2010, and of equity and cash flows for the nine-month periods ended September 30, 2011 and 2010.  These interim financial statements are the responsibility of the Company’s management.

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

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

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

/s/ DELOITTE & TOUCHE LLP

Boise, Idaho

November 3, 2011

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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 September 30, 2011, and the related condensed consolidated statements of income and comprehensive income for the three-month and nine-month periods ended September 30, 2011 and 2010, and of cash flows for the nine-month periods ended September 30, 2011 and 2010.  These interim financial statements are the responsibility of the Company’s management.

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

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

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

/s/ DELOITTE & TOUCHE LLP

Boise, Idaho

November 3, 2011

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

• the effect of regulatory decisions by the Idaho Public Utilities Commission, the Oregon Public Utility Commission, the Federal Energy Regulatory Commission, and other regulators affecting Idaho Power's ability to recover costs and/or earn a reasonable rate of return;

• 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;

• changes in the cost and availability of materials, fuel, and commodities, and their impact on Idaho Power's infrastructure costs, power costs, the ability to meet required loads, and 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, 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 power portfolio;

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

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

• changes in and costs of compliance with laws, regulations, and policies relating to the environment, natural resources, and endangered species and the adoption of laws and regulations addressing greenhouse gas emissions, global climate change, and energy policies intended to mitigate carbon dioxide, mercury, and other emissions;

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

• inclement weather and other natural phenomena such as earthquakes, floods, droughts, lightning, wind, and fire, which, in addition to affecting customer demand for power, could significantly affect the ability and cost to procure adequate

32

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 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 pursuant to existing power purchase and credit arrangements;

• 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;

• 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 unionization or the attempt to unionize all or part of the companies' workforce, and the ability to adjust the labor cost structure to changes in growth within Idaho Power's service territory;

• 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; 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.

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 494,000 general business customers as of September 30, 2011.  Idaho Power is regulated by the Federal Energy Regulatory Commission (FERC) and the state regulatory commissions of Idaho and Oregon.  Idaho Power is the parent of Idaho Energy Resources Co. (IERCo), a joint venturer in Bridger Coal Company (BCC), which mines and supplies coal to the Jim Bridger generating plant owned in part by Idaho Power.  Idaho Power generates revenues and cash flows primarily from the sale and distribution of electricity to customers in its Idaho and Oregon service territories, as well as from the wholesale sale and transmission of electricity.  Idaho Power’s revenues and income from operations are subject to fluctuations during the year due to the impacts of seasonal weather conditions on demand for electricity, availability of water for hydroelectric generation, price changes, customer usage patterns (which are affected in large part by the condition of the local economy), and the availability and price of purchased power and fuel.  Idaho Power is a dual peaking utility that typically experiences its highest retail energy sales during the summer irrigation and cooling season, with a lower peak in the winter that generally results from heating demand.  IDACORP’s and Idaho Power’s financial condition is also affected by regulatory decisions, through which Idaho Power seeks to recover its costs, including purchased power and fuel costs, on a timely basis, and to earn an authorized return on investment, and by the ability to obtain financing through the issuance of debt and/or equity securities.

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

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

EXECUTIVE OVERVIEW

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

Regulatory Cost Recovery:  Idaho Power is under the retail jurisdiction (as to rates, service, accounting, and other general matters of utility operation) of the Idaho Public Utilities Commission (IPUC) and the Oregon Public Utility Commission (OPUC), and under the jurisdiction of the Federal Energy Regulatory Commission (FERC) as to transmission services and wholesale energy sales.  The prices that Idaho Power is authorized to charge are major factors 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's management continues to focus on timely recovery of its costs through filings with the company's regulators. Notable regulatory actions occurring during the periods and through the date of this report included the following:

• Idaho 2011 General Rate Case - On June 1, 2011, Idaho Power filed a general rate case with the IPUC, requesting approximately $82.6 million in additional Idaho jurisdiction annual revenues in base rates. 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. The settlement stipulation provides for a 7.86 percent authorized rate of return on an Idaho-jurisdictional rate base of approximately $2.36 billion, and for the IPUC to allow Idaho Power to earn an authorized rate of return of 7.86 percent in any regulatory matter until subsequently changed by IPUC order. Idaho Power had requested an 8.17 percent rate of return in its general rate case application. The settlement stipulation, if approved by the IPUC, would result in a $34 million, or 4.07 percent overall average, increase in Idaho Power's annual Idaho jurisdictional base rate revenues, effective January 1, 2012. The settlement stipulation also provides that approximately $22.8 million of Idaho jurisdictional revenue associated with the recovery of certain net power supply costs would not be included in base rates, but would instead be eligible for

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100 percent recovery through the Idaho PCA mechanism if the costs are incurred.

• Idaho Base Rate Increase - On May 28, 2010, the IPUC approved an increase to Idaho jurisdiction base rates of $88.7 million, effective June 1, 2010.

• 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.  The Idaho PCA mechanism compares Idaho Power's actual net power supply costs to net power supply costs currently being recovered in retail rates, with most of the variance between these two amounts deferred for future recovery from, or refund to, customers.  On May 28, 2010, the IPUC issued an order approving a $146.9 million PCA decrease, effective June 1, 2010. On May 31, 2011, the IPUC issued an order approving a $40.4 million PCA decrease, effective June 1, 2011. These rate changes are offset by fluctuations in related net power supply costs and deferrals and amortization under the PCA mechanism, resulting in a relatively small impact on earnings.

• Oregon 2011 General Rate Case - On July 29, 2011, Idaho Power filed a general rate case for its Oregon jurisdiction with the OPUC, requesting a $5.8 million increase in annual Oregon jurisdictional revenues. As of the date of this report, the general rate case remains pending.

• Application for Extension of Certain Provisions of the January 2010 Settlement Agreement - 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 accelerated amortization of accumulated deferred investment tax credits (ADITC) to help achieve a minimum 9.5 percent return on year-end equity in the Idaho jurisdiction, and (b) an equal sharing of any Idaho jurisdiction earnings exceeding a return on year-end equity of 10.5 percent in the Idaho jurisdiction.  Recognition of tax benefits in the third quarter of 2011 had a significant impact on Idaho Power's estimate of return on 2011 year-end equity and contributed to triggering of the sharing mechanism under the settlement agreement. In the third quarter, Idaho Power recorded an $18.1 million regulatory liability, reflecting 50 percent of Idaho Power's estimated 2011 Idaho jurisdictional earnings over a 10.5 percent return on year-end equity required to be shared with customers.

• 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, with the following terms:

◦ If Idaho Power's Idaho jurisdiction return on year-end equity for 2012 or 2013 is less than 9.5 percent, then Idaho Power may continue to use up to $45 million of deferred investment tax credits to help achieve a minimum 9.5 percent return on year-end equity in the Idaho jurisdiction in those years. Idaho Power may use an aggregate of $45 million of additional ADITC in 2012 and 2013, comprised of up to a maximum of $25 million of additional ADITC in 2012 and any unused portion carried forward to 2013.

◦ If Idaho Power's Idaho jurisdictional return on year-end equity for 2012 or 2013 exceeds 10.0 percent, the amount exceeding 10.0 percent would be shared equally between Idaho Power and its customers in the applicable year.

◦ Idaho Power would allocate to customers 50 percent of Idaho Power's share of estimated 2011 Idaho jurisdictional earnings over a 10.5 percent return on year-end equity, reflected as a reduction in customer rates or an offset to amounts that would otherwise be collected from rates.

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 and the customer growth rate, while still positive, has been low relative to prior years.  During the twelve months ended September 30, 2011, the customer growth rate in Idaho Power's service territory was 0.7 percent. By comparison, for the 20-year period ending 2010 the average annual customer growth rate in Idaho Power's service territory was 2.7 percent. Economic conditions can impact consumer demand for electricity, collectability of accounts, the volume of off-system sales due to power demand, and Idaho Power's need for purchased power.  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 on 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 of each

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calendar year, irrigation customers use electricity to operate irrigation pumps.  A four percent increase in energy usage by Idaho Power customers in the third quarter of 2011 compared to the third quarter of 2010 is largely attributable to above average temperatures and below average precipitation, resulting in higher use of irrigation pumps and increased air conditioning load.   

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, river base flows in the Snake River, spring flows, rainfall, water leases and other water rights, and other weather and stream flow considerations.  As of the date of this report, Idaho Power expects hydroelectric generation during 2011 in the range of 11.0 to 11.5 million MWh, compared to 7.3 million MWh in 2010, as a result of above-average precipitation levels during the most recent snow accumulation period. Median annual hydroelectric generation is 8.6 million MWh. Due largely to favorable hydroelectric generation conditions, hydroelectric generation comprised 64 percent of Idaho Power's total system generation in the third quarter of 2011 and 71 percent year-to-date 2011. 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 were down 37 percent in the third quarter of 2011 and 33 percent year-to-date compared to the third quarter and year-to-date 2010, respectively.

An abundance of intermittent wind power generation at times when Idaho Power has available lower-cost resources to meet load demands has an impact on the operation of Idaho Power's hydroelectric generation plants, system reliability, power supply costs, and the wholesale power markets in the Pacific Northwest. Wind power generated from PURPA projects, which Idaho Power is generally obligated to purchase regardless of the then-current load demand or wholesale energy market prices, increases the likelihood and frequency that Idaho Power will be required to reduce output from its lower-cost hydroelectric and fossil fuel-fired generation resources, even when weather conditions have resulted in favorable hydroelectric generation conditions or fuel prices are low. Abundant wind generation in the Pacific Northwest during periods when abundant hydroelectric generation is also available reduces wholesale market prices, resulting in Idaho Power's potential sale of excess power at a significant discount to the price paid by Idaho Power under PURPA wind power purchase contracts and the sale of excess lower-cost hydroelectric or fuel-based power at depressed wholesale market prices. Also, balancing load and generation from Idaho Power's power generation portfolio is challenging and may further increase customer costs as Idaho Power works to integrate intermittent, non-dispatchable power from a large number of PURPA power projects. When forecasted wind resources do not materialize, Idaho Power must obtain a substitute source of power to meet load demand, and often must purchase power in the wholesale power markets to balance loads. Idaho Power will continue to incur costs associated with the integration of wind resources into its power portfolio, and Idaho Power anticipates that those costs will increase as the volume of wind power on Idaho Power's system increases.

Fuel and Purchased Power Expense:  Fuel and purchased power costs are impacted by electricity sales volumes, the terms of contracts for purchased power and fuel (principally coal and natural gas), Idaho Power's power generation capacity, the rate of expansion of alternative energy generation sources such as wind energy, the availability of hydroelectric generation resources, transmission capacity, energy market prices, and Idaho Power's hedging program for managing power costs.

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.  For the three and nine months endedSeptember 30, 2011, Idaho Power's weighted average fuel-related cost per MWh for its fossil fuel generation resources increased 6.6 percent and 14.8 percent, respectively, relative to the same periods in 2010, mainly due to coal price increases and the effect of lower generation output, such as the spreading of fixed costs over lower output. Notwithstanding the increase in fuel cost per MWh generated, for the three and nine months endedSeptember 30, 2011, total fuel expense decreased 20 percent and 22 percent, respectively, relative to the same periods in 2010, due to a decrease in output from fuel-fired power generating plants resulting from both the abundant hydroelectric generation and increased wind power obtained through mandated power purchases pursuant to PURPA. Looking ahead, operation of the Langley Gulch power plant that Idaho Power is currently constructing will increase Idaho Power's demand for natural gas, and thus its exposure to volatility in natural gas prices.

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

Regulatory and Environmental Compliance Costs and Expenditures:  Idaho Power is subject to extensive federal and state laws, policies, and regulations, as well as regulatory actions and audits.  Compliance with these requirements directly

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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, was recently the subject of proceedings with Oregon regulators relating to the installation of costly emission controls and a cessation of coal-fired operations in 2020, and in September 2010 the U.S. Environmental Protection Agency (EPA) issued a Notice of Violation to Portland General Electric Company (PGE), the operator of the Boardman plant, alleging Clean Air Act (CAA) violations.  Idaho Power continues to monitor developing legislation and increased regulation concerning greenhouse gas emissions and the potential impacts on its power generation facilities, and as legislation further develops will assess the impact of any resulting legislation on the costs to operate those facilities, as well as the willingness or ability of power plant participants to fund any required pollution control equipment upgrades. Idaho Power intends to seek recovery of such costs through the ratemaking process.

Other Notable Matters and Future Challenges

Retirement Benefit Plans:  In September 2010, Idaho Power contributed $60 million to its defined benefit pension plan.  On May 19, 2011, the IPUC approved Idaho Power's March 2011 application to increase the amount included in base rates for recovery of the Idaho-allocated portion of Idaho Power's cash contributions to its defined benefit pension plan from the current amount of $5.4 million to $17.1 million annually, with new rates effective on June 1, 2011. In September 2011, Idaho Power contributed an additional $18.5 million to the defined benefit pension plan. Idaho Power expects to make additional significant cash contributions to its pension plan and has significant funding obligations under postretirement benefit plans through at least 2015. See Note 11 - “Benefit Plans” to the consolidated financial statements included in IDACORP's and Idaho Power's Annual Report on Form 10-K for the fiscal year ended December 31, 2010 for additional information relating to Idaho Power’s pension plan funding obligations.

Water Management and Relicensing of Hydroelectric Projects: Because of Idaho Power's reliance on streamflow 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.

Primary Drivers of Third Quarter and Year-to-Date Financial Results

For the three and nine months endedSeptember 30, 2011, IDACORP's and Idaho Power's financial results were affected primarily by the following items:  

• Tax Related Projects and Associated Impacts - In September 2011, the U.S. Internal Revenue Service (IRS) notified Idaho Power that Idaho Power's uniform capitalization tax method agreement had been approved, resulting in the recognition of $56.9 million of its previously unrecognized tax benefits in the third quarter of 2011. Recognition of these tax benefits also contributed to:

• the reversal of $6.8 million of Idaho Power's additional amortization of ADITC recognized in the first six months of 2011. A January 2010 settlement agreement with the IPUC and other parties provides for additional amortization of ADITC only if Idaho Power's actual return on year-end equity in its Idaho jurisdiction is below 9.5 percent.

• Idaho Power's recording of the ongoing tax benefit for the current year, approximately $3 million annually.

• Sharing of Earnings - Idaho Power's recording of an $18.1 million regulatory liability, as required by the January 2010 settlement agreement, which provided that if Idaho Power's 2011 return on year-end equity exceeds 10.5 percent in the Idaho jurisdiction, Idaho Power would share with Idaho customers 50 percent of the earnings in excess of the 10.5 percent return.

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• Significant Rate Changes - Rate and regulatory changes, primarily the impact of the January 2010 rate settlement agreement and subsequent filings with the IPUC that approved a $146.9 million decrease in PCA rates in the Idaho jurisdiction, along with a base rate increase of $88.7 million, effective on June 1, 2010. The IPUC approved a further decrease of $40.4 million to Idaho PCA rates for the period from June 1, 2011 to May 31, 2012.

• Increase in Operating Expense - An increase in operating and maintenance expense at Idaho Power, principally labor-related expenses, plant maintenance, and property taxes.

• Seasonal Sales Volume Fluctuations - Increased sales volume during the first quarter of 2011 relative to the first quarter of 2010 as a result of cooler weather, together with a sales volume increase during the third quarter of 2011 relative to the third quarter of 2010 as a result of warmer and drier weather.

If the IPUC were to approve Idaho Power's November 2, 2011 application described above in this MD&A under "Overview of General Factors and Trends Affecting Results of Operations and Financial Condition - Regulatory Cost Recovery," Idaho Power would be required to record a fourth quarter 2011 charge for the additional 50 percent of Idaho Power's share of estimated Idaho jurisdictional earnings over a 10.5 percent return on year-end equity allocated to customers. Idaho Power estimates that the amount of the charge would be approximately $10 million on a pre-tax basis, based on its estimate of full year 2011 return on equity and the terms set forth in the application Idaho Power submitted to the IPUC.

Summary of Third Quarter and Year-to-Date 2011 Financial Results

A summary of net income attributable to IDACORP, Inc. and earnings per diluted share for the three and nine months endedSeptember 30, 2011 and 2010 is as follows: 

	Three months ended September 30,				Nine months ended September 30,
	2011		2010		2011		2010
Net income attributable to IDACORP, Inc.	$	107,067	$	67,135	$	157,708	$	122,407
Average outstanding shares – diluted (000’s)	49,622		48,252		49,499		48,062
Earnings per diluted share	$	2.16	$	1.39	$	3.19	$	2.55

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The following table presents a reconciliation of net income attributable to IDACORP, Inc. for the three and nine month periods ended September 30, 2011 to the same periods in 2010 (items are in millions and are before tax unless otherwise noted):

	Three months ended						Nine months ended
Net income attributable to IDACORP, Inc. - September 30, 2010				$	67.1					$	122.4
Change in Idaho Power net income before taxes:
Rate and other regulatory changes, including power cost and
fixed cost adjustment mechanisms	$	4.3					$	25.1
Changes in sales volumes	7.3						9.2
Increased transmission service revenues	2.2						6.7
Increased other operating and maintenance expenses:
Pension and payroll related expenses	(6.3		)				(12.9		)
Thermal plant expenses	(1.0		)				(6.0		)
Other	(5.3		)				(2.6		)
Increased depreciation expense	(1.0		)				(2.8		)
Increased property taxes	(1.7		)				(4.6		)
Other changes in operating income, net	0.4						0.9
Decrease in revenues as a result of sharing mechanism	(18.1		)				(18.1		)
Change in Idaho Power operating income	(19.2		)				(5.1		)
Decrease in earnings at Bridger Coal Company	(1.7		)				(6.6		)
Other net increases	4.6						6.2
Change in additional amortization of ADITC	(6.8		)				—
Tax method changes and related examination settlements	49.5						27.8
Change in other income tax expense	13.8						11.4
Total increase in Idaho Power net income				40.2						33.7
Changes at holding company (net of tax)				(0.6		)				1.3
Other net increases (net of tax)				0.4						0.3
Net income attributable to IDACORP, Inc. - September 30, 2011				$	107.1					$	157.7

Idaho Power's 2011 net income increased for the third quarter and year-to-date compared to the same periods in 2010 largely as a result of the effect of approval by the U.S. Congress Joint Committee on Taxation (Joint Committee) of the uniform capitalization method agreement with the IRS. Approval of the method change allowed Idaho Power to recognize in the third quarter of 2011 approximately $56.9 million of previously unrecognized tax benefits for tax years 2009 and prior. Idaho Power recognized a $7.4 million benefit from a tax method change in the same period of 2010. The impact of the uniform capitalization method approval contributed to triggering of the sharing mechanism under Idaho Power's January 2010 settlement agreement with the IPUC Staff and other parties. Idaho Power recorded an $18.1 million provision against current revenues to be refunded to or otherwise benefit customers. The provision reflects the equal sharing of anticipated 2011 Idaho-jurisdiction earnings exceeding the authorized return on year-end equity of 10.5 percent, as is required by the settlement agreement. Idaho Power also reversed in the third quarter of 2011, $6.8 million of additional amortization of ADITC that had been recorded in the first six months of the current year under a separate provision of the January 2010 settlement agreement.

Idaho Power's 2011 third quarter operating income decreased $19.2 million compared to the third quarter of 2010 largely as a result of the triggered sharing mechanism discussed above, as $18.1 million of revenues were reserved for potential refund under the mechanism. Expense increases were largely offset by increased base rates and other regulatory changes as well as increased sales volumes. Pension expense increases were due to incremental amortization of pension costs concurrent with the authorization to recover these costs in revenues. Increased other operating and maintenance expense includes a $1.6 million increase in the cost of water leases, which are recovered through the Idaho PCA mechanism.

Year-to-date 2011 operating income was also impacted by the $18.1 million reduction in revenue discussed above, but only decreased $5.1 million compared to the same period in 2010. Changes in rates and other regulatory mechanisms offset most of the reserve for sharing. Increases in base rates and transmission service revenues were partially offset by an increase o

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f $21.5 million in other operations and maintenance (O&M) expenses, such as payroll-related expenses, thermal plant expenses, pension expenses, and hydroelectric license compliance costs. Year-to-date, costs associated with thermal plant maintenance outage activities were largely in line with Idaho Power's expectations but higher than 2010.

On June 1, 2010 and 2011, rate orders increasing Idaho base rates and reducing PCA rates were implemented. The net impact of these rate changes collectively reduced Idaho-jurisdiction revenues approximately $12.3 million and $69.9 million for the quarter and the year-to-date, respectively. The revenue impact of certain rate changes was directly offset by related changes in operating expense. For example, the PCA rate reductions were offset by reduced PCA amortization expense and reduced net power supply costs (primarily fuel and purchased power, less off-system sales). The rate changes and changes in power supply costs, net of the related PCA mechanisms, increased operating income by approximately $4.3 million and $25.1 million for the third quarter of 2011 and year-to-date 2011 relative to the comparable periods in 2010.

For the third quarter, higher sales volumes increased operating income $7.3 million compared to the third quarter of 2010, largely due to a 4.8 percent, 4.9 percent, and 2.4 percent increase in irrigation, residential, and commercial customer usage, respectively. A decline in precipitation compared with the same period in 2010 caused an increase in irrigation usage. Also, a 24.4 percent increase in cooling degree days when compared to the same period in the prior year drove increased demand for electricity to power residential and commercial air conditioning units. For the year-to-date, increased sales volumes improved operating income by $9.2 million. A 19.0 percent increase in cooling degree days year-to-date caused the increased demand.

BCC continued to experience lower than anticipated results, with $1.7 million and $6.6 million lower earnings for the quarter and year-to-date, respectively, compared to the same periods last year, resulting from reduced coal deliveries to the Bridger generating plant and increased mine production costs. Due to the abundance of lower-cost hydroelectric generation and increased wind generation, production at the Bridger generating plant was down 19 percent for the quarter and 25 percent year-to-date compared to the prior year periods. Idaho Power expects BCC coal prices to increase in the fourth quarter of 2011 to bring 2011 more in line with 2010 results.

Key Operating and Financial Metrics

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

	2011 Estimates
	Current (3)	Previous (4)
Idaho Power Operating & Maintenance Expense (millions)	No change	$310-$320
Idaho Power Capital Expenditures (millions)(1)	No change	$320-$330
Idaho Power Hydroelectric Generation (million MWh)(2)	11.0-11.5	9.5-10.5
Non-regulated subsidiary earnings and holding company expenses (millions)	No change	$0.0-$3.0
(1)    The range for capital expenditures includes amounts for the Langley Gulch power plant and expenditures for the siting and permitting of major transmission expansions for the Boardman to Hemingway and Gateway West transmission projects, excluding AFUDC.
(2)    The range of estimated hydroelectric generation has been revised to reflect actual hydroelectric generation through September and estimated ranges of hydroelectric generation for the remainder of the year.
(3) As of November 3, 2011.
(4) As of August 4, 2011, the date of filing of IDACORP's and Idaho Power's Quarterly Report on Form 10-Q for the period ended June 30, 2011.

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RESULTS OF OPERATIONS

This section of the MD&A takes a closer look at the significant factors that affected IDACORP’s and Idaho Power’s earnings during the three and nine months endedSeptember 30, 2011.  In this analysis, the results for the three and nine months endedSeptember 30, 2011 are compared to the same periods in 2010.

Results for the Three and Nine Months EndedSeptember 30, 2011

The following table presents net income (losses) for IDACORP and its subsidiaries for the three and nine months endedSeptember 30, 2011 and 2010:

	Three months ended September 30,						Nine months ended September 30,
	2011			2010			2011			2010
Idaho Power – Utility operations	$	104,872		$	64,650		$	155,420		$	121,700
IDACORP Financial Services	(378		)	(384		)	(295		)	(321		)
Ida-West Energy	1,390			1,123			2,756			2,310
IDACORP Energy	(36		)	(55		)	(97		)	96
Holding company	1,219			1,801			(76		)	(1,378		)
Net income attributable to IDACORP, Inc.	$	107,067		$	67,135		$	157,708		$	122,407
Average common shares outstanding (diluted, in 000’s)	49,622			48,252			49,499			48,062
Earnings per diluted share	$	2.16		$	1.39		$	3.19		$	2.55

Utility Operations

The table below presents Idaho Power’s energy sales and supply (in thousands of MWh) for the three and nine months endedSeptember 30, 2011 and 2010: 

	Three months ended September 30,				Nine months ended September 30,
	2011		2010		2011		2010
General business sales	4,239		4,078		10,524		10,314
Off-system sales	747		235		2,794		1,602
Total energy sales	4,986		4,313		13,318		11,916
Hydroelectric generation	2,790		1,687		8,683		5,887
Coal generation	1,482		1,961		3,370		4,988
Natural gas and other generation	83		117		124		138
Total system generation	4,355		3,765		12,177		11,013
Purchased power	974		928		2,157		1,902
Line losses	(343	)	(380	)	(1,016	)	(999	)
Total energy supply	4,986		4,313		13,318		11,916

For the three months ended September 30, 2011, hydroelectric generation comprised 64 percent of Idaho Power’s total system generation and 56 percent of its total energy supply.  Based on current reservoir levels, forecasted stream flow, and other conditions relevant to hydroelectric generation capacity, Idaho Power expects to generate between 11.0 and 11.5 million MWh from its hydroelectric facilities in 2011, compared to 7.3 million MWh in 2010.  Idaho Power’s modeled median annual hydroelectric generation is 8.6 million MWh, based on hydrologic conditions for the period 1928 through 2010 and adjusted to reflect the current level of water resource development.  The increase in hydroelectric generation during the third quarter of 2011 resulted in a decreased reliance on coal-fired generation, contributing to a $10.1 million decrease in fuel expense relative to the third quarter of 2010, and also contributed to the availability of additional surplus power available for off-system sales. Most of the decrease in power supply costs that typically results from increased hydroelectric generation is returned to customers through the PCA mechanisms.

Idaho Power’s system is dual peaking, with the larger peak demand occurring in the summer.  To reduce the magnitude of peak demands, Idaho Power has implemented a demand response program and a number of energy efficiency programs. The 2011 summer peak demand was 2,973 MW, set on July 6, 2011. The record summer peak demand of 3,214 MW was set on June 30,

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2008, and the highest winter peak demand of 2,527 MW was set on December 10, 2009.  During these and other similar heavy load periods, Idaho Power’s system is fully committed to serve loads and meet required operating reserves.

General business revenue:  The following table presents Idaho Power’s general business revenues, MWh sales, and number of customers for the three and nine months endedSeptember 30, 2011 and 2010:

	Three months ended September 30,						Nine months ended September 30,
	2011			2010			2011			2010
Revenue
Residential	$	103,035		$	99,701		$	302,464		$	295,266
Commercial	61,630			63,466			169,229			176,990
Industrial	38,496			35,907			105,098			105,975
Irrigation	70,596			70,540			99,467			104,328
Total	273,757			269,614			676,258			682,559
Provision for sharing	(18,100		)	—			(18,100		)	—
Deferred revenue related to Hells Canyon
Complex relicensing AFUDC(1)	(3,344		)	(3,344		)	(8,277		)	(8,266		)
Total general business revenues	$	252,313		$	266,270		$	649,881		$	674,293
MWh
Residential	1,246			1,182			3,786			3,624
Commercial	1,035			1,002			2,867			2,813
Industrial	783			780			2,294			2,280
Irrigation	1,175			1,114			1,577			1,597
Total	4,239			4,078			10,524			10,314
Customers (period end)
Residential	410,079			407,777
Commercial	65,061			64,471
Industrial	124			124
Irrigation	18,807			18,637
Total	494,071			491,009

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

General business revenue decreased $14.0 million and $24.4 million in the quarter and the nine months endedSeptember 30, 2011, respectively, compared to the same periods in 2010.  Most of the decrease is a result of recording a regulatory liability of $18.1 million to be refunded to or otherwise benefit customers, reflecting the equal sharing of anticipated Idaho jurisdiction earnings exceeding the authorized return on year-end equity of 10.5 percent. The offset to this liability was recorded as a reduction to general business revenue during the third quarter. The remaining changes in general business revenue, an increase of $4.1 million for the quarter and a decrease of $6.3 million for the year-to-date, are primarily attributable to the effects of rate changes and usage. These factors are discussed in more detail below.

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•         Rates:  The following table presents notable Idaho and Oregon rate increases and decreases, shown on an

annualized basis, that affected results for the quarter:

		Percentage Rate Increase (Decrease)		Annualized $ Impact (millions)
	Effective Date
Description
2010 Idaho settlement agreement	6/1/2010	9.9%		89
2010 Idaho PCA	6/1/2010	(16.4%)		(147	)
2010 Idaho pension expense recovery	6/1/2010	0.8%		5
2010 Idaho AMI	6/1/2010	0.4%		2
2010 Idaho FCA	6/1/2010	0.9%		4
2010 Oregon power cost update	6/1/2010	5.5%		2
2011 Idaho PCA	6/1/2011	(4.8%)		(40	)
2011 Idaho FCA	6/1/2011	0.4%		3
2011 Idaho pension expense recovery	6/1/2011	1.4	%	12

These rate changes combined to reduce general business revenue by $12.3 million for the quarter and $69.9 million for the year-to-date 2011 relative to the same periods in 2010. 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 $7.6 million for the quarter and $50.2 million for the year-to-date 2011, respectively, compared to the same periods of 2010 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.

The Idaho general rate case settlement stipulation filed by Idaho Power with the IPUC on September 23, 2011 would, if approved, result in a 4.07 percent overall average increase in Idaho jurisdictional base rates, effective January 1, 2012, representing a $34 million base rate increase. For more information related to the settlement stipulation, see “Regulatory Matters” later in this MD&A.

•         Customers:  Changes related to a special industrial customer contract, along with small increments in customer count, increased general business revenues by $6.6 million and $10.3 million for the quarter and year-to-date, respectively, compared to the same periods in 2010.  For the quarter and year-to-date, customer count increased 0.7 percent and 0.3 percent, respectively, compared to the same periods in 2010.

•         Usage and weather:  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.

For the third quarter of 2011, higher usage increased general business revenue by $9.8 million compared to the third quarter of 2010. Irrigation usage increased 4.8 percent in the third quarter of 2011 compared to the same period in 2010 due to reduced precipitation, which resulted in irrigation customers increasing the use of irrigation pumps. Residential and commercial customer usage increased 4.9 percent and 2.4 percent, respectively, for the third quarter of 2011 as compared to the third quarter of 2010 due to a 24.4 percent increase in cooling degree days which drove increased demand for operation of air conditioning systems.

Year-to-date, higher usage increased general business revenue $14.2 million relative to the same period in 2010, due primarily to colder first quarter temperatures, which increases power demand for residential heating purposes, and for the reasons described above for the third quarter. This increase was partially offset by a 1.5 percent decrease in irrigation usage resulting from the cooler spring weather and the timing and amount of precipitation.

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The following table presents Boise, Idaho weather conditions for the three and nine months endedSeptember 30, 2011 and 2010:

	Three months ended September 30,			Nine months ended September 30,
	2011	2010	Normal	2011	2010	Normal
Heating degree-days (1)	10	70	137	3,438	3,111	3,478
Cooling degree-days (1)	969	779	646	1,054	886	802
Precipitation (inches)	0.11	0.39	1.15	8.01	9.01	8.06
(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.

Off-system sales:  Off-system sales consist primarily of long-term sales contracts and opportunity sales of surplus system energy.  The following table presents Idaho Power’s off-system sales for the three and nine months endedSeptember 30, 2011 and 2010: 

	Three months ended September 30,				Nine months ended September 30,
	2011		2010		2011		2010
Revenue	$	24,083	$	12,070	$	74,648	$	64,245
MWh sold	747		235		2,794		1,602
Revenue per MWh	$	32.24	$	51.36	$	26.72	$	40.10

For the quarter, off-system sales revenue increased $12.0 million, or 99.5 percent, as compared to the same period in 2010. Sales volumes for the quarter tripled, as increases in output from hydroelectric and PURPA contract wind resources increased surplus power available for sale. This increase was partially offset by a 37.2 percent decrease in average prices due to abundant energy supply in the region.  Due to an increase in the volume of MWh sold, year-to-date off-system sales revenue increased $10.4 million, or 16.2 percent, as compared to the same period of 2010 despite a 33.4 percent decrease in average prices.

Other revenues:  The table below presents the components of other revenues for the three and nine months endedSeptember 30, 2011 and 2010: 

	Three months ended September 30,				Nine months ended September 30,
	2011		2010		2011		2010
Transmission services and other	$	13,145	$	10,579	$	37,491	$	29,833
Energy efficiency	18,504		19,549		31,011		33,348
Total	$	31,649	$	30,128	$	68,502	$	63,181

Transmission services and other revenue increased $2.6 million and $7.7 million in the third quarter and first nine months of 2011, respectively, compared to the same periods in 2010 as a result of revenue received under the terms of an operating agreement relating to the Hemingway substation, which became effective in June 2010, and an increase in FERC transmission rates that took effect on October 1, 2010.

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 September 30, 2011, Idaho Power’s energy efficiency rider balance was a regulatory asset of $11.0 million, and Idaho Power expects the balance to decrease to $6.9 million by the end of 2011.

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Purchased power:  The following table presents Idaho Power’s purchased power expenses and volumes for the three and nine months endedSeptember 30, 2011 and 2010: 

	Three months ended September 30,				Nine months ended September 30,
	2011		2010		2011		2010
Expense
PURPA contracts	$	28,095	$	20,302	$	66,929	$	42,823
Other purchased power (including wheeling)	38,046		41,925		60,729		70,927
Total purchased power expense	$	66,141	$	62,227	$	127,658	$	113,750
MWh purchased
PURPA contracts	415		307		1,123		716
Other purchased power	559		621		1,034		1,186
Total MWh purchased	974		928		2,157		1,902
Cost per MWh from PURPA contracts	$	67.70	$	66.13	$	59.60	$	59.81
Cost per MWh from other sources	$	68.06	$	67.51	$	58.73	$	59.80
Weighted average - all sources	$	67.91	$	67.05	$	59.18	$	59.81

Purchased power expense increased $3.9 million, or 6 percent, in the third quarter of 2011 and $13.9 million, or 12 percent, year-to-date compared to the same periods in 2010. This increase was driven by MWh purchased from PURPA contracts, which increased 35 percent for the quarter and 57 percent year-to-date due to new PURPA wind generation facilities coming on-line. Reduced wholesale market purchases resulted from Idaho Power's above average hydroelectric generation in 2011.

Fuel expense:  The following table presents Idaho Power’s fuel expenses and generation at its thermal generating plants for the three and nine months endedSeptember 30, 2011 and 2010: 

	Three months ended September 30,				Nine months ended September 30,
	2011		2010		2011		2010
Expense
Coal	$	35,805	$	43,418	$	81,050	$	105,248
Natural gas and other	5,390		7,921		9,751		10,835
Total fuel expense	$	41,195	$	51,339	$	90,801	$	116,083
MWh generated
Coal	1,482		1,961		3,370		4,988
Natural gas and other	83		117		124		138
Total MWh generated	1,565		2,078		3,494		5,126
Cost per MWh
Coal	$	24.16	$	22.14	$	24.05	$	21.10
Natural gas and other	64.94		67.70		78.64		78.51
Weighted average, all sources	26.32		24.71		25.99		22.65

Fuel expense decreased $10.1 million, or 20 percent, in the third quarter of 2011 and $25.3 million, or 22 percent, year-to-date compared to the same periods in 2010 due to lower generation at Idaho Power's thermal plants. The output at these plants was down 0.5 million MWh, or 24 percent, in the quarter and 1.6 million MWh, or 32 percent, year-to-date compared to 2010. The reduced dispatch was primarily caused by lower regional power prices due to higher regional hydroelectric and wind generation. The impact of lower thermal generation was partially offset by higher coal prices. During 2010, the Bridger and Valmy generating plants received fuel from prior lower-cost contracts.

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.

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PCA mechanisms:  Idaho Power's power supply costs can vary significantly from year to year, primarily because of the impacts of weather, system loads, and commodity markets.  To address the volatility of power supply costs, Idaho Power has PCA mechanisms for 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, resulting in fluctuations in operating cash flows from year to year.

PCA expense represents the effects of the Idaho and Oregon power cost adjustment mechanisms.  The following table presents the components of the Idaho and Oregon PCA mechanisms for the three and nine months endedSeptember 30, 2011 and 2010: 

	Three months ended September 30,						Nine months ended September 30,
	2011			2010			2011		2010
Idaho power supply cost (deferral) accrual	$	(9,845	)	$	(27,742	)	$	25,756	$	(4,459	)
Oregon power supply cost (deferral) accrual	(159		)	(593		)	1,159		—
Amortization of prior year authorized balances	(185		)	7,401			9,703		59,920
Total power cost adjustment (benefit) expense	$	(10,189	)	$	(20,934	)	$	36,618	$	55,461

The power supply accruals or deferrals represent the portion of that periods' power supply cost fluctuations accrued or deferred under the PCA mechanisms.  If actual power supply costs are greater than the amount forecasted in PCA rates, most of the excess is deferred. Accruals represent additional costs recorded because actual power supply costs were less than the amount forecasted in PCA rates. 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 expenses:  Amortization of pension costs, plant maintenance costs, and labor-related costs were the primary drivers of increases in other O&M expense, which increased $12.6 million for the quarter and $21.5 million for the year-to-date period, compared to the same periods in 2010.  Pension and other benefit increases of $3.8 million for the quarter and $7.8 million year-to-date were primarily due to incremental amortization of pension costs concurrent with the regulatory authorization to recover those costs in revenues. Payroll-related expenses were higher by $2.5 million and $5.3 million for the quarter and year-to-date, respectively, relative to the same periods in 2010. The current year costs associated with thermal plant maintenance outage activities were largely in line with expectations but compared to 2010 were $1.0 million higher for the quarter and $6.0 million higher for the year. Finally, for the quarter and year to date, there was an increase of $1.6 million and $1.3 million, respectively, in water leases due to a combination of additional leased volumes and lease agreement cost escalation; these costs are collected through the PCA mechanism. For the year to date, these increases were partially offset by lower customer account and customer service expense of $2.8 million due to a combination of lower meter reading expense as a result of deployment of advanced metering infrastructure and the completed amortization of certain demand-side management program expenses.

Income Taxes

Income Tax Expense: IDACORP's and Idaho Power's income tax expense for the nine months endedSeptember 30, 2011, relative to the same period in 2010, decreased $38.9 million and $39.2 million, respectively, primarily as a result of an IRS examination settlement in 2011 related to Idaho Power's uniform capitalization tax accounting method. For information relating to IDACORP's and Idaho Power's computation of income tax expense and estimated annual effective tax rate, see Note 2 - “Income Taxes” to the condensed consolidated financial statements included in this report.

Idaho Power's January 2010 settlement agreement with the IPUC and other parties provided for additional amortization of ADITC if Idaho Power's actual return on year-end equity in its Idaho jurisdiction is below 9.5 percent in any calendar year from 2009 to 2011.  At the beginning of 2011, Idaho Power had up to $25 million of additional ADITC amortization available for use in 2011, in accordance with the settlement agreement. Idaho Power recorded $6.8 million of additional ADITC amortization for the first six months of 2011.  The additional ADITC amortization was reversed in the third quarter based on Idaho Power's estimate that its 2011 Idaho jurisdictional return on year-end equity will exceed 9.5 percent.

Status of Audit Proceedings and Tax Method Changes: In September 2010, Idaho Power adopted a tax accounting method change for capitalized repair expenditures on utility assets concurrent with the filing of IDACORP's 2009 consolidated federal income tax return. Also in 2010, Idaho Power reached an agreement with the IRS, subject to subsequent review by the Joint Committee, regarding the allocation of mixed service costs in its method of uniform capitalization.  Both methods were subject to audit under IDACORP's 2009 IRS examination.

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In April 2011, IDACORP and the IRS reached an agreement on Idaho Power's tax accounting method change for capitalized repairs. Accordingly, the IRS finalized the 2009 examination and submitted its report on the 2009 tax year to the Joint Committee for review. Idaho Power considers the capitalized repairs method effectively settled and believes that no material income tax uncertainties remain for the method. As such, Idaho Power recognized $3.4 million of its previously unrecognized tax benefits for this method in the second quarter of 2011.

In September 2011, the IRS notified IDACORP that the Joint Committee had completed its review and approved the uniform capitalization method agreement. Idaho Power considers the uniform capitalization method effectively settled and believes that no material income tax uncertainties remain for the method. Accordingly, Idaho Power recognized $56.9 million of its previously unrecognized tax benefits for tax years 2009 and prior in the third quarter of 2011. Idaho Power also increased its uniform capitalization tax deduction estimate in its current year tax provision which resulted in an additional $2 million income tax benefit for the nine months ended September 30, 2011.

Completion of the Joint Committee review allowed the IRS to finalize its 2009 examination, process the income tax changes, and close the case prior to September 30, 2011. In the fourth quarter, IDACORP and Idaho Power will pay previously accrued income tax liabilities of $3.9 million and $8.1 million, respectively, related to the capitalized repairs examination agreement. The difference in liabilities is due to IDACORP's utilization of deferred federal general business tax credits and Idaho investment tax credits. There are no 2011 cash impacts related to the uniform capitalization method settlement as income tax refunds for the method change were received in 2010. In early 2011, IDACORP requested and received the return of $13 million of previously made estimated tax payments for the 2010 tax year.

Bonus Depreciation Legislation: The Small Business Jobs Act (Jobs Act) and the Tax Relief, Unemployment Insurance Reauthorization, and Job Creation Act of 2010 (Tax Relief Act) includes provisions for the extension and increase of bonus depreciation.  Bonus depreciation provides for the accelerated deduction of current capital expenditures from certain asset classes.  The Jobs Act extended 50 percent bonus depreciation to 2010 and the Tax Relief Act extended bonus depreciation to 2011-2012 and increased it to 100 percent for a portion of 2010 and 2011.  Idaho Power has included an estimated bonus deprecation deduction in its current income tax provision. The estimated deduction would reduce Idaho Power's 2011 federal income tax liability by approximately $36 million. The State of Idaho did not conform to the federal bonus depreciation rules for 2010-2012.

LIQUIDITY AND CAPITAL RESOURCES

Overview

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

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

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

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IDACORP and Idaho Power expect minimal need for external financing in 2011, other than issuances of IDACORP common stock under the dividend reinvestment and employee-related plans and potentially issuances of IDACORP common stock pursuant to IDACORP's continuous equity program.  However, IDACORP and Idaho Power monitor debt market conditions and may issue debt securities when they determine that, under the circumstances and in light of the timing and extent of financing needs, conditions are favorable for issuance of debt securities. A significant focus for the remainder of 2011 and into 2012 will be to control costs and generate sufficient cash from operations to meet operating needs and contribute to capital expenditure requirements.

Beyond 2011, IDACORP and Idaho Power expect to continue financing capital requirements with a combination of internally generated funds and externally financed capital. Idaho Power expects it will continue to be engaged in significant construction projects during the coming years, and has $100 million of first mortgage bonds maturing in November 2012.

On October 26, 2011, each of IDACORP and Idaho Power entered into a Second Amended and Restated Credit Agreement with Wells Fargo Bank, National Association, as administrative agent, swingline lender, and LC issuer; JPMorgan Chase Bank, N.A., as syndication agent and LC issuer; KeyBank National Association and Union Bank, N.A., as documentation agents; Wells Fargo Securities, LLC, J.P. Morgan Securities Inc., Keybanc Capital Markets, and Union Bank, N.A. as joint lead arrangers and joint book runners; and the other financial institutions party thereto, as lenders. The new credit agreements amend and restate IDACORP's and Idaho Power's existing $100 million and $300 million, respectively, credit facilities dated April 25, 2007, that were to expire on April 25, 2012. The credit facilities will be used for general corporate purposes and commercial paper backup. IDACORP's credit agreement provides for the issuance 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 agreement provides for 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 agreements mature on October 26, 2016, though 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 is based on either (1) a base rate determined by 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 of October 28, 2011, 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 1.2 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 as of October 28, 2011. IDACORP is evaluating potential renewal of the program or entering into a similar program;

• Idaho Power's shelf registration statement, which can be used for the issuance of first mortgage bonds and debt securities; $300 million remained available under the shelf registration statement as of October 28, 2011; and

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

The conditions of the capital markets 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 impacted by this disruption in the credit environment, including in the commercial paper markets, and currently expect to continue to be able to access the capital markets to meet short- and long-term borrowing needs.

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Operating Cash Flows

IDACORP’s and Idaho Power’s operating cash inflows for the nine months endedSeptember 30, 2011 were $235 million and $227 million, respectively.  IDACORP's and Idaho Power's operating cash flows increased by $12 million and $31 million, respectively, compared to the nine months endedSeptember 30, 2010.  With the exception of cash flows related to income taxes, IDACORP’s operating cash flows are principally derived from the operating cash flows of Idaho Power.  Significant items that affected the companies' operating cash flows in the first nine months of 2011 relative to the same period in 2010 are as follows:

• income before income taxes decreased by $3 million for IDACORP and $5 million for Idaho Power;

• Idaho Power recorded an $18 million regulatory liability related to sharing in 2011, which reduced income before income taxes but did not reduce operating cash flows. No sharing was recorded during 2010;

• cash outflows related to the pension and postretirement benefit plans decreased by $44 million. An $18.5 million cash contribution was made in 2011 as compared with a $60 million cash contribution in 2010;

•      cash inflows related to income taxes increased by $12 million and $29 million for IDACORP and Idaho Power, respectively. IDACORP received income tax refunds of nearly $12 million in 2011 compared with net payments of $1 million in 2010. Idaho Power’s net refunds from IDACORP for income tax were $7 million for the nine months endedSeptember 30, 2011, compared with net payments of $22 million for the same period in 2010;

• changes in regulatory assets associated with the Idaho and Oregon PCA mechanisms reduced cash flows by $19 million, as Idaho Power collected $50 million less of previously deferred costs, partially offset by a $31 million increase in the current year accrual, as compared with the first nine months of 2010;

• changes in fuel inventories reduced operating cash flows by $18 million as fuel on hand increased by $22 million during the first nine months of 2011 due to decreased thermal plant operation, compared with $4 million during the same period in 2010; and

• changes in retail accounts receivable and unbilled revenue balances decreased cash flows by $14 million.

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 $260 million for the nine months endedSeptember 30, 2011, an increase of $30 million and $38 million for IDACORP and Idaho Power, respectively, over the nine months endedSeptember 30, 2010.  Investing cash outflows for 2011 were primarily for construction of utility infrastructure needed to address Idaho Power’s peak demand growth, aging plant and equipment, and forecasted customer growth. The most significant capital expenditure in 2011 is the Langley Gulch power plant, for which Idaho Power spent $115 million in the nine months endedSeptember 30, 2011

Financing Cash Flows

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

IDACORP’s and Idaho Power’s financing cash outflows for the nine months endedSeptember 30, 2011 were $172 million and $166 million, respectively.  The following are significant items that affected financing cash flows in 2011:

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

•      IDACORP and Idaho Power paid cash dividends of approximately $45 million.

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

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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 $300 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 September 30, 2011, 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 September 30, 2011 was limited to approximately $539 million. Idaho Power may increase the $2.0 billion limit on the maximum amount of first mortgage bonds outstanding by filing a supplemental indenture with the trustee as provided in the Indenture of Mortgage and Deed of Trust.

Credit Facilities: As described above, on October 26, 2011, IDACORP and Idaho Power executed new credit agreements that mature on October26,2016, which may be used for general corporate purposes and commercial paper back-up, and that provide for the issuance of loans and standby letters of credit. IDACORP's facility permits borrowings of up to $125 million at any one time outstanding, which may be increased, subject to specified conditions, to $150 million. Idaho Power's facility permits borrowings of up to $300 million at any one time outstanding, which may be increased, 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 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 0.65 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 September 30, 2011, the leverage ratios for IDACORP and Idaho Power were 48 percent and 50 percent, respectively. IDACORP's and Idaho Power's ability to utilize the credit facilities is conditioned upon their continued compliance with the leverage ratio covenants included in the credit facilities, which could limit the ability of the companies to issue first mortgage bonds and debt securities. There are additional covenants, subject to exceptions, that prohibit or restrict certain investments or acquisitions, mergers or sale or disposition of property without consent, the creation of certain liens, and any agreements restricting dividend payments from any material subsidiary. At October 28, 2011, 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

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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. The IPUC order provides that Idaho Power's authority will continue for 364 days from such downgrade, if Idaho Power promptly notifies the IPUC and files to continue its original authority to borrow. The Oregon statutes permit the issuance of short-term debt without approval of the OPUC.

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

The following table outlines available short-term borrowing liquidity as of the dates specified: 

	September 30, 2011						December 31, 2010
				Idaho						Idaho
	IDACORP(2)			Power			IDACORP(2)			Power
Revolving credit facility	$	100,000		$	300,000		$	100,000		$	300,000
Commercial paper outstanding	(51,500		)	—			(66,900		)	—
Identified for other use (1)	—			(24,245		)	—			(24,245		)
Net balance available	$	48,500		$	275,755		$	33,100		$	275,755
(1)  Port of Morrow and American Falls bonds that holders may put to Idaho Power.
(2)  Holding company only. As described above, on October 26, 2011, IDACORP executed a Second Amended and Restated Credit Agreement, increasing the maximum amount of borrowings under IDACORP's revolving credit facility to $125 million.

At October 28, 2011, IDACORP had no loans outstanding under its credit facility and $55 million of commercial paper outstanding, and Idaho Power had no loans outstanding under its credit facility and no commercial paper outstanding.

The following table presents additional information about short-term borrowing during the three- and nine-month periods ended September 30, 2011:

	Three months ended September 30,						Nine months ended September 30,
	IDACORP (1)			Idaho Power			IDACORP (1)			Idaho Power
Commercial paper:
Period end:
Amount outstanding	$	51,500		$	—		$	51,500		$	—
Weighted average interest rate	0.42		%	—		%	0.42		%	—		%
Daily average amount outstanding during the period	$	63,454		$	—		$	67,682		$	—
Weighted average interest rate during the period	0.40		%	—		%	0.40		%	—		%
Maximum month-end balance	$	64,000		$	—		$	74,400		$	—
(1) Holding company only

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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 following table 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.

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 September 30, 2011, Idaho Power had posted approximately $1.6 million of 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 additional requests by its wholesale counterparties to post additional performance assurance collateral.  Counterparties to derivative instruments and other forward contracts could request immediate payment or demand immediate ongoing full daily collateralization on derivative instruments and contracts in net liability positions.  Based upon Idaho Power’s current energy and fuel portfolio and market conditions as of September 30, 2011, the approximate amount of additional collateral that could be requested upon a downgrade to below investment grade is approximately $5 million.  Idaho Power actively monitors the portfolio exposure and the potential exposure to additional requests for performance assurance collateral calls, through sensitivity analysis, to minimize capital requirements.

Capital Requirements

Idaho Power's construction expenditureswere $267 million and $249 million during the nine months ended ended September 30, 2011 and 2010, respectively.  The following table presents Idaho Power's estimated cash requirements for construction, excluding AFUDC, for 2011 through 2013 (in millions of dollars): 

	2011	2012-2013
Ongoing capital expenditures	$187-189	$395-406
Langley Gulch Power Plant (detailed below)	121-125	35-39
Other major projects	12-16	20-25
Total	$320-330	$450-470

Major Infrastructure Projects:

Idaho Power is engaged in the development of a number of significant projects and has entered into and is in discussions with third parties concerning arrangements for joint infrastructure development. The discussion below provides a summary of notable developments with respect to certain of these projects during the nine months endedSeptember 30, 2011 and since the discussion of these matters included in Part II, Item 7 - “MD&A - Capital Requirements” in IDACORP's and Idaho Power's Annual Report on Form 10-K for the year ended December 31, 2010.

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Langley Gulch Power Plant:

The Langley Gulch Power Plant is a natural gas-fired combined cycle combustion turbine generating plant with a summer nameplate capacity of approximately 300 MW and a winter capacity of approximately 330 MW. Construction of the plant, substation, and transmission lines is in process. The plant is being constructed near New Plymouth, Idaho and is contracted to achieve commercial operation by November 1, 2012. Based on contract incentives and the current project status, Idaho Power estimates that the plant will be in service by June 2012. The commitment estimate for the project is $427 million, $321 million of which Idaho Power has incurred from inception in 2009 through September 30, 2011. AFUDC is included in both amounts. As of the date of this report, the overall project remains on schedule and Idaho Power expects the total project cost to be at or below the commitment estimate.

In September 2009, the IPUC issued an order providing Idaho Power assurance and pre-approval to include $396.6 million of construction costs in Idaho Power’s rate base when Langley Gulch achieves commercial operation. The order contemplates that Idaho Power may request recovery of additional costs if they exceed $396.6 million, provided that Idaho Power is able to demonstrate that the additional costs were reasonably and prudently incurred.

During the third quarter of 2011, plant construction activities continued. Major equipment incorporated into the project during the third quarter of 2011 included installation of steam piping, major electrical equipment, and the delivery and initial setting of the steam turbine equipment. The water delivery system that will provide cooling water to the site was completed and commissioned during the third quarter of 2011. The natural gas delivery system, including the gas pipeline lateral and metering station, was also completed during the third quarter of 2011. The plant will connect to Idaho Power's existing grid through a new substation and two new transmission lines. The substation is under construction and on schedule. One of the new transmission lines has been constructed and incorporated into the grid, while the other is under design. The second transmission line is expected to be completed by May 2012.

Transmission Projects; Termination of Memorandum of Understanding:

As described in its 2011 Integrated Resource Plan (IRP), Idaho Power continues to focus on expansion of its existing transmission system in an effort to improve system reliability and resource adequacy. Two significant transmission projects in which Idaho Power has been recently involved include the Boardman-Hemingway line, a proposed 299 mile, 500-kV transmission project between a station near Boardman, Oregon and the Hemingway station near Boise, Idaho, and Idaho Power's and PacifiCorp's pursuit of the joint development of the Gateway West project to build transmission lines between a station located near Douglas, Wyoming and the Hemingway station. 

On March 5, 2010, Idaho Power and PacifiCorp entered into a Memorandum of Understanding (MOU) under which Idaho Power and PacifiCorp agreed to negotiate in good faith to reach arrangements pertaining to, among other items, the sale by the parties to one another of an undivided ownership interest in certain transmission facilities, and joint development and construction of three transmission projects, including the Boardman-Hemingway and Gateway West projects. 

In April 2010, Idaho Power and PacifiCorp entered into an arrangement pursuant to which they agreed to sell to one another interests in certain high-voltage transmission-related and interconnection equipment, and in May 2010 executed agreements pertaining to the joint ownership and operation of portions of those facilities. In subsequent months, Idaho Power and PacifiCorp sought to negotiate the terms and conditions of the other arrangements contemplated by the MOU, including the Boardman-Hemingway and Gateway West transmission projects, but were unable to reach agreement on those arrangements, and the MOU was ultimately terminated in April 2011. Notwithstanding termination of the MOU, Idaho Power continues to pursue the joint development of the Boardman-Hemingway transmission line with one or more parties and continues its participation with PacifiCorp in the permitting process for the Gateway West transmission project. Idaho Power increased its estimate of capital expenditures associated with 2011 Boardman-Hemingway transmission line activities by $8 million in the second quarter of 2011, based on its assumption that it will be responsible for all project expenses during 2011. Idaho Power expects that a portion of the permitting expenses will be reimbursed in a subsequent year or years by other parties who participate in the project, pro rata based on the respective parties' ownership of the transmission line.

On July 29, 2011, the U.S. Bureau of Land Management (BLM) issued for public review and comment a draft environmental impact statement (EIS) for the Gateway West project. The draft EIS did not identify a preferred route for the project. Idaho Power submitted comments relating to the draft EIS to the BLM in October 2011.

The Obama Administration announced on October 5, 2011 the Rapid Response Team for Transmission (RRTT) pilot program to streamline federal permitting and increase cooperation at the federal, state, and tribal levels for several transmission projects. The Boardman-Hemingway and Gateway West projects are included in the RRTT pilot. Idaho Power has reviewed the RRTT pilot but, given the complexity of the projects and number of parties involved, is unable to predict whether the pilot will have an impact on the timing or ultimate cost of the Boardman-Hemingway or Gateway West projects.

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

The advanced metering infrastructure (AMI) project provides the means to automatically retrieve energy consumption information, eliminating manual meter reading expense. Idaho Power intends to install this technology for approximately 99 percent of its customers and is on pace to complete the installations by the end of 2011. As of September 30, 2011, Idaho Power had installed approximately 468,000 AMI meters at a cost of $70 million. The total cost estimate for the project is approximately $74 million. The 2011 estimated costs are included in the Capital Requirements table above.

Under the ARRA, Idaho Power was awarded a grant of $47 million from the U.S. Department of Energy (DOE). This grant matches a $47 million investment by Idaho Power in Smart Grid technology, including AMI. The grant was signed by the DOE on April 2, 2010 and applies to project costs incurred beginning in August 2009. As of September 30, 2011, Idaho Power had invoiced approximately $31 million from the DOE, of which $28.4 million had been received, and expects to continue billing and collecting monthly over the three-year term of the award. The costs to be reimbursed by the grant are not included in the Capital Requirements table above.

Contractual Obligations

The following items are the only material changes to contractual obligations, outside of the ordinary course of business, during the nine months endedSeptember 30, 2011:

• Idaho Power entered into several power purchase agreements with wind and other alternative energy developers.  Payments pursuant to these agreements are expected to total approximately $128 million from 2011 to 2037.

• The IPUC issued orders on June 8, 2011 that disapproved 13 wind power purchase agreements. The orders were subject to a 21-day reconsideration period and reconsiderations were denied by the IPUC on July 27, 2011. Idaho Power considers these agreements terminated, though two of the projects have filed appeals with the Idaho Supreme Court. Payments pursuant to these 13 agreements were expected to total approximately $1.3 billion over the terms of the agreements and had been reported as contractual obligations in the Annual Report on Form 10-K for the year ended December 31, 2010.

• Uncertain tax positions reported as of December 31, 2010 have been resolved in favor of Idaho Power.

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

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. Notable pending 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. Except where noted in Note 9 - "Contingencies," 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.

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REGULATORY MATTERS

Overview

As a regulated utility, many of Idaho Power's fundamental business decisions are subject to the approval of governmental agencies. Idaho Power is under the retail jurisdiction (as to rates, service, accounting, and other general matters of utility operation) of the IPUC and the OPUC, which determine the rates that Idaho Power charges to its general business customers.  Idaho Power is also under the regulatory jurisdiction of the IPUC, the OPUC, and the Public Service Commission of Wyoming as to the issuance of debt and equity securities.  Also, as a public utility under the Federal Power Act, Idaho Power has authority to charge market-based rates for wholesale energy sales under its FERC tariff and to provide transmission services under its FERC 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, 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 of IDACORP's and Idaho Power's Annual Report on Form 10-K for the year ended December 31, 2010, refer to Note 3 - “Regulatory Matters” to the condensed consolidated financial statements included in this report for additional information and updates relating to Idaho Power's regulatory matters and recent regulatory filings and orders.

Change in Deferred Net Power Supply Costs

The table below summarizes the change in deferred net power supply costs during the nine months endedSeptember 30, 2011:

	Idaho			Oregon(1)			Total
Balance at December 31, 2010	$	17,559		$	12,194		$	29,753
Current period net power supply costs accrued	(25,756		)	(1,159		)	(26,915		)
Prior costs expensed and recovered through rates	(7,891		)	(1,812		)	(9,703		)
Transfer of energy efficiency funds	10,000			—			10,000
SO2 allowance and renewable energy certificate (REC) sales	(4,551		)	(382		)	(4,933		)
Interest and other	(85		)	478			393
Balance at September 30, 2011	$	(10,724	)	$	9,319		$	(1,405	)
(1)  Oregon power supply cost deferrals are subject to a statute that specifically limits rate amortizations of deferred costs to six percent of gross Oregon revenue per year (approximately $2 million).  Deferrals are amortized sequentially.

Idaho General Rate Case and Filing of Settlement Stipulation

On June 1, 2011, Idaho Power filed a general rate case and proposed rate schedules for the Idaho jurisdiction with the IPUC, Case No. IPC-E-11-08. On September 23, 2011, Idaho Power, the Staff of the IPUC, 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. The settlement stipulation is subject to approval by the IPUC. The settlement stipulation, if approved, would result in a 4.07 percent overall average increase in Idaho Power's annual Idaho jurisdictional base rate revenues, effective January 1, 2012.

In its general rate case application, Idaho Power requested an additional $82.6 million in annual revenues in Idaho-jurisdictional base rates, comprised of approximately $71.3 million related to revenue requirement categories other than net power supply expenses (non-NPSE) and $11.3 million associated with net power supply expenses (NPSE). The settlement stipulation provides for a decrease of approximately $25.8 million to the requested non-NPSE recovery, resulting in a $45.5 million increase in the non-NPSE components of Idaho jurisdictional base rates. The settlement stipulation also provides that approximately $22.8 million of Idaho jurisdictional revenue associated with the recovery of NPSE associated with PURPA power costs would not be included in base rates, but would instead be eligible for 100 percent recovery through the Idaho PCA mechanism if the costs are incurred. Idaho Power's requested Idaho jurisdictional base rate increase and the adjustments reflected in the settlement stipulation are summarized in the table below (in millions).

	Non-NPSE			NPSE			Total
As-Filed in General Rate Case	$	71.3		$	11.3		$	82.6
Adjustments in Settlement Stipulation	(25.8		)	(22.8		)	(48.6		)
Settlement Stipulation Result	$	45.5		$	(11.5	)	$	34.0

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The settlement stipulation provides for a 7.86 percent authorized rate of return on an Idaho-jurisdictional rate base of approximately $2.36 billion, and for the IPUC to allow Idaho Power to earn an authorized rate of return of 7.86 percent in any Idaho Power regulatory matter until subsequently changed by IPUC order. Idaho Power had requested an 8.17 percent rate of return in its general rate case application.

The settlement stipulation also addresses Idaho Power's calculation of the load change adjustment rate ("LCAR") to be applied in Idaho Power's PCA mechanism. The LCAR adjusts power supply cost recovery within the Idaho PCA formula by adjusting recovery upwards or downwards for differences between actual load and the load used in calculating base rates. The settlement stipulation provides for an LCAR of $18.16 per MWh, compared to the current rate of $19.67 per MWh, to become effective on the date that Idaho Power's new base rates become effective.

The settlement stipulation does not resolve all matters included in Idaho Power's general rate case. The parties to the settlement stipulation agreed that certain matters would be examined in either separate, subsequent proceedings or continued in the general rate case docket. Those additional matters relate to, among other items, determining whether the FCA pilot program, which separates (or decouples) the recovery of fixed costs from the variable kilowatt-hour charge and links it instead to a set amount per customer, should be made permanent as well as determining the appropriate percentage amount for Idaho Power's energy efficiency rider. The settlement stipulation provides that these subsequent proceedings will not impact the agreements reached in the settlement stipulation.

The parties to the settlement stipulation have requested that the IPUC issue an order approving the agreed-upon rates effective January 1, 2012. Idaho Power is unable to predict whether the IPUC will approve the settlement stipulation or the ultimate outcome of the general rate case proceedings.

Application for Extension of Certain Provisions of the January 2010 Settlement Agreement

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 accelerated amortization of ADITC to help achieve a minimum 9.5 percent return on year-end equity in the Idaho jurisdiction, and (b) an equal sharing of any Idaho jurisdiction earnings exceeding a return on year-end equity of 10.5 percent in the Idaho jurisdiction.  Recognition of tax benefits in the third quarter of 2011 had a significant impact on Idaho Power's estimate of return on 2011 year-end equity and contributed to triggering of the sharing mechanism under the settlement agreement. As a result of the terms of the settlement agreement, Idaho Power also recorded an $18.1 million regulatory liability, reflecting 50 percent of Idaho Power's estimated Idaho jurisdictional earnings over a 10.5 percent return on year-end equity required to be shared with customers.

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 with the following terms:

• If Idaho Power's Idaho jurisdiction return on year-end equity for 2012 or 2013 is less than 9.5 percent, then Idaho Power may continue to use up to $45 million of deferred investment tax credits to help achieve a minimum 9.5 percent return on year-end equity in the Idaho jurisdiction in those years. Idaho Power may use an aggregate of $45 million of additional ADITC in 2012 and 2013, comprised of up to a maximum of $25 million of additional ADITC in 2012 and any unused portion carried forward to 2013.

• If Idaho Power's Idaho jurisdictional return on year-end equity for 2012 or 2013 exceeds 10.0 percent, the amount exceeding 10.0 percent would be shared equally between Idaho Power and its customers in the applicable year.

• Idaho Power would allocate to customers 50 percent of Idaho Power's share of estimated 2011 Idaho jurisdictional earnings over a 10.5 percent return on year-end equity, reflected as a reduction in customer rates or an offset to amounts that would otherwise be collected from rates.

The application provides that it is independent and separate from the 2011 general rate case proceeding and the associated settlement stipulation, and further provides that Idaho Power will withdraw the application in the event Idaho Power's base rate revenues are not increased in accordance with the terms of the general rate case settlement stipulation. The application also states that Idaho Power's proposal to apply a one-time adjustment to the 2011 sharing calculation is contingent on the completion of a signed settlement stipulation agreeing to the extension and modification of the ADITC amortization and sharing mechanisms, as described above, on or before December 31, 2011.

If the IPUC approves Idaho Power's application, Idaho Power would be required to record a fourth quarter 2011 charge for the additional share of estimated Idaho jurisdictional earnings over a 10.5 percent return on year-end equity allocated to customers.

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Idaho Power estimates that the amount of the charge would be approximately $10 million on a pre-tax basis, based on its estimate of full year 2011 return on equity. As of the date of this report, Idaho Power is unable to predict the outcome the proceedings and, accordingly, whether such a charge will be required.

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 requests a $5.8 million increase in annual Oregon jurisdictional revenues, which if approved would result in a 14.7 percent overall average rate increase for customers in the Oregon jurisdiction. The filing requests an authorized rate of return on equity of 10.5 percent with an Oregon retail rate base of approximately $121.9 million, and a rate of return on capital of 8.17 percent. As of the date of this report, Idaho Power is unable to predict the outcome of the Oregon general rate case. Idaho Power anticipates that new rates, if approved by the OPUC, would not be effective until June 1, 2012.

2011 Integrated Resource Plan

As a public utility under the jurisdiction of the FERC, the IPUC, and the OPUC, Idaho Power is obligated to plan for and expand its transmission system to provide requested firm transmission service to third parties, to construct and place in service sufficient generation and transmission capacity to reliably deliver resources to network customers and the company’s retail customers, and otherwise take actions to fulfill its obligation to provide safe and reliable electric service. As part of its resource planning, and in accordance with regulatory requirements, Idaho Power prepares and publishes an IRP every two years. The IRP addresses available supply-side and demand-side resource options, planning period load forecasts, potential resource portfolios, a risk analysis, and near-term and long-term action plans.

Idaho Power filed its 2011 IRP with the IPUC and OPUC on June 30, 2011. In developing its 2011 IRP, Idaho Power forecast the number of customers in Idaho Power’s service area will increase approximately 1.5 percent per year, from approximately 492,000 at the end of 2010 to over 650,000 by the end of the IRP's 20-year planning period in 2030. The 2011 IRP expected-case load forecast projects peak-hour load will grow 69 MW annually and average-system load will increase annually 29 average MW (aMW) over the 20-year planning period, with an expected-case, median, average annual system load of 2,362 aMW by 2030.

Idaho Power intends to meet the anticipated increase in demand through energy efficiency and demand response programs, the development of transmission capacity and additional generation resources, such as its 300 MW Langley Gulch natural gas-fired power plant currently under construction, and from the purchase of power from third parties, including from renewable energy projects and market power purchases. Idaho Power stated in the 2011 IRP that it expects energy efficiency programs to result in 233 aMW of load reduction by 2030, and that demand response programs are targeted to reduce peak summer load by 351 MW by summer 2016. The 2011 IRP also identifies transmission constraints as a significant current issue for Idaho Power. Idaho Power is currently in the process of developing the Boardman-Hemingway transmission project in an effort to alleviate in part its current transmission capacity constraint from the Pacific Northwest.

PURPA Power Purchase Contracts

Pursuant to the requirements of Section 210 of PURPA, the IPUC and OPUC have each issued orders and rules regulating Idaho Power's purchase of power from cogeneration and small power production facilities.  A key component of the PURPA power purchase contracts is the energy price contained within the agreements.  Regulatory-mandated execution of PURPA agreements may result in Idaho Power acquiring energy it does not need at above wholesale market prices and require additional operational integration measures, thus increasing costs to Idaho Power's customers.  Substantially all PURPA power purchase costs are recovered through base rates and Idaho Power's power supply cost mechanisms, and thus the primary impact of the PURPA agreements is on customer rates. 

In response to a November 5, 2010 application filed by Idaho Power and two other electric utilities with Idaho service territories, on February 7, 2011, the IPUC issued an order temporarily reducing the eligibility cap for PURPA projects entitled to published avoided cost rates from 10 aMW to 100 kW for wind and solar PURPA projects while the IPUC further investigated the implications of large projects disaggregating into smaller projects to qualify for higher published avoided cost rates and other benefits. On June 8, 2011, the IPUC issued an order maintaining the 100 kW eligibility cap for published avoided cost rates for wind and solar PURPA projects, and initiating additional proceedings to allow the parties to investigate and analyze the methodologies used in determining the appropriate power purchase price for PURPA projects. On that same date, the IPUC issued orders disapproving 13 wind power purchase agreements. Idaho Power estimates that the payments over the life of the disapproved agreements would have totaled approximately $1.3 billion. Under existing regulatory mechanisms, the primary impact of the power purchase costs would have been on customer rates.

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Bonneville Power Administration Residential Exchange Program

The Pacific Northwest Electric Power Planning and Conservation Act of 1980, through the Residential Exchange Program (REP), has provided access to the benefits of low-cost federal hydroelectric power to residential and small farm customers of the region's investor-owned utilities (IOUs).  The program is administered by the Bonneville Power Administration (BPA).  Pursuant to agreements between the BPA and Idaho Power, benefits from the REP were passed through to Idaho Power’s Idaho and Oregon residential and small farm customers in the form of electricity bill credits. However, on May 3, 2007, the U.S. Court of Appeals for the Ninth Circuit ruled that the settlement agreements entered into between the BPA and the IOUs (including Idaho Power) are inconsistent with the Northwest Power Act. As a result, on May 21, 2007, the BPA notified Idaho Power and six other IOUs that it was immediately suspending the REP payments. Since that time, Idaho Power has been working with other northwest IOUs and consumer-owned utilities, Pacific Northwest public utility commissions, and the BPA to craft an agreement so that residential and small farm customers of Idaho Power can resume sharing in the benefits of the federal Columbia River power system.

In April 2011, pursuant to a previously executed Agreement in Principle, several parties approved a settlement agreement resolving challenges over BPA's implementation of the REP; however, the settlement agreement failed to receive approval from a pre-established threshold of BPA's customers and stakeholders and therefore did not become effective. The threshold level of customers and stakeholders needed to approve the settlement agreement was subsequently lowered, and in June 2011 the BPA announced that it had received signed contracts from the revised requisite threshold of customers and stakeholders needed to approve the REP settlement agreement. The BPA Administrator approved the REP settlement agreement in a Record of Decision dated July 26, 2011 and committed the BPA to perform its obligations under the settlement agreement in accordance with its terms. The settlement includes a commitment by the parties to seek legislation that would affirm the settlement. Updated rates became effective October 1, 2011. However, since any benefits would pass directly through to Idaho Power's eligible residential and small farm customers, the settlement is not expected to have a material effect on Idaho Power's financial condition or results of operations.

FERC Compliance Programs

The FERC has approved an extensive number of reliability standards developed by the North American Electric Reliability Corporation and the Western Electricity Coordinating Council (WECC), including critical infrastructure protection (CIP) standards and regional standard variations. As part of its compliance program, Idaho Power periodically reviews its operations for compliance with FERC rules, orders, and standards and self-reports compliance issues to the FERC and the WECC. Recent reports Idaho Power has submitted to the FERC have generally focused on Standards of Conduct and Idaho Power’s FERC OATT. Idaho Power has also self-reported matters relating to CIP and other reliability standards to the WECC. During the nine months endedSeptember 30, 2011, Idaho Power self-reported to the FERC and received notices of alleged violations from the FERC and the WECC. Idaho Power has also received notification that the FERC intends to take no further action regarding several issues previously reported by Idaho Power.

Consistent with its historical practice, Idaho Power is working with the FERC and the WECC to resolve alleged violations and items it self-reported to the FERC and the WECC. Idaho Power is unable to predict what action, if any, the WECC or the FERC will take on those unresolved matters, but based on the nature of the potential violations Idaho Power does not expect any material adverse effect on its financial position, results of operations, or cash flows. Idaho Power plans to continue its efforts to reduce potential violations through its compliance program and its approach of self-reporting compliance issues to, and working with, the FERC and the WECC.

Relicensing of Hydroelectric Projects

Costs for the relicensing of Idaho Power's hydroelectric projects are recorded in construction work in progress until new multi-year licenses are issued by the FERC, at which time the charges are transferred to electric plant in service. Relicensing costs and costs related to new licenses will be submitted to regulators for recovery through the ratemaking process. Relicensing costs of $141 million and $5 million for the HCC and Swan Falls projects, respectively, were included in construction work in progress at September 30, 2011. As of the date of this report, the IPUC authorizes Idaho Power to include in rates approximately $6.8 million annually ($10.6 million grossed up for income taxes) of AFUDC relating to the HCC relicensing project, and collecting these amounts will reduce the relicensing amount submitted to regulators for recovery through the ratemaking process.

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ENVIRONMENTAL MATTERS

Idaho Power is subject to a broad range of federal, state, regional, and local laws and regulations designed to protect, restore, and enhance the environment.  Current and pending legislation relates to, among other items, climate change, greenhouse gas emissions and air quality, renewable energy standards (RES), mercury and other emissions, hazardous wastes, and polychlorinated biphenyls.  In addition to imposing continuing compliance obligations 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 EPA and various other state and local agencies. All such laws and regulations are subject to a range of interpretation, which may ultimately be resolved by the courts.  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 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.

The discussion below provides 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, 2010. Also, refer to Note 9 - “Contingencies” to the condensed consolidated financial statements included in this report for additional information regarding certain environmental proceedings affecting Idaho Power's properties.

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.  Mercury continuous emission monitoring systems have been installed on all of the coal-fired units at the Jim Bridger, Boardman, and Valmy generating plants.  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 CAA. In the same notice, the EPA further proposed to revise the NSPS for fossil fuel-fired EGUs. The proposed regulation would impose maximum achievable control technology and NSPS standards on all coal-fired EGUs and would replace the former Clean Air Mercury Rule. Specifically, the proposed regulation would set numeric emission limitations on coal-fired EGUs for total particulate matter (a surrogate for non-mercury HAPs), hydrogen chloride, and mercury. In addition, the proposed regulation would impose a work practice standard for organic HAPs, including dioxins and furans. For the revised NSPS, for EGUs commencing construction of a new source after publication of the proposed regulation, the EPA would establish amended emission limitations for particulate matter, sulfur dioxide, and nitrogen oxides. The final rule is expected in November 2011. Idaho Power is reviewing the proposed regulations 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, as proposed, with current and planned control technologies.

Environmental Regulation Slowdown: On September 2, 2011, President Obama asked the EPA to withdraw a proposal to tighten the National Ambient Air Quality Standards for ozone. This was followed on September 23, 2011, with the U.S. House of Representatives passing H.R. 2401 entitled, “Transparency in Regulatory Analysis of Impacts on the Nation Act of 2011” (TRAIN Act). If enacted into law, the TRAIN Act would require a review of a number of recent EPA rules and regulations, including the air quality standards for fine particulate matter, ozone, sulfur dioxide, and nitrogen dioxide. In addition, the TRAIN Act would require a review of the Industrial Boiler MACT, Utility MACT, and Coal Combustion Residuals EPA rules. The review would be focused on the economic impacts and competitive impacts of these rules on the U.S. economy. The ultimate status and impacts of these administrative and legislative actions is not clear, but could result in the delay of promulgation and implementation of some environmental rules and regulations impacting Idaho Power.

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Boardman Power Plant Rulemaking and Proceedings:Following the introduction of various plans and an extensive public process, in December 2010 the Oregon Environmental Quality Commission (OEQC) approved a plan to cease coal-fired operations at the Boardman power plant no later than December 31, 2020. The rules implementing the plan were approved by the EPA and published in the Federal Register in July 2011, and require the installation of a number of emissions controls. The new rules repeal the OEQC's 2009 Best Available Retrofit Technology rule, which would have allowed continued operation of the Boardman plant through at least 2040 with installation of a more extensive suite of emissions controls. The estimated combined total capital cost of the required controls under the plan approved by the OEQC is approximately $60 million. Idaho Power is a 10 percent owner of the Boardman plant, and thus Idaho Power's estimated share of the capital cost is $6 million, which is in addition to normal capital expenditures and maintenance costs. At September 30, 2011, Idaho Power's net book value in the Boardman plant was approximately $21.8 million with annual depreciation of approximately $1.3 million.

The scheduled 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, on September 26, 2011, Idaho Power filed an application with the IPUC requesting an order accepting Idaho Power's regulatory accounting and cost recovery plan associated with the early 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. In its application, Idaho Power did not seek current approval for rate recovery of future expenses associated with the shut-down of coal-fired operations, but estimated that the incremental Idaho jurisdictional annual revenue deficiency associated with early shut-down is approximately $1.4 million.

Public Nuisance-Related Suits for GHGs: In December 2010, the U.S. Supreme Court granted certiorari in Connecticut v. American Electric Power, Inc., to review the opinion from the U.S. Court of Appeals for the Second Circuit granting plaintiffs standing to bring climate change-related public nuisance suits against six major emitters of greenhouse gases (GHGs). On June 20, 2011, the U.S. Supreme Court held that federal courts do not have jurisdiction to hear federal common law nuisance claims relating to GHG emissions, because the legal authority to regulate GHGs has been delegated by Congress to the EPA, not to federal courts. Even though the Court rejected the merits of the plaintiffs' claim, the Court nevertheless held that the plaintiffs had the requisite legal standing to bring the claims. Finally, the Court remanded to the Second Circuit the issue of whether state common law nuisance claims would also be barred by the federal CAA. Accordingly, the decision of the Supreme Court in this case does not eliminate the potential for future nuisance-related suits based on GHG emissions.

Renewable Energy and PURPA Contracts - Wind: As of September 30, 2011, Idaho Power had contracts to purchase energy from 18 on-line wind projects with a combined nameplate rating of 395 MW.  At that date, Idaho Power also had signed and commission-approved PURPA contracts to purchase energy from an additional 16 wind projects with a combined nameplate rating of 363 MW.  These projects are expected to be online between mid-2011 and the end of 2012.  In addition, at September 30, 2011, 13 contracts with a combined nameplate capacity of 294 MW that had previously sought IPUC approval were denied approval by the IPUC. Filings for reconsiderations at the IPUC for these contracts have been processed and also denied. Two of the projects (equaling 42 MW) have filed for reconsideration of this ruling with the Idaho Supreme Court. Also, in June 2011 Idaho Power entered into a purchase power agreement for an additional 20 MW solar project with an expected online date of September 2012, and the IPUC approved the agreement in October 2011.

REC Sales: Idaho Power is selling its near-term renewable energy certificates (RECs) and returning to customers their share of those proceeds through the PCA.  Idaho Power filed a REC Management Plan with the IPUC in December 2009 to address its treatment of future RECs.  Under Idaho Power's REC Management Plan, Idaho Power would sell near-term RECs, while continuing to acquire and hold long-term contractual rights to own RECs for use in meeting future RES requirements.  For the nine months endedSeptember 30, 2011, Idaho Power's REC sales totaled $5.2 million.

OTHER MATTERS

Critical Accounting Policies and Estimates

IDACORP’s and Idaho Power’s discussion and analysis of their financial condition and results of operations are based upon their condensed consolidated financial statements, which have been prepared in accordance with generally accepted accounting principles.  The preparation of these financial statements requires IDACORP and Idaho Power to make estimates and judgments that affect the reported amounts of assets, liabilities, revenues and expenses and related disclosure of contingent assets and liabilities.  On an ongoing basis, IDACORP and Idaho Power evaluate these estimates, including those estimates related to rate regulation, benefit costs, contingencies, litigation, impairment of assets, income taxes, unbilled revenue, and bad debt.  These estimates are based on historical experience and on other assumptions and factors that are believed to be reasonable under the circumstances, and are the basis for making judgments about the carrying values of assets and liabilities

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that are not readily apparent from other sources.  IDACORP and Idaho Power, based on their ongoing reviews, make adjustments when facts and circumstances dictate.

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

Recently Issued Accounting Pronouncements

There have been no recently issued accounting pronouncements that have had or are expected to have a material impact on IDACORP's or Idaho Power's results of operations or financial condition. See Note 1 - “Summary of Significant Accounting Policies” to the condensed consolidated financial statements included in this report.

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 September 30, 2011.

Interest Rate Risk

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

Variable Rate Debt:  As of September 30, 2011, IDACORP and Idaho Power had $75.6 million and $24.1 million, respectively, in net floating-rate debt. The fair market value of this debt was $75.6 million and $24.1 million, respectively. Assuming no change in financial structure, if variable interest rates were to average one percentage-point higher than the average rate on September 30, 2011, interest rate expense would increase and pre-tax earnings would decrease by approximately $0.8 million for IDACORP and $0.2 million for Idaho Power.

Fixed Rate Debt:  As of September 30, 2011, 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 $195 million for both IDACORP and Idaho Power if interest rates were to decline by one percentage point from their September 30, 2011 levels.

Commodity Price Risk

Idaho Power's exposure to changes in commodity prices is related to its ongoing utility operations that produce electricity to meet the demand of its retail electric customers. To supplement its generation resources and balance its supply of power with the demand of its retail customers, Idaho Power participates in the wholesale marketplace. IDACORP’s and Idaho Power’s commodity price risk as of September 30, 2011 had not changed materially from that reported in Item 7A of IDACORP's and Idaho Power's Annual Report on Form 10-K for the year ended December 31, 2010.  Information regarding Idaho Power’s use of derivative instruments to manage commodity price risk can be found in Note 12 – “Derivative Financial Instruments” to the condensed consolidated financial statements included in this report.

Credit Risk

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

The use of performance assurance collateral in the form of cash, letters of credit, or guarantees is common industry practice.  Idaho Power maintains margin agreements relating to its wholesale commodity contracts that allow performance assurance

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collateral to be requested of and/or posted with certain counterparties.  As of September 30, 2011, Idaho Power had posted approximately $1.6 million of 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 additional requests by its wholesale counterparties to post additional performance assurance collateral.  Counterparties to derivative instruments and other forward contracts could request immediate payment or demand immediate ongoing full daily collateralization on derivative instruments and contracts in net liability positions.  Based upon Idaho Power's current energy and fuel portfolio and market conditions as of September 30, 2011, the approximate amount of additional collateral that could be requested upon a downgrade to below investment grade is approximately $5 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 September 30, 2011 had not changed materially from that reported in Item 7A of IDACORP's and Idaho Power's Annual Report on Form 10-K for the year ended December 31, 2010.

Equity Price Risk

IDACORP and Idaho Power are exposed to price fluctuations in equity markets, primarily through their defined benefit pension plan assets, a mine reclamation trust fund owned by an equity-method investment of Idaho Power, and other equity investments at Idaho Power. IDACORP’s and Idaho Power’s equity price risk as of September 30, 2011 had not changed materially from that reported in Item 7A of IDACORP's and Idaho Power's Annual Report on Form 10-K for the year ended December 31, 2010.

ITEM 4.  CONTROLS AND PROCEDURES

Disclosure Controls and Procedures

IDACORP:  The Chief Executive Officer and the Chief Financial Officer of IDACORP, based on their evaluation of IDACORP’s disclosure controls and procedures (as defined in Exchange Act Rule 13a-15(e)) as of September 30, 2011, have concluded that IDACORP’s disclosure controls and procedures are effective as of that date.

Idaho Power:  The Chief Executive Officer and the Chief Financial Officer of Idaho Power, based on their evaluation of Idaho Power’s disclosure controls and procedures (as defined in Exchange Act Rule 13a-15(e)) as of September 30, 2011, have concluded that Idaho Power’s disclosure controls and procedures are effective as of that date.

Changes in Internal Control Over Financial Reporting

There have been no changes in IDACORP’s or Idaho Power’s internal control over financial reporting during the quarter ended September 30, 2011, that have materially affected, or are reasonably likely to materially affect, IDACORP’s or Idaho Power’s internal control over financial reporting.

PART II – OTHER INFORMATION

ITEM 1.  LEGAL PROCEEDINGS

Please refer to Note 9 - “Contingencies” to the condensed consolidated financial statements included in this report for information regarding certain legal and administrative proceedings in which the registrants are involved, including an update on the Pacific Northwest refund proceedings.

ITEM 1A.  RISK FACTORS

The factors discussed in Part I - Item 1A - “Risk Factors” in IDACORP’s and Idaho Power’s Annual Report on Form 10-K for the year ended December 31, 2010, could materially affect IDACORP’s and Idaho Power’s business, financial condition, or future results. The following supplements the factors discussed in that report:

Acts or threats of terrorism, cyber attacks, security breaches, and other acts of individuals or groups seeking to disrupt Idaho Power Company's operations, or the businesses of third parties, could result in reduced revenues and increased costs.

Idaho Power Company's generation and transmission facilities are potential targets for terrorist acts and threats, as well as cyber attacks and other disruptive activities of individuals or groups.  Some of Idaho Power Company's facilities are deemed critical

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infrastructure, in that incapacity or destruction of the facilities could have a debilitating impact on security, national economic security, national public health or safety, or any combination of those matters. The possibility that infrastructure facilities, such as generation facilities and electric transmission facilities, would be direct targets of, or indirect casualties of, an act of terror or cyber attack (whether originating internally or externally) may affect Idaho Power Company's operations by limiting the ability to generate, purchase, or transmit power and by delaying the development and construction of new generating and transmission facilities and capital improvements to existing facilities.  These events, and governmental actions in response, could result in a material decrease in revenues and significant additional costs to repair and insure Idaho Power Company's assets, and could further adversely affect Idaho Power Company's operations by contributing to disruption of supplies and markets for natural gas or coal used to fuel gas-fired or coal-fired power plants.  Because generation and transmission are part of an interconnected system, Idaho Power Company faces the risk of possible loss of business due to a disruption caused by the impact of an event on the interconnected system. The events could also impair IDACORP, Inc.'s and Idaho Power Company's ability to raise capital by contributing to financial instability and lower economic activity. Further, the implementation of security guidelines and measures has resulted in and is expected to continue to result in increased compliance costs.

In the normal course of business, Idaho Power Company collects, processes, and retains sensitive and confidential customer and proprietary information, and operates systems that directly impact the availability of electric power and the transmission of electric power in the electric grid.  Idaho Power Company operates in a highly regulated industry that requires the continued operation of sophisticated information technology systems and network infrastructure.  Despite the security measures in place, Idaho Power Company's facilities and systems, and those of third-party service providers, could be vulnerable to security breaches, data leakage, or other similar events that could interrupt operations, resulting in a shutdown of service and exposing Idaho Power Company to liability.  Those breaches and events may result from acts of Idaho Power employees, contractors, or third parties. If Idaho Power Company's technology systems were to fail or be breached and Idaho Power Company were unable to recover the systems and/or data in a timely manner, Idaho Power Company would be unable to fulfill critical business functions, and confidential and proprietary business, employee, or customer information could be compromised, exposing Idaho Power to liability and causing business disruptions, which could have a material adverse effect on Idaho Power's operations and IDACORP, Inc.'s and Idaho Power Company's financial results. The implementation of security guidelines and measures and maintenance of insurance, to the extent available, addressing such activities could increase costs and impact financial results. In addition, these types of events could require significant management attention and resources, and could adversely affect IDACORP, Inc.'s and Idaho Power Company's reputation among customers and the public.

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 0.65 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.

ITEM 5.  OTHER INFORMATION

Mine Safety and Health Matters

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 is included in Exhibit 99.1 of this report, which is incorporated herein by reference.

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ITEM 6.  EXHIBITS

The agreements filed as exhibits to this Quarterly Report on Form 10-Q are filed to provide information regarding their terms and are not intended to provide any other factual or disclosure information about IDACORP, Inc., Idaho Power Company, or the other parties to the agreements.  The agreements contain representations and warranties by each of the parties to the applicable agreement.  These representations and warranties have been made solely for the benefit of the other parties to the applicable agreement and (a) should not in all instances be treated as categorical statements of fact, but rather as a way of allocating the risk to one of the parties to the agreement if those statements prove to be inaccurate; (b) have been qualified by disclosures that were made to the other party, which disclosures are not necessarily reflected in the agreement; (c) may apply standards of materiality in a way that is different from what may be viewed as material to investors; and (d) were made only as of the date of the applicable agreement or such other date or dates as may be specified in the agreement and are subject to more recent developments.

Exhibit No.	Description
* 10.70	Second Amended and Restated Credit Agreement, dated October 26, 2011, among IDACORP, Inc., various lenders, Wells Fargo Bank, National Association, as administrative agent, swingline lender, and LC issuer, JPMorgan Chase Bank, N.A., as syndication agent and LC issuer, KeyBank National Association and Union Bank, N.A., as documentation agents, and Wells Fargo Securities, LLC, J.P. Morgan Securities Inc., Keybanc Capital Markets, and Union Bank, N.A. as joint lead arrangers and joint book runners. File No. 1-14465, Form 8-K, filed on 10/28/11, as Exhibit 10.70
* 10.71	Second Amended and Restated Credit Agreement, dated October 26, 2011, among Idaho Power Company, various lenders, Wells Fargo Bank, National Association, as administrative agent, swingline lender, and LC issuer, JPMorgan Chase Bank, N.A., as syndication agent and LC issuer, KeyBank National Association and Union Bank, N.A., as documentation agents, and Wells Fargo Securities, LLC, J.P. Morgan Securities Inc., Keybanc Capital Markets, and Union Bank, N.A. as joint lead arrangers and joint book runners. File No. 1-3198, Form 8-K, filed on 10/28/11, as Exhibit 10.71
10.72	Amendment to the Idaho Power Company Employee Savings Plan, dated August 31, 2011
12.1	IDACORP, Inc. Computation of Ratio of Earnings to Fixed Charges and Supplemental Ratio of Earnings to Fixed Charges
12.2	Idaho Power Company Computation of Ratio of Earnings to Fixed Charges and Supplemental Ratio of Earnings to Fixed Charges
15.1	Letter Re:  Unaudited Interim Financial Information
31.1	IDACORP, Inc. Rule 13a-14(a) CEO certification
31.2	IDACORP, Inc. Rule 13a-14(a) CFO certification
31.3	Idaho Power Rule 13a-14(a) CEO certification
31.4	Idaho Power Rule 13a-14(a) CFO certification
32.1	IDACORP, Inc. Section 1350 CEO certification
32.2	IDACORP, Inc. Section 1350 CFO certification
32.3	Idaho Power Section 1350 CEO certification
32.4	Idaho Power Section 1350 CFO certification
99.1	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
* Previously filed and incorporated herein by reference
1   Includes data files for the following materials from the quarterly report on Form 10-Q of IDACORP, Inc. for the quarter ended September 30, 2011, formatted in Extensible Business Reporting Language (XBRL): (i) the Condensed Consolidated Statements of Income; (ii) the Condensed Consolidated Balance Sheets; (iii) the Condensed Consolidated Statements of Cash Flows; (iv) the Condensed Consolidated Statements of Comprehensive Income; (v) the Condensed Consolidated Statements of Equity; and (vi) the Notes to Condensed Consolidated Financial Statements.  Also includes data files for the following materials from the quarterly report on Form 10-Q of Idaho Power Company for the quarter ended September 30, 2011, 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.

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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:	November 3, 2011	By:	/s/ J. LaMont Keen
			J. LaMont Keen
			President and Chief Executive Officer
Date:	November 3, 2011	By:	/s/ Darrel T. Anderson
			Darrel T. Anderson
			Executive Vice President - Administrative
			Services and Chief Financial Officer
		IDAHO POWER COMPANY
		(Registrant)
Date:	November 3, 2011	By:	/s/ J. LaMont Keen
			J. LaMont Keen
			President and Chief Executive Officer
Date:	November 3, 2011	By:	/s/ Darrel T. Anderson
			Darrel T. Anderson
			Executive Vice President - Administrative
			Services and Chief Financial Officer

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EXHIBIT INDEX

Exhibit No.	Description
10.72	Amendment to the Idaho Power Company Employee Savings Plan, dated August 31, 2011
12.1	IDACORP, Inc. Computation of Ratio of Earnings to Fixed Charges and Supplemental Ratio of Earnings to Fixed Charges
12.2	Idaho Power Company Computation of Ratio of Earnings to Fixed Charges and Supplemental Ratio of Earnings to Fixed Charges
15.1	Letter Re:  Unaudited Interim Financial Information
31.1	IDACORP, Inc. Rule 13a-14(a) CEO certification
31.2	IDACORP, Inc. Rule 13a-14(a) CFO certification
31.3	Idaho Power Rule 13a-14(a) CEO certification
31.4	Idaho Power Rule 13a-14(a) CFO certification
32.1	IDACORP, Inc. Section 1350 CEO certification
32.2	IDACORP, Inc. Section 1350 CFO certification
32.3	Idaho Power Section 1350 CEO certification
32.4	Idaho Power Section 1350 CFO certification
99.1	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 September 30, 2011, formatted in Extensible Business Reporting Language (XBRL): (i) the Condensed Consolidated Statements of Income; (ii) the Condensed Consolidated Balance Sheets; (iii) the Condensed Consolidated Statements of Cash Flows; (iv) the Condensed Consolidated Statements of Comprehensive Income; (v) the Condensed Consolidated Statements of Equity; and (vi) the Notes to Condensed Consolidated Financial Statements.  Also includes data files for the following materials from the quarterly report on Form 10-Q of Idaho Power Company for the quarter ended September 30, 2011, 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.

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EX-10.72

Exhibit 10.72

AMENDMENT

TO THE

IDAHO POWER COMPANY EMPLOYEE SAVINGS PLAN

WHEREAS, Idaho Power Company (“Employer”) previously established and currently maintains a qualified retirement plan and trust which is known and designated as captioned above (“Plan”); and

WHEREAS, the Employer desires to amend the Plan to ensure compliance with the Internal Revenue Code (“Code”) Section 401(a)(9) final regulations, Code Section 401(k) and 401(m) final regulations, and Code Section 415 regulations;

NOW THEREFORE, the Employer hereby amends the Plan, effective as of the dates stated below, as follows:

FIRST: Except as otherwise provided, the article, section, and/or paragraph designations and/or numbering in this Amendment are solely for purposes of this Amendment and do not relate to any Plan article, section, paragraph or other numbering designations. The terms used below, whether or not defined, shall be interpreted in a manner consistent with those used in the Plan and/or as required by applicable law as the context dictates.

SECOND: The following provisions are effective January 1, 2003 and are intended to ensure compliance with the Code Section 401(a)(9) final regulations, and therefore supersede the provisions of the Plan to the extent those provisions are inconsistent with the provisions of this Amendment as follows:

Section 1.1. Time and Manner of Distribution

(a)Required Beginning Date. The Participant's entire benefits must be distributed, or begin to be distributed, to the Participant no later than the Participant's Required Beginning Date.

(b)Death of Participant Before Distributions Begin. If the Participant dies before distributions begin (see below), the Participant's entire benefits will be distributed, or begin to be distributed, no later than as follows:

(i)If the Participant's surviving Spouse is the Participant's sole Designated Beneficiary, distributions to the surviving Spouse will begin by December 31 of the calendar year immediately following the calendar year in which the Participant died, or by December 31 of the calendar year in which the Participant would have attained age 70½, if later.

(ii)If the Participant's surviving Spouse is not the Participant's sole Designated Beneficiary, the Participant's entire benefits will be distributed to the Designated Beneficiary by December 31 of the calendar year containing the fifth anniversary of the Participant's death.

(iii)If there is no Designated Beneficiary as of September 30 of the year following the year of the Participant's death, the Participant's entire benefits will be distributed by December 31 of the calendar year containing the fifth anniversary of the Participant's death.

(iv)If the Participant's surviving Spouse is the Participant's sole Designated Beneficiary and the surviving Spouse dies after the Participant but before distributions to the surviving Spouse begin, this subsection 1.1(b), other than subsection 1.1(b)(i), will apply as if the surviving Spouse were the Participant.

For purposes of this subsection 1.1(b) and Section 1.3, unless subsection 1.1(b)(iv) applies, distributions are considered to begin on the Participant's Required Beginning Date.  If subsection 1.1(b)(iv) applies, distributions are considered to begin on the date distributions are required to begin to the surviving Spouse under subsection 1.1(b)(i).  If distributions under an annuity purchased from an insurance company irrevocably commence to the Participant before the Participant's Required Beginning Date (or to the Participant's surviving Spouse before the date distributions are required to begin to the surviving Spouse under subsection 1.1(b)(i)), the date distributions are considered to begin is the date distributions actually commence.

(c)Forms of Distribution. Unless the Participant's benefits are distributed in the form of an annuity purchased from an insurance company or in a single sum on or before the Required Beginning Date, as of the first Distribution Calendar Year distributions will be made in accordance with Sections 1.2 and 1.3. If the Participant's benefits are distributed in the form of an annuity purchased from an insurance company, distributions thereunder will be made in accordance with the requirements of Code § 401(a)(9) and the Treasury Regulations.

Section 1.2. Required Minimum Distributions During Participant's Lifetime

(a)Amount of Required Minimum Distribution for Each Distribution Calendar Year. During the Participant's lifetime, the minimum amount that will be distributed for each Distribution Calendar Year is the lesser of:

(i)the quotient obtained by dividing the Participant's Account Balance by the distribution period in the Uniform Lifetime Table set forth in § 1.401(a)(9)-9 of the Treasury Regulations, using the Participant's age as of the Participant's birthday in the Distribution Calendar Year; or

(ii)if the Participant's sole Designated Beneficiary for the Distribution Calendar Year is the Participant's Spouse, the quotient obtained by dividing the Participant's Account Balance by the number in the Joint and Last Survivor Table set forth in § 1.401(a)(9)-9 of the Treasury Regulations, using the Participant's and Spouse's attained ages as of the Participant's and Spouse's birthdays in the Distribution Calendar Year.

(b)Lifetime Required Minimum Distributions Continue Through Year of Participant's Death. Required minimum distributions will be determined under this Section 1.2 beginning with the first Distribution Calendar Year and up to and including the Distribution Calendar Year that includes the Participant's date of death.

Section 1.3. Required Minimum Distributions After Participant's Death

(a)Death On or After Date Distributions Begin

(i)Participant Survived by Designated Beneficiary. If the Participant dies

on or after the date distributions begin and there is a Designated Beneficiary, the minimum amount that will be distributed for each Distribution Calendar Year after the year of the Participant's death is the quotient obtained by dividing the Participant's Account Balance by the longer of the remaining life expectancy of the Participant or the remaining life expectancy of the Participant's Designated Beneficiary, determined as follows:

(A)The Participant's remaining life expectancy is calculated using the age of the Participant in the year of death, reduced by one for each subsequent year.

(B)If the Participant's surviving Spouse is the Participant's sole Designated Beneficiary, the remaining life expectancy of the surviving Spouse is calculated for each Distribution Calendar Year after the year of the Participant's death using the surviving Spouse's age as of the Spouse's birthday in that year. For Distribution Calendar Years after the year of the surviving Spouse's death, the remaining life expectancy of the surviving Spouse is calculated using the age of the surviving Spouse as of the Spouse's birthday in the calendar year of the Spouse's death, reduced by one for each subsequent calendar year.

(C) If the Participant's surviving Spouse is not the Participant's sole Designated Beneficiary, the Designated Beneficiary's remaining life expectancy is calculated using the age of the Beneficiary in the year following the year of the Participant's death, reduced by one for each subsequent year.

(ii)No Designated Beneficiary.  If the Participant dies on or after the date distributions begin and there is no Designated Beneficiary as of September 30 of the year after the year of the Participant's death, the minimum amount that will be distributed for each Distribution Calendar Year after the year of the Participant's death is the quotient obtained by dividing the Participant's Account Balance by the Participant's remaining life expectancy calculated using the age of the Participant in the year of death, reduced by one for each subsequent year.

(b)Death Before Date Distributions Begin

(i) Participant Survived by Spousal Designated Beneficiary. If the Participant dies before the date distributions begin and the Designated Beneficiary is the Participant's surviving Spouse, the minimum amount that will be distributed for each Distribution Calendar Year after the year of the Participant's death is the quotient obtained by dividing the Participant's Account Balance by the remaining life expectancy of the Participant's Designated Beneficiary, determined as provided in subsection 1.3(a).

(ii) Death of Surviving Spouse Before Distributions to Surviving Spouse Are Re-quired to Begin. If the Participant dies before the date distributions begin, the Participant's surviving Spouse is the Participant's sole Designated Beneficiary, and the surviving Spouse dies before distributions are required to begin to the surviving Spouse under subsection 1.1(b)(i), this subsection 1.3(b) will apply as if the surviving Spouse were the Participant.

Section 1.4. Definitions

(a)“Designated Beneficiary” means the individual who is designated as the Beneficiary under the Plan and is the designated beneficiary under § 401(a)(9) of the Code and § 1.401(a)(9)-1, Q&A-4, of the Treasury Regulations.

(b)“Distribution Calendar Year” means a calendar year for which a minimum distribution is required. For distributions beginning before the Participant's death, the first Distribution Calendar Year is the calendar year immediately preceding the calendar year which contains the Participant's Required Beginning Date. For distributions beginning after the Participant's death, the first Distribution Calendar Year is the calendar year in which distributions are required to begin under subsection 1.1(b). The required minimum distribution for the Participant's first Distribution Calendar Year will be made on or before the Participant's Required Beginning Date. The required minimum distribution for other Distribution Calendar Years, including the required minimum distribution for the Distribution Calendar Year in which the Participant's Required Beginning Date occurs, will be made on or before December 31 of that Distribution Calendar Year.

(c)“Life expectancy” means the life expectancy as computed by use of the Single Life Table in § 1.401(a)(9)-9 of the Treasury Regulations.

(d)“Participant's Account Balance” means the Account Balance of all the Participant's Accounts as of the last Valuation Date in the calendar year immediately preceding the Distribution Calendar Year (“Valuation Calendar Year”) increased by the amount of any Contributions made and allocated or Forfeitures allocated to the Accounts as of dates in the Valuation Calendar Year after the Valuation Date and decreased by distributions made in the Valuation Calendar Year after the Valuation Date. The Account Balance for the Valuation Calendar Year includes any amounts rolled over or transferred to the Plan either in the Valuation Calendar Year or in the Distribution Calendar Year if distributed or transferred in the Valuation Calendar Year.

(e)Required Beginning Date

(i)Non-5% Owners. The Required Beginning Date of a Participant who is not a 5% owner is April 1st of the calendar year following the calendar year in which the later of retirement or attainment of age 70½ occurs.

(ii)5% Owners. The Required Beginning Date of a Participant who is a 5% owner is April 1st fol-lowing the calendar year in which the Participant attains age 70½.

(iii)Transitional Rules. The Plan hereby incorporates any transitional rules that apply to the definition of Required Beginning Date. In particular, in connection with the Small Business Job Protection Act of 1996, Participants who after the enactment of such Act were at least age 70½, were not 5% owners, and who were still employed by the Employer, were given the option to not receive the minimum distributions required under the law as the law existed prior to such Act (and instead such Participants will receive such minimum distributions that are required under the Plan as hereby restated under the Act (e.g., when the over-age-70½ Participant retires pursuant to subsection 1.4(e)(i))).

(iv)“5% Owner” means, for purposes of this Section, a Participant who is a 5% owner of the Employer as defined in Code § 416(i) (but determined without regard to whether the Plan is Top-Heavy) at any time during the Plan Year ending with or within the calendar year in which such owner attains age 70½ (or any other Plan Year as required by the Code or regulations thereunder).

Section 1.5. Construction. Except as otherwise provided, the requirements of this Section 1 shall apply to any distribution of a Participant's benefits and shall take precedence over any inconsistent provisions of this Plan. All distributions required under this Section 1 shall be determined and made in accordance with Treasury Regulations under § 401(a)(9), including the minimum distribution incidental benefit requirement of § 1.401(a)(9)-2 of said Regulations, and those Regulations govern to the extent a conflict exists.

Section 1.6. TEFRA § 242(b) Transitional Rule. In accordance with § 242(b) of The Tax Equity and Fiscal Responsibility Act of 1982 (“TEFRA”), the following transitional rule shall apply:

(a)Notwithstanding anything in this Section 1 to the contrary and subject to Code § 417, a distribution on behalf of any Participant, including a 5% Owner, may be made in accordance with the following requirements (regardless of when such distribution commences):

(i)the distribution is one which would not have disqualified this Plan and Trust under Code § 401(a)(9) as in effect prior to amendment by the Deficit Reduction Act of 1984;

(ii)the distribution is in accordance with a method of distribution designated by the Participant whose benefits in the Trust are being distributed or, if the Participant is deceased, by a Beneficiary of such Participant;

(iii)such designation was in writing, signed by the Participant or the Beneficiary , and made before January 1, 1984;

(iv)the Participant had accrued a benefit under the Plan as of December 31, 1983; and

(v)the method of distribution designated specifies the time at which distributions will commence, the period over which distributions will be made, and in the case of any distribution upon the Participant's death, the Beneficiariesof the Participant listed in order of priority.

(b)A distribution upon death will not be covered by the transitional rule contained in this subsection unless the designation contains the information described in subsection (a) with respect to the distributions to be made upon the death of the Participant.

(c)For any distribution which commences before January 1, 1984 but continues after December 31, 1983, the Participant or the Beneficiaryto whom such distribution is being made will be presumed to have designated the method of distribution under which the distribution is being made if the method of distribution was specified in writing and the distribution satisfies the requirements in subsections (a)(i) and (v).

(d)Any changes in the designation will be considered to be a revocation of the designation. However, the mere substitution or addition of another Beneficiary(one not named in the designation) under the designation will not be considered to be a revocation of the designation, so long as such substitution or addition does not alter the period over which distributions are to be made under the designation, directly or indirectly (for example, by altering the relevant measuring life).

(e)If a designation is revoked, any subsequent distribution must satisfy the requirements of Code § 401(a)(9) and the regulations thereunder. If a designation is revoked subsequent to the date when distributions are required to begin, the Trust must distribute by the end of the calendar year following the calendar year in which the revocation occurs the total amount not yet distributed which would have been required to have been distributed to satisfy Code § 401(a)(9) and the regulations thereunder, but for the TEFRA § 242(b)(2) election hereunder. Such distributions must also meet the minimum distribution incidental benefit requirements in Treasury Regulations § 1.401(a)(9)-2.

(f)If an amount is transferred or rolled over from one plan to another plan (including this Plan), the rules in Q&A J-2 and Q&A J-3 of Treasury Regulations § 1.401(a)(9)-1 shall apply.

THIRD: The following provisions are effective January 1, 2006 and are intended to ensure compliance with the Code Section 401(k) and 401(m) final regulations; they supplement the provisions of the Plan that was restated on December 31, 2009 (which, to the extent necessary, the provisions of such are made effective January 1, 2006 and are hereby incorporated by reference) and, to the extent those provisions are inconsistent with the provisions of this Amendment, these provisions supersede them, as follows:

Section 2.1. Elections. The Participant's Deferral Contributions election may be effective only with respect to Compensation paid after the completion of his or her election and, except for occasional bona fide administrative considerations, paid after the Participant's performance of services with respect to which such election is made.

Section 2.2. Dollar Limitation of Deferral Contributions. For purposes of Plan subsection 3.2.1(a), a Participant's Deferral Contributions shall mean, with respect to each calendar year, the sum of any Deferral Contributions made to this Plan, any other employer contributions made on behalf of such Participant pursuant to an election to defer under any qualified cash or deferred arrangement as described in Code § 401(k), any SIMPLE arrangement as described in Code § 408(p)(2)(A)(i), any simplified employee pension contribution as described in Code § 402(h)(1)(B), any employee contribution under a plan as described in Code § 501(c) (18), and any employer contributions made on behalf of a Participant for the purchase of an annuity contract as described in Code § 403(b) pursuant to a salary reduction agreement, and any “Roth” elective deferrals as described in Code § 402A.

Section 2.3. Excess Contributions. Section 10.4.5(a) of the Plan is revised to provide that “excess contributions” means, with respect to a Plan Year, the aggregate of the excess of the Deferral Contributions allocated to the Account of each Highly Compensated Employee over the maxi-mum Deferral Contributions which may be allocated to such Account without failing the Actual Deferral Percentage (“ADP”) Test. The amount of excess contributions shall be calculated by reducing the ADP of the Highly Compensated Employee with the highest ADP to the extent such reduction enables the Plan to satisfy the ADP Test or causes such Participant's

ADP to equal the ADP of the Highly Compensated Employee with the next highest ADP. This process shall be repeated until the Plan satisfies the ADP Test. After the Administrator has determined the excess contribution amount, the Trustee, as directed by the Administrator, will distribute to each Highly Compensated Employee his or her respective share of the excess contributions. The Administrator will determine the respective shares of excess contributions by starting with the Highly Compensated Employee(s) who has/have the greatest Deferral Contributions for the Plan Year and reducing such contributions but not to a point below the next highest amount of Deferral Contributions, and then if necessary, reducing the Deferral Contributions of the Highly Compensated Employee(s) with the next greatest amount of contributions, including the Deferral Contributions of the Highly Compensated Employee(s) whose Deferral Contributions the Administrator already has reduced, but to a point not below the next greatest amount of Deferral Contributions, and continuing in this manner until the Trustee has distributed all excess contributions.

Section 2.4. Earnings and Losses. Subsection 4.4.3 of the Plan is revised by adding the following new provisions:

To the extent the Plan requires gap period income, the Administrator may use any reasonable method for computing the Trust Fund earnings and losses allocable to excess contributions, provided that the method does not violate Code § 401(a)(4), is used consistently for all Participants and for all corrective distributions under the Plan for the applicable year, and is used by the Plan for allocating Trust Fund earnings and losses to Participant's Accounts. A Plan will not fail to use a reasonable method for computing the Trust Fund earnings and losses allocable to excess contributions merely because the Trust Fund earnings and losses allocable to excess contributions are determined on a date that is no more than 7 days before the distribution of excess contributions.

The Administrator may use the safe harbor method in this paragraph to determine Trust Fund Earnings and losses on excess contributions for the gap period. Under this method, Trust Fund earnings on excess contributions for the gap period are equal to 10% of the Trust Fund earnings and losses allocable to excess contributions for the applicable year that would be determined under subsection 4.4.3, multiplied by the number of calendar months that have elapsed since the end of the Plan Year. For purposes of calculating the number of calendar months that have so elapsed, a corrective distribution that is made on or before the fifteenth day of a month is treated as made on the last day of the preceding month and a distribution made after the fifteenth day of a month is treated as made on the last day of the month.

The Administrator may determine Trust Fund earnings and losses for the aggregate of the applicable year and the gap period by applying the method provided in subsection 4.4.3 to this aggregate period. This is accomplished by (A) substituting the Trust Fund earnings and losses for the applicable year and the gap period, for the Trust Fund earnings and losses for the applicable year, and (B) substituting the amounts taken into account under the ADP Test for the applicable year and the gap period, for the amounts taken into account under the ADP Test for the applicable year in determining the fraction that is multiplied by the Trust Fund earnings and losses.

“Applicable year” means the Plan Year to which the excess contributions relate.

Section 2.5. Plan Aggregation Rules. The first sentence of plan subsection 10.4.2 of the Plan is replaced with the following:

In the event that this Plan satisfies the requirements of Code §§ 401(k), 401(a)(4), or 410(b) only if aggregated with one or more other plans, or if one or more other plans satisfy the requirements of such sections of the Code only if aggregated with this Plan, then this subsection shall be applied by determining the ADP of employees as if all such plans were a single plan. Such plans may be aggregated in order to satisfy Code § 401(k) only if they have the same Plan Year. If a Highly Compensated Employee also participates in another cash or deferred arrangement described in Code § 401(k) which is maintained by the Employer, then this Plan and such other arrangement shall be aggregated and treated as one cash or deferred arrangement for purposes of calculating such Participant's ADP. If a Highly Compensated Employee participates in two or more such cash or deferred arrangements that have different plan years, all such cash or deferred arrangements in which the Participant participates that have plan years ending with or within the same calendar year shall be treated as a single arrangement for purposes of calculating such Participant's ADP. Aggregation under Plan subsection 10.4.2 shall not occur for arrangements that are required to be disaggregated under the Treasury regulations.

Section 2.6. Excess Aggregate Contributions. Subsection 10.5.4 of the Plan is revised to provide that “excess aggregate contributions” means, with respect to a Plan Year and for each Highly Compensated Employee, the aggregate of the excess of the After-Tax and Matching Contributions allocated to the Accounts of the Highly Compensated Employee over the maximum amount of such contributions which may be allocated to such Accounts without failing the Actual Contribution Percentage (“ACP”) Test. The amount of excess aggregate contributions shall be calculated by reducing the ACP of the Highly Compensated Employee with the highest ACP to the extent such reduction enables the Plan to satisfy the ACP Test or causes such Participant's ACP to equal the ACP of the Highly Compensated Employee with the next highest ACP. This process shall be repeated until the Plan satisfies the ACP Test. After the Administrator has determined the excess aggregate contribution amount, the Trustee, as directed by the Administrator, will distribute or forfeit to each Highly Compensated Employee his or her respective shares of the excess aggregate contributions. The Administrator will determine the respective share of excess aggregate contributions by starting with the Highly Compensated Employee(s) who has/have the greatest After-Tax Matching Contributions for the Plan Year and reducing such contributions (but not below the next highest level of After-Tax and Matching Contributions), and then if necessary, reducing such contributions of the Highly Compensated Employee(s) with the next highest level of contributions, including such contributions of the Highly Compensated Employee(s) whose After-Tax and Matching Contributions the Administrator already has reduced (but not below the next highest level of such contributions), and continuing in this manner until the Trustee has distributed all excess aggregate contributions. Any excess aggregate contributions distributed to a Participant shall be increased (or decreased) as determined and allocated in accordance with the provisions of subsection 4.4.3 of the Plan as modified by Section 2.4 of this amendment, except that such shall be applied by substituting “excess contributions” with “excess aggregate contributions” and by substituting amounts taken into account under the ACP Test for amounts taken into account under the ADP Test.

Section 2.7. Plan Aggregation Rules. The following is added to subsection 10.5.2 of the Plan:

In the event that this Plan satisfies the requirements of Code §§ 401(m), 401(a)(4) or 410(b) only if aggregated with one or more other plans, or if one or more other plans satisfy the requirements of such sections of the Code only if aggregated with this Plan, then this subsection shall be applied by determining the ACP of employees as if all such plans were a single plan. Such plans may be aggregated in order to satisfy § 401(m) of the Code only if they have the same Plan Year. If a Highly Compensated Employee also participates in any other plan or arrangement (under Code §§ 401(a) or 401(k)) which is maintained by the Employer and to which matching contributions, employee contributions or elective deferrals are made, then, for purposes of calculating that Participant's ACP, all the plans in which the Participant is eligible to participate shall be treated as one plan. If a Highly Compensated Employee participates in two or more such arrangements that have different plan years, all such arrangements ending with or within the same calendar year shall be treated as a single arrangement for purposes of calculating the Participant's ACP. Aggregation under Plan subsection 10.5.2 shall not occur for arrangements that are required to be disaggregated under the Treasury regulations.

Section 2.8. References to “Roth Contributions” in the provisions of the Plan that define Actual Contribution Percentage and the calculation of Actual Contribution Percentage, are hereby stricken as dictated by the context and as necessary to comply with the Code and Treasury Regulations.  Missing references to “Roth Contributions” in the provision of the Plan that define Actual Deferral Percentage and the calculation Actual Deferral Percentage, are hereby added as dictated by the context and as necessary to comply with the Code and Treasury Regulations.

Section 2.9. Subsections 4.2.6, 10.4.6, and 10.5.6 of the Plan are modified by adding the following: Section 0.11. Miscellaneous Rules

(a)Targeted Contribution Limit. Qualified Nonelective Contributions (as defined in Treas. Reg. § 1.401(k)-6) cannot be taken into account in determining the ADP or the ACP of a nonhighly compensated employee to the extent such contributions exceed the product of that nonhighly compensated employee's Code § 414(s) compensation and the greater of five percent (5%) or two (2) times the Plan's “representative contribution rate.” Any Qualified Nonelective Contribution taken into account under the ACP Test under Treas. Reg. § 1.401(m)-2(a)(6) (including the determination of the representative contribution rate for purposes of Treas. Reg. § 1.401(m)-2(a)(6)(v)(B)), is not permitted to be taken into account for purposes of the ADP Test (including the determination of the “representative contribution rate' under this Section), and in the same manner, any such contribution taken into account in the ADP Test under Treas. Reg. § 1.401(k)-2(a)(6) will not be taken into account under the ACP Test. For purposes of this subsection:

(i)The Plan's “representative contribution rate” is the lowest “applicable contribution rate” of any eligible nonhighly compensated employee among a group of eligible nonhighly compensated employees that consists of half of all eligible nonhighly compensated employees for the Plan Year (or, if greater, the lowest “applicable contribution rate” of any eligible nonhighly compensated employee who is in the group of all eligible nonhighly compensated employees for the Plan Year and who is employed by the Employer on the last day of the Plan Year).

(ii)The “applicable contribution rate” for an eligible nonhighly compensated employee in determining the ADP of a nonhighly compensated employee is the sum of the Qualified Matching Contributions (as defined in Treas. Reg. § 1.401(k)-6) taken into account in determining the ADP for the eligible nonhighly compensated employee for the Plan Year and the Qualified Nonelective Contributions made for the eligible nonhighly compensated employee for the Plan Year, divided by the eligible nonhighly compensated employee's Code § 414(s) compensation for the same period.

(iii)The “applicable contribution rate” for an eligible nonhighly compensated employee in determining the ACP of an nonhighly compensated employee is the sum of the Matching Contributions (as defined in Treas. Reg. § 1.401(m)-1(a)(2)) taken into account in determining the ACP for the eligible nonhighly compensated employee for the Plan Year and the Qualified Nonelective Contributions made for the eligible nonhighly compensated employee for the Plan Year, divided by the eligible nonhighly compensated employee's Code § 414(s) compensation for the same period.

Notwithstanding the above, Qualified Nonelective Contributions that are made in connection with an Employer's obligation to pay prevailing wages under the Davis-Bacon Act (46 Stat. 1494), Public Law 71-798, Service Contract Act of 1965 (79 Stat. 1965), Public Law 89-286, or similar legislation can be taken into account for a Plan Year for a nonhighly compensated employee to the extent such contributions do not exceed 10 percent (10%) of that nonhighly compensated employee's Code § 414(s) compensation.

Qualified Matching Contributions may only be used to calculate an ADP to the extent that such Qualified Matching Contributions are Matching Contributions that are not precluded from being taken into account under the ACP test for the Plan Year under the rules of Treas. Reg. § 1.401(m)-2(a)(5)(ii).

(b)Targeted Matching Contribution Limit. Matching Contributions with respect to Deferral Contributions for a Plan Year are not taken into account under the ACP Test for an nonhighly compensated employee to the extent it exceeds the greatest of: (i) five percent (5%) of the nonhighly compensated employee's Code § 414(s) compensation for the Plan Year; (ii) the nonhighly compensated employee's Deferral Contributions for the Plan Year; and (iii) the product of two (2) times the Plan's “representative matching rate” and the nonhighly compensated employee's Deferral Contributions for the Plan Year. For purposes of this subsection (b), the Plan's “representative matching rate” is the lowest “matching rate” for any eligible nonhighly compensated employee among a group of nonhighly compensated employees that consists of half of all eligible nonhighly compensated employees in the Plan for the Plan Year who make Deferral Contributions for the Plan Year (or, if greater, the lowest “matching rate” for all eligible nonhighly compensated employees in the Plan who are employed by the Employer on the last day of the Plan Year and who make Deferral Contributions for the Plan Year). For purposes of this subsection, the “matching rate” for an Employee generally is the Matching Contributions made for such Employee divided by the Employee's Deferral Contributions for the Plan Year. If the matching rate is not the same for all levels of Deferral Contributions for an Employee, then the Employee's “matching rate” is determined assuming that an Employee's Deferral Contributions are equal to six percent (6%) of Code § 414(s) compensation. If the Plan provides a match with respect to the sum of the

Employee's After-Tax Contributions and Deferral Contributions, then for purposes of this subsection, that sum is substituted for the amount of the Employee's Deferral Contributions in (i) through (iii) above in this subsection and in determining the “matching rate,” and Employees who make either After-Tax Contributions or Deferral Contributions are taken into account in determining the Plan's “representative matching rate.” Similarly, if the Plan provides a match with respect to the Employee's After-Tax Contributions, but not Deferral Contributions, then for purposes of this subsection, the Employee's After-Tax Contributions are substituted for the amount of the Employee's Deferral Contributions in (i) through (iii) above in this subsection and in determining the “matching rate,” and Employees who make After-Tax Contributions are taken into account in determining the Plan's “representative matching rate.”

(c)Limitation on QNECs and QMACs. Qualified Nonelective Contributions and Qualified Matching Contributions cannot be taken into account to determine an ADP to the extent such contributions are taken into account for purposes of satisfying any other ADP Test, any ACP Test, or the requirements of Treas. Reg. §§ 1.401(k)-3, 1.401(m)-3, or 1.401(k)-4. Thus, for example, Matching Contributions that are made pursuant to Treas. Reg. § 1.401(k)-3(c) cannot be taken into account under the ADP Test. Similarly, if the Plan switches from the current year testing method to the prior year testing method pursuant to Treas. Reg. § 1.401(k)-2(c), Qualified Nonelective Contributions that are taken into account under the current year testing method for a year may not be taken into account under the prior year testing method for the next year.

(d)Coordination with Other Plan Provisions.

(i)Excess contributions and excess aggregate contributions are annual additions notwithstanding their correction. Excess deferrals are annual additions unless they are distributed in accordance with the Plan. Deferral Contributions which are excess annual additions that are returned in accordance with the Plan are disregarded in calculating the Employee's Elective Deferrals and the numerators of the ADP and ACP.

(e)Additional Provisions. (i) Any contributions and any adjustments which are made to any contributions and the determination and treatment of the ADP and ACP shall satisfy such other requirements which may be prescribed by the Secretary of the Treasury. (ii) In conformance with the Code, the Employer may separately apply the ADP and ACP Tests to Employees who are and are not otherwise excludable employees, and also may disaggregate and separately test within the Plan, within the meaning of Code §§ 410(b) and 401(k) and the Treasury regulations thereunder. (iii) The provisions of Code § 401(k)(3)(F) may be used to exclude from consideration all non-highly compensated employees who have not satisfied the mini-mum age and service requirements of Code § 410(a)(1)(A). (iv) The ADP and ACP tests shall be per-formed separately for each commonly con-trolled entity.

(f)Recordkeeping. The Employer shall maintain records sufficient to demonstrate satisfaction of the ADP Test, the ACP Test and the amount of contributions used in such tests.

FOURTH: The following provisions are effective the first day of the Plan Year and Limitation Year beginning on or after July 1, 2007 and are intended to ensure compliance with the Code Section 415 final regulations, and therefore supersede the provisions of the Plan to the extent those provisions are inconsistent with the provisions of this Amendment as follows:

Section 3.1. Post-Termination Compensation

(a)Post-Termination. To determine compensation for purposes of Code Section 415 (and not for the purpose of determining contributions), compensation shall not include any amounts paid after an Employee's “severance from employment” (as defined by Treas. Reg. § 1.415(a)-1(f)(5)) with the Employer as provided below.

(i)Compensation shall include payments made after severance from employment by the later of two and one-half (2½) months after severance from employment or the end of the Plan Year that includes the date of severance from employment provided such payment would have been paid to the Employee if employment had continued and the payment is regular compensation for services performed during the Employee's regular working hours (such as overtime or shift differential), commissions, bonuses, or other similar payments.

(ii)Compensation shall include payments made after severance from employment by the later of two and one-half (2½) months after severance from employment or the end of the Plan Year that includes the date of severance from employment provided such payment is for unused accrued bona fide sick, vacation, or other leave, but only if the Employee would have been able to use the leave if employment had continued and if such amounts would have been included in compensation if they were paid prior to the Employee's severance from employment with the Employer.

(iii)Compensation shall not include payments made after severance from employment by the later of two and one-half (2½) months after severance from employment or the end of the Plan Year that includes the date of severance from employment provided such payment is received by an Employee pursuant to a nonqualified unfunded deferred compensation plan, but only if the payment would have been paid to the Employee at the same time if the Employee had continued in employment with the Employer and only to the extent that the payment is includable in the Employee's gross income and such amounts would have been included in compensation if they were paid prior to the Employee's severance from employment with the Employer.

(iv)Compensation shall include amounts paid after an Employee's severance from employment with the Employer if the Employee is not currently performing services for the Employer by reason of qualified military service (as defined by Code Section 414(u)(1)) to the extent the payments do not exceed the amounts the Employee would have received if the Employee had continued to perform services for the Employer rather than entering qualified military service.

(v)Compensation shall not include amounts paid after an Employee's severance from employment with the Employer notwithstanding that the Employee is permanently and totally disabled (as defined by Code Section 22(e)(3)).

(b)Notwithstanding any provision of the Plan to the contrary, compensation that may be deferred as Section 401(k) Contributions shall not be limited to the compensation limit of Code § 401(a)(17).

(c)Notwithstanding any provision of the Plan to the contrary, Code § 415 Compensation shall be used to determine whether an Employee is a highly compensated employee.

IN ALL OTHER RESPECTS, the Plan is hereby ratified and approved.

This Amendment is adopted this 31^st day of August, 2011.

IDAHO POWER COMPANY,

FIDUCIARY COMMITTEE

/s/ Darrel T. Anderson

Darrel T. Anderson

/s/ Luci K. McDonald

Luci K. McDonald

/s/ Daniel B. Minor

Daniel B. Minor

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)

	Nine months ended September 30,
			Twelve Months Ended
			December 31,
	2011		2010		2009		2008		2007		2006
RATIO OF EARNINGS TO FIXED CHARGES
Earnings, as defined:
Income from continuing operations before income taxes	$	113,741	$	141,729	$	146,737	$	117,614	$	96,003	$	115,452
Adjust for distributed income of equity investees	6,032		3,522		13,724		5,176		6,064		(9,347		)
Fixed charges, as below	65,281		86,806		79,461		81,172		72,879		65,745
Total earnings, as defined	$	185,054	$	232,057	$	239,922	$	203,962	$	174,946	$	171,850
Fixed charges, as defined:
Interest charges1	$	63,989	$	85,840	$	78,457	$	80,282	$	71,946	$	64,720
Rental interest factor	1,292		966		1,004		890		933		1,025
Total fixed charges, as defined	$	65,281	$	86,806	$	79,461	$	81,172	$	72,879	$	65,745
Ratio of earnings to fixed charges	2.83x		2.67x		3.02x		2.51x		2.40x		2.61x
SUPPLEMENTAL RATIO OF EARNINGS TO FIXED CHARGES
Earnings, as defined:
Income from continuing operations before income taxes	$	113,741	$	141,729	$	146,737	$	117,614	$	96,003	$	115,452
Adjust for distributed income of equity investees	6,032		3,522		13,724		5,176		6,064		(9,347		)
Supplemental fixed charges, as below	65,886		87,870		80,946		82,962		74,631		67,521
Total earnings, as defined	$	185,659	$	233,121	$	241,407	$	205,752	$	176,698	$	173,626
Supplemental fixed charges:
Interest charges1	$	63,989	$	85,840	$	78,457	$	80,282	$	71,946	$	64,720
Rental interest factor	1,292		966		1,004		890		933		1,025
Supplemental increment to fixed charges2	605		1,064		1,485		1,790		1,752		1,776
Total supplemental fixed charges	$	65,886	$	87,870	$	80,946	$	82,962	$	74,631	$	67,521
Supplemental ratio of earnings to fixed charges	2.82x		2.65x		2.98x		2.48x		2.37x		2.57x
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)

	Nine months ended September 30,
				Twelve Months Ended
				December 31,
	2011			2010			2009		2008			2007			2006
RATIO OF EARNINGS TO FIXED CHARGES
Earnings, as defined:
Income from continuing operations before income taxes	$	118,423		$	151,347		$	158,080	$	131,715		$	111,965		$	137,890
Adjust for distributed income of equity investees	(97		)	(6,526		)	2,464		(6,772		)	(5,553		)	(9,347		)
Fixed charges, as below	64,903			85,579			78,543		77,568			68,272			60,687
Total earnings, as defined	$	183,229		$	230,400		$	239,087	$	202,511		$	174,684		$	189,230
Fixed charges, as defined:
Interest charges1	$	63,639		$	84,651		$	77,580	$	76,711		$	67,386		$	59,955
Rental interest factor	1,264			928			963		857			886			732
Total fixed charges, as defined	$	64,903		$	85,579		$	78,543	$	77,568		$	68,272		$	60,687
Ratio of earnings to fixed charges	2.82x			2.69x			3.04x		2.61x			2.56x			3.12x
SUPPLEMENTAL RATIO OF EARNINGS TO FIXED CHARGES
Earnings, as defined:
Income from continuing operations before income taxes	$	118,423		$	151,347		$	158,080	$	131,715		$	111,965		$	137,890
Adjust for distributed income of equity investees	(97		)	(6,526		)	2,464		(6,772		)	(5,553		)	(9,347		)
Supplemental fixed charges, as below	65,508			86,643			80,028		79,358			70,024			62,463
Total earnings, as defined	$	183,834		$	231,464		$	240,572	$	204,301		$	176,436		$	191,006
Supplemental fixed charges:
Interest charges1	$	63,639		$	84,651		$	77,580	$	76,711		$	67,386		$	59,955
Rental interest factor	1,264			928			963		857			886			732
Supplemental increment to fixed charges2	605			1,064			1,485		1,790			1,752			1,776
Total supplemental fixed charges	$	65,508		$	86,643		$	80,028	$	79,358		$	70,024		$	62,463
Supplemental ratio of earnings to fixed charges	2.81x			2.67x			3.01x		2.57x			2.52x			3.06x
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

November 3, 2011

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 periods ended September 30, 2011 and 2010, as indicated in our reports dated November 3, 2011; 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 September 30, 2011, are incorporated by reference in Registration Statement Nos. 333-155498 and 333-155645 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:	November 3, 2011	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:	November 3, 2011	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:	November 3, 2011	By:	/s/ J. LaMont Keen
			J. LaMont Keen
			President and 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:	November 3, 2011	By:	/s/ Darrel T. Anderson
			Darrel T. Anderson
			Executive Vice President - Administrative Services
			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 September 30, 2011 (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

November 3, 2011

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 September 30, 2011 (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

November 3, 2011

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 September 30, 2011 (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

November 3, 2011

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 September 30, 2011 (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

November 3, 2011

EX-99.1

Exhibit 99.1

Mine Safety and Health Matters

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

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

The table below summarizes citations, notices, and orders issued and penalties assessed by MSHA for the Mine under the indicated provisions of the Mine Safety Act, and other information, for the three and nine month periods ended September 30, 2011.

			Three-month period ended September 30, 2011				Nine-month period ended September 30, 2011
			(surface)		(underground)		(surface)		(underground)
Mine Safety Act
	Section 104(a) Significant & Substantial Citations (1)		-		6		6		32
	Section 104(b) Orders (2)		-		-		-		1
	Section 104(d) Citations & Orders (3)		-		-		-		-
	Section 110(b)(2) Flagrant Violations (4)		-		-		-		-
	Section 107(a) Imminent Danger Orders (5)		-		-		-		-
	Section 104(e) Notice (6)		-		-		-		-
Total Value of Proposed MSHA Assessments (in thousands)		$	1	$	54	$	10	$	120
Legal Actions (7)			6		18		6		18
Number of Fatalities			-		-		-		-
_______________
(1)  For alleged violations of a mandatory mining safety standard or regulation where such violation contributed to a discrete safety hazard and there exists a reasonable likelihood that the hazard will result in an injury or illness and there is a reasonable likelihood that such injury will be of a reasonably serious nature.
(2)  For alleged failure to totally abate the subject matter of a Mine Safety Act Section 104(a) citation within the period specified in the citation or as subsequently extended.
(3)  For an alleged unwarrantable failure (i.e., aggravated conduct constituting more than ordinary negligence) to comply with a mining safety standard or regulation.
(4)  The term “flagrant” with respect to a violation means a reckless or repeated failure to make reasonable efforts to eliminate a known violation of mandatory health or safety standard that substantially and proximately caused, or reasonably could have been expected to cause, death or serious bodily injury.
(5)  The existence of any condition or practice in a coal or other mine that could reasonably be expected to cause death or serious physical harm if normal mining operations were permitted to proceed in the area before such condition or practice is eliminated.
(6)   For a pattern, or the potential to have a pattern, of violations of mandatory health or safety standards that are of such nature as could have significantly and substantially contributed to the cause and effect of coal or other mine health or safety hazards.
(7)   Represents the total number of legal actions or proceedings pending before the Federal Mine Safety and Health Review Commission, which is not exclusive to citations, notices, orders, and penalties assessed by MSHA, as of September 30, 2011.

XML

Condensed Consolidated Balance Sheets Statement (USD $) In Thousands	Sep. 30, 2011	Dec. 31, 2010
Current Assets:
Cash and cash equivalents	$ 31,314	$ 228,677
Receivables:
Customer	75,540	62,114
Other	10,693	10,157
Income taxes receivable	0	12,130
Accrued unbilled revenues	49,368	47,964
Materials and supplies (at average cost)	46,558	45,601
Fuel stock (at average cost)	49,742	27,547
Prepayments	11,245	11,063
Deferred income taxes	3,850	10,715
Current regulatory assets	26,438	6,216
Other	4,507	1,854
Total current assets	309,255	464,038
Investments	192,343	202,944
Property, Plant and Equipment:
Utility plant in service	4,451,427	4,332,054
Accumulated provision for depreciation	(1,669,123)	(1,614,013)
Utility plant in service - net	2,782,304	2,718,041
Construction work in progress	547,777	416,950
Utility plant held for future use	6,974	7,076
Other property, net of accumulated depreciation	18,991	19,315
Property, plant and equipment - net	3,356,046	3,161,382
Other Assets:
American Falls and Milner water rights	20,275	22,120
Company-owned life insurance	24,084	26,672
Regulatory assets	880,412	753,172
Long-term receivables	5,041	3,965
Other	39,479	41,762
Total other assets	969,291	847,691
Total	4,826,935	4,676,055
Current Liabilities:
Current maturities of long-term debt	1,667	122,572
Notes payable	51,500	66,900
Accounts payable	90,088	103,100
Income taxes accrued	8,785	0
Interest accrued	23,388	23,937
Uncertain tax positions	0	74,436
Current regulatory liabilities	16,067	8,011
Other	62,966	50,103
Total current liabilities	254,461	449,059
Other Liabilities:
Deferred income taxes	750,001	566,473
Regulatory liabilities	332,675	298,094
Other	341,442	338,158
Total other liabilities	1,424,118	1,202,725
Long-Term Debt	1,487,468	1,488,287
Commitments and Contingencies
Equity:
Common stock	820,271	807,842
Retained earnings	846,873	733,879
Accumulated other comprehensive loss	(10,268)	(9,568)
Treasury stock	(29)	(40)
Total IDACORP, Inc. shareholders’ equity	1,656,847	1,532,113
Noncontrolling interests	4,041	3,871
Total equity	1,660,888	1,535,984
Total	4,826,935	4,676,055
Idaho Power Company
Current Assets:
Cash and cash equivalents	24,993	224,233
Receivables:
Customer	75,540	62,114
Other	10,577	8,835
Income taxes receivable	0	21,063
Accrued unbilled revenues	49,368	47,964
Materials and supplies (at average cost)	46,558	45,601
Fuel stock (at average cost)	49,742	27,547
Prepayments	11,132	10,910
Deferred income taxes	3,837	7,334
Current regulatory assets	26,438	6,216
Other	4,507	1,238
Total current assets	302,692	463,055
Property, Plant and Equipment:
Utility plant in service	4,451,427	4,332,054
Accumulated provision for depreciation	(1,669,123)	(1,614,013)
Utility plant in service - net	2,782,304	2,718,041
Construction work in progress	547,777	416,950
Utility plant held for future use	6,974	7,076
Property, plant and equipment - net	3,337,055	3,142,067
Investments and Other Property	116,124	120,641
Other Assets:
American Falls and Milner water rights	20,275	22,120
Company-owned life insurance	24,084	26,672
Regulatory assets	880,412	753,172
Other	38,531	40,666
Total other assets	963,302	842,630
Total	4,719,173	4,568,393
Current Liabilities:
Current maturities of long-term debt	1,064	121,064
Accounts payable	89,615	102,474
Accounts payable to related parties	1,812	1,110
Income taxes accrued	3,986	0
Interest accrued	23,388	23,930
Uncertain tax positions	0	74,436
Current regulatory liabilities	16,067	8,011
Other	62,316	48,733
Total current liabilities	198,248	379,758
Other Liabilities:
Deferred income taxes	846,324	661,165
Regulatory liabilities	332,675	298,094
Other	339,277	335,860
Total other liabilities	1,518,276	1,295,119
Long-Term Debt	1,487,468	1,488,287
Commitments and Contingencies
Equity:
Common stock	97,877	97,877
Premium on capital stock	688,758	688,758
Capital stock expense	(2,097)	(2,097)
Retained earnings	740,911	630,259
Accumulated other comprehensive loss	(10,268)	(9,568)
Total equity	1,515,181	1,405,229
Total capitalization	3,002,649	2,893,516
Total	$ 4,719,173	$ 4,568,393

XML

Condensed Consolidated Balance Sheets (Parenthetical) (USD $) In Thousands, except Share data	Sep. 30, 2011	Dec. 31, 2010
Current Assets:
Allowance for doubtful customer receivables	$ 1,378	$ 1,499
Allowance for doubtful other receivables	205	1,471
Allowance for doubtful long-term receivables	3,304	1,861
Equity:
Common stock, par value	$ 0	$ 0
Common stock, shares authorized	120,000,000	120,000,000
Common stock, shares issued	49,774,042	49,419,452
Treasury stock, shares	11,675	14,302
Idaho Power Company
Current Assets:
Allowance for doubtful customer receivables	1,378	1,499
Allowance for doubtful other receivables	$ 205	$ 142
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

XML

FAIR VALUE MEASUREMENTS:

3 Months Ended

Sep. 30, 2011

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.

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.

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 September 30, 2011 and December 31, 2010 (in thousands of dollars).  IDACORP’s and Idaho Power’s assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy.  There were no transfers between levels for the periods presented. 

	Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)		Total
September 30, 2011
IDACORP
Assets:
Derivatives	$	3,826	$	80	$	—	$	3,906
Money market funds	100		—		—		100
Trading securities:  Equity securities	3,239		—		—		3,239
Available-for-sale securities:  Equity securities	21,346		—		—		21,346
Liabilities:
Derivatives	$	130	$	977	$	—	$	1,107
Idaho Power
Assets:
Derivatives	$	3,826	$	80	$	—	$	3,906
Money market funds	100		—		—		100
Trading securities:  Equity securities	3,239		—		—		3,239
Available-for-sale securities:  Equity securities	21,346		—		—		21,346
Liabilities:
Derivatives	$	130	$	977	$	—	$	1,107
December 31, 2010
IDACORP
Assets:
Derivatives	$	573	$	—	$	—	$	573
Money market funds	151,975		—		—		151,975
Trading securities:  Equity securities	5,361		—		—		5,361
Available-for-sale securities:  Equity securities	24,561		—		—		24,561
Liabilities:
Derivatives	$	—	$	508	$	—	$	508
Idaho Power
Assets:
Derivatives	$	573	$	—	$	—	$	573
Money market funds	151,173		—		—		151,173
Trading securities:  Equity securities	4,746		—		—		4,746
Available-for-sale securities:  Equity securities	24,561		—		—		24,561
Liabilities:
Derivatives	$	—	$	508	$	—	$	508

The table below presents the carrying value and estimated fair value of financial instruments that are not reported at fair value, as of September 30, 2011 and December 31, 2010, using available market information and appropriate valuation methodologies.  The use of different market assumptions and/or estimation methodologies may have a material effect on the estimated fair value amounts.  Cash and cash equivalents, deposits, customer and other receivables, notes payable, accounts payable, interest accrued, and taxes accrued are reported at their carrying value as these are a reasonable estimate of their fair value.  The estimated fair values for notes receivable and long-term debt are based upon quoted market prices of the same or similar issues or discounted cash flow analysis as appropriate. 

	September 30, 2011				December 31, 2010
	Carrying		Estimated		Carrying		Estimated
	Amount		Fair Value		Amount		Fair Value
	(thousands of dollars)
IDACORP
Assets:
Notes receivable	$	2,946	$	2,946	$	2,946	$	2,946
Liabilities:
Long-term debt	1,492,330		1,729,623		1,614,299		1,622,924
Idaho Power
Liabilities:
Long-term debt	$	1,491,727	$	1,729,022	$	1,612,790	$	1,621,425

XML

Document And Entity Information	3 Months Ended
	Sep. 30, 2011	Oct. 28, 2011
Entity Information
Document Type	10-Q
Amendment Flag	false
Document Period End Date	Sep. 30, 2011
Document Fiscal Year Focus	2011
Document Fiscal Period Focus	Q3
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		49,768,118
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

XML

INCOME TAXES: Level 3 (Tables)

3 Months Ended

Sep. 30, 2011

Income Taxes [Abstract]

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

An analysis of income tax expense (benefit) for the three and nine months endedSeptember 30 is as follows (in thousands of dollars):

	IDACORP						Idaho Power
	2011			2010			2011			2010
Three months ended September 30,
Income tax at statutory rates (federal and state)	$	24,123		$	30,204		$	24,671		$	31,036
Additional ADITC amortization reversal	6,750			—			6,750			—
Accounting method change	—			(7,374		)	—			(7,374		)
Examination settlement - uniform capitalization	(56,898		)	—			(56,898		)	—
Other	(19,347		)	(12,715		)	(16,299		)	(8,936		)
Income tax (benefit) expense	$	(45,372	)	$	10,115		$	(41,776	)	$	14,726
Effective tax rate	(73.5		)%	13.1		%	(66.2		)%	18.6		%
Nine months ended September 30,
Income tax at statutory rates (federal and state)	$	44,407		$	45,824		$	46,303		$	48,451
Accounting method change	—			(32,561		)	—			(32,561		)
Examination settlement - capitalized repairs	(3,428		)	—			(3,428		)	—
Examination settlement - uniform capitalization	(56,898		)	—			(56,898		)	—
Other	(28,218		)	(18,473		)	(22,974		)	(13,674		)
Income tax (benefit) expense	$	(44,137	)	$	(5,210	)	$	(36,997	)	$	2,216
Effective tax rate	(38.9		)%	(4.4		)%	(31.2		)%	1.8		%

XML

SEGMENT INFORMATION: Level 4 (Details) (USD $) In Thousands, unless otherwise specified	3 Months Ended		9 Months Ended
	Sep. 30, 2011	Sep. 30, 2010	Sep. 30, 2011	Sep. 30, 2010	Dec. 31, 2010
Segment Reporting Information
Revenues	$ 308,045	$ 308,468	$ 793,031	$ 801,719
Revenues	309,630	309,357	796,107	804,073
Income (loss) attributable to IDACORP, Inc.	107,414	67,125	157,878	122,219
Income (loss) attributable to IDACORP, Inc.	107,067	67,135	157,708	122,407
Total assets	4,826,935		4,826,935		4,676,055
Idaho Power Company [Member] | Idaho Power Company
Segment Reporting Information
Revenues	308,045	308,468	793,031	801,719
Income (loss) attributable to IDACORP, Inc.	104,872	64,650	155,420	121,700
Total assets	4,719,173		4,719,173
All Other
Segment Reporting Information
Revenues	1,585	889	3,076	2,354
Income (loss) attributable to IDACORP, Inc.	2,195	2,485	2,288	707
Total assets	124,273		124,273
Eliminations
Segment Reporting Information
Revenues	0	0	0	0
Income (loss) attributable to IDACORP, Inc.	0	0	0	0
Total assets	(16,511)		(16,511)
Idaho Power Company [Member]
Segment Reporting Information
Revenues	308,045	308,468	793,031	801,719
Income (loss) attributable to IDACORP, Inc.	104,872	64,650	155,420	121,700
Total assets	$ 4,719,173		$ 4,719,173		$ 4,568,393
Bridger Coal Company
Segment Reporting Information
IERCo's ownership percentage in Bridger Coal Company	33.00%

XML

INCOME TAXES:

3 Months Ended

Sep. 30, 2011

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

An analysis of income tax expense (benefit) for the three and nine months endedSeptember 30 is as follows (in thousands of dollars):

	IDACORP						Idaho Power
	2011			2010			2011			2010
Three months ended September 30,
Income tax at statutory rates (federal and state)	$	24,123		$	30,204		$	24,671		$	31,036
Additional ADITC amortization reversal	6,750			—			6,750			—
Accounting method change	—			(7,374		)	—			(7,374		)
Examination settlement - uniform capitalization	(56,898		)	—			(56,898		)	—
Other	(19,347		)	(12,715		)	(16,299		)	(8,936		)
Income tax (benefit) expense	$	(45,372	)	$	10,115		$	(41,776	)	$	14,726
Effective tax rate	(73.5		)%	13.1		%	(66.2		)%	18.6		%
Nine months ended September 30,
Income tax at statutory rates (federal and state)	$	44,407		$	45,824		$	46,303		$	48,451
Accounting method change	—			(32,561		)	—			(32,561		)
Examination settlement - capitalized repairs	(3,428		)	—			(3,428		)	—
Examination settlement - uniform capitalization	(56,898		)	—			(56,898		)	—
Other	(28,218		)	(18,473		)	(22,974		)	(13,674		)
Income tax (benefit) expense	$	(44,137	)	$	(5,210	)	$	(36,997	)	$	2,216
Effective tax rate	(38.9		)%	(4.4		)%	(31.2		)%	1.8		%

The changes in year-to-date 2011 income tax expense as compared to the same period in 2010 were primarily due to an income tax benefit in 2010 related to Idaho Power's tax accounting method change for capitalized repair expenditures, an income tax benefit in 2011 related to the examination settlement of Idaho Power's uniform capitalization method, increased 2011 flow-through tax adjustments related to both methods, and lower 2011 pre-tax earnings. Other net regulatory flow-through tax adjustments at Idaho Power and tax credits at IFS for the nine months endedSeptember 30, 2011 were comparable to the same period in 2010.

Idaho Power's January 2010 settlement agreement with the Idaho Public Utilities Commission (IPUC) and other parties 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 2009 to 2011.  Idaho Power has up to $25 million of additional ADITC amortization available for use in 2011 under the settlement agreement. In the third quarter of 2011, Idaho Power reversed $6.8 million of additional ADITC amortization previously recorded in the first six months of 2011, based on itsestimate that 2011 Idaho jurisdictional return on year-end equity will exceed 9.5 percent.

Status of Audit Proceedings and Tax Method Changes

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

In April 2011, IDACORP and the IRS reached an agreement on Idaho Power's tax accounting method change for capitalized repairs. Accordingly, the IRS finalized the 2009 examination and submitted its report on the 2009 tax year to the Joint Committee for review. Idaho Power considers the capitalized repairs method effectively settled and believes that no material income tax uncertainties remain for the method. As such, Idaho Power recognized $3.4 million of its previously unrecognized tax benefits for this method in the second quarter of 2011.

In September 2011, the IRS notified IDACORP that the Joint Committee had completed its review and approved the uniform capitalization method agreement. Idaho Power considers the uniform capitalization method effectively settled and believes that no material income tax uncertainties remain for the method. Accordingly, Idaho Power recognized $56.9 million of its previously unrecognized tax benefits for tax years 2009 and prior in the third quarter of 2011. Idaho Power also increased its uniform capitalization tax deduction estimate in its current year tax provision, which resulted in an additional $2.0 million income tax benefit for the nine months ended September 30, 2011.

Completion of the Joint Committee review allowed the IRS to finalize its 2009 examination, process the income tax changes, and close the case prior to September 30, 2011. In the fourth quarter of 2011, IDACORP and Idaho Power will pay previously accrued income tax liabilities of $3.9 million and $8.1 million, respectively, related to the capitalized repairs examination agreement. The difference in liabilities is due to IDACORP's utilization of deferred federal general business tax credits and Idaho investment tax credits. There are no 2011 cash impacts related to the uniform capitalization method settlement as income tax refunds for the method change were received in 2010. In early 2011, IDACORP requested and received the return of $13 million of previously made estimated tax payments for the 2010 tax year.

XML

NOTES PAYABLE: Level 3 (Tables)

3 Months Ended

Sep. 30, 2011

Shedule of short term debt [Abstract]

Schedule of Short-term Debt

 Balances and interest rates of IDACORP’s short-term borrowings were as follows at September 30, 2011 and December 31, 2010 (in thousands of dollars):

	September 30, 2011			December 31, 2010
Commercial paper outstanding	$	51,500		$	66,900
Weighted-average annual interest rate	0.42		%	0.43		%

XML

BENEFIT PLANS: Level 4 (Details) (USD $)	3 Months Ended		9 Months Ended
	Sep. 30, 2011	Sep. 30, 2010	Sep. 30, 2011	Sep. 30, 2010
Pension Plan
Defined Benefit Plan Disclosure
Service cost	$ 5,120,000	$ 4,417,000	$ 15,359,000	$ 13,253,000
Interest cost	7,581,000	7,279,000	22,742,000	21,839,000
Expected return on plan assets	(7,968,000)	(7,270,000)	(23,903,000)	(19,847,000)
Amortization of transition obligation	0	0	0	0
Amortization of prior service cost	130,000	163,000	389,000	488,000
Amortization of net loss	2,168,000	1,918,000	6,505,000	5,756,000
Net periodic benefit cost	7,031,000	6,507,000	21,092,000	21,489,000
Costs not recognized due to the effects of regulation	(2,371,000)	(4,624,000)	(11,981,000)	(18,650,000)
Net periodic benefit cost recognized for financial reporting	4,660,000	1,883,000	9,111,000	2,839,000
Amount by which the Idaho-jurisdiction pension recovery was increased in the current year	17,100,000		17,100,000
Contributions made to the defined benefit pension plan	18,500,000
Defined Benefit Plan, Minimum Employer Contributions Required in Current Fiscal Year			6,000,000
Senior Management Security Plan
Defined Benefit Plan Disclosure
Service cost	487,000	385,000	1,463,000	1,156,000
Interest cost	773,000	751,000	2,319,000	2,253,000
Expected return on plan assets	0	0	0	0
Amortization of transition obligation	0	0	0	0
Amortization of prior service cost	61,000	59,000	183,000	175,000
Amortization of net loss	323,000	232,000	969,000	698,000
Net periodic benefit cost	1,644,000	1,427,000	4,934,000	4,282,000
Costs not recognized due to the effects of regulation	0	0	0	0
Net periodic benefit cost recognized for financial reporting	1,644,000	1,427,000	4,934,000	4,282,000
Postretirement Benefits
Defined Benefit Plan Disclosure
Service cost	330,000	340,000	992,000	1,020,000
Interest cost	859,000	898,000	2,576,000	2,693,000
Expected return on plan assets	(660,000)	(641,000)	(1,981,000)	(1,921,000)
Amortization of transition obligation	510,000	510,000	1,530,000	1,530,000
Amortization of prior service cost	(105,000)	(133,000)	(316,000)	(401,000)
Amortization of net loss	144,000	143,000	433,000	430,000
Net periodic benefit cost	1,078,000	1,117,000	3,234,000	3,351,000
Costs not recognized due to the effects of regulation	0	0	0	0
Net periodic benefit cost recognized for financial reporting	$ 1,078,000	$ 1,117,000	$ 3,234,000	$ 3,351,000

XML

NOTES PAYABLE: Level 4 (Details) (USD $)	Oct. 26, 2011	Sep. 30, 2011	Dec. 31, 2010
IDACORP
Short-term borrowings:
Commercial paper outstanding		$ 51,500,000	$ 66,900,000
Weighted-average annual interest rate		0.42%	0.43%
Credit facility:
Credit facility	125,000,000	100,000,000
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 [Member]
Credit facility:
Interest Rate Addition to Base Rate	0.50%
IDACORP | LIBOR Rate [Member]
Credit facility:
Interest Rate Addition to Base Rate	1.00%
Idaho Power Company
Short-term borrowings:
Commercial paper outstanding		0	0
Credit facility:
Credit facility	300,000,000	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
Idaho Power Company | Federal Funds Rate [Member]
Credit facility:
Interest Rate Addition to Base Rate	0.50%
Idaho Power Company | LIBOR Rate [Member]
Credit facility:
Interest Rate Addition to Base Rate	1.00%

XML

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

3 Months Ended

Sep. 30, 2011

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 is regulated by the Federal Energy Regulatory Commission (FERC) and the state regulatory commissions of Idaho and Oregon.  Idaho Power is the parent of Idaho Energy Resources Co. (IERCo), a joint venturer in Bridger Coal Company (BCC), which mines and supplies coal to the Jim Bridger generating plant owned in part by Idaho Power.

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

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 $16 million of intercompany long-term debt, which is eliminated in consolidation.  EEC has borrowed amounts from Ida-West to fund a portion of its required capital contributions to Marysville.  The loans are payable from EEC’s share of distributions and are secured by the stock of EEC and EEC’s interest in Marysville.  Ida-West is the primary beneficiary because the ownership of the intercompany note and the EEC note result in it controlling the entity.  Creditors of Marysville have no recourse to the general credit of IDACORP and there are no other arrangements that could require IDACORP to provide financial support to Marysville or expose IDACORP to losses.

Through IERCo, Idaho Power holds a variable interest in BCC, a VIE for which it is not the primary beneficiary.  IERCo is not the primary beneficiary because the power to direct the activities that most significantly impact the economic performance of BCC is shared with the joint venture partner.  The carrying value of BCC is $91 million at September 30, 2011, 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 – “Commitments.”

Through IFS, IDACORP also holds variable interests in VIEs for which it is not the primary beneficiary.  These VIEs are affordable housing developments and other real estate investments in which IFS holds limited partnership interests ranging from 5 to 99 percent.  As a limited partner, IFS does not control these entities and they are not consolidated.  These investments were acquired between 1996 and 2010.  IFS’s maximum exposure to loss in these developments is limited to its net carrying value, which was $66 million at September 30, 2011.

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 positions as of September 30, 2011, consolidated results of operations for the three and nine months endedSeptember 30, 2011 and 2010, and consolidated cash flows for the nine months endedSeptember 30, 2011 and 2010.  These adjustments are of a normal and recurring nature.  These financial statements do not contain the complete detail or footnote disclosure concerning accounting policies and other matters that would be included in full-year financial statements and should be read in conjunction with the audited consolidated financial statements included in IDACORP’s and Idaho Power’s Annual Report on Form 10-K for the year ended December 31, 2010.  The results of operations for the interim periods are not necessarily indicative of the results to be expected for the full year.

U

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.

Reclassifications

Certain prior year amounts have been reclassified to conform to the current year presentation, including amounts related to regulatory assets and liabilities in the condensed consolidated balance sheets.  Net income, cash flows, and shareholders' equity were not affected by these reclassifications.

Description of New Accounting Pronouncements Not yet Adopted

The Financial Accounting Standards Board (FASB) has issued the following accounting guidance, which is effective for periods beginning after December 15, 2011:

• In May 2011, the FASB issued guidance to provide a consistent definition of fair value and ensure that the fair value measurement and disclosure requirements are similar between generally accepted accounting principles in the United States and International Financial Reporting Standards. The guidance changes certain fair value measurement principles and enhances the disclosure requirements, particularly for Level 3 fair value measurements. IDACORP and Idaho Power are currently assessing the impact of the guidance but do not believe that the adoption of this guidance will have a material effect on their consolidated financial statements.

• In June 2011, the FASB issued guidance on the presentation of comprehensive income in an entity's financial statements. The guidance requires that comprehensive income be presented either in one continuous statement or in two separate but consecutive statements presenting the components of net income and its total, the components of other comprehensive income and its total, and total comprehensive income. The guidance also requires that reclassification adjustments from other comprehensive income to net income be presented in both the components of net income and the components of other comprehensive income. IDACORP and Idaho Power do not expect the adoption of this guidance to have a material effect on their consolidated financial statements.

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EARNINGS PER SHARE:

3 Months Ended

Sep. 30, 2011

Earnings Per Share [Abstract]

Earnings Per Share

EARNINGS PER SHARE

The following table presents the computation of IDACORP’s basic and diluted earnings per share (EPS) for the three and nine months endedSeptember 30, 2011 and 2010 (in thousands, except for per share amounts):

	Three months ended September 30,				Nine months ended September 30,
	2011		2010		2011		2010
Numerator:
Net income attributable to IDACORP, Inc.	$	107,067	$	67,135	$	157,708	$	122,407
Denominator:
Weighted-average common shares outstanding - basic	49,520		48,086		49,411		47,917
Effect of dilutive securities:
Options	12		30		15		37
Restricted Stock	90		136		73		108
Weighted-average common shares outstanding - diluted	49,622		48,252		49,499		48,062
Basic earnings per share	$	2.16	$	1.40	$	3.19	$	2.55
Diluted earnings per share	$	2.16	$	1.39	$	3.19	$	2.55

The diluted EPS computation excludes 134,772 and 183,840 options for the three and nine months endedSeptember 30, 2011, respectively, because the options’ exercise prices were greater than the average market price of the common stock during that period.  For the same period in 2010, the computation excludes 321,891 and 337,242 options for the same reason.  In total, 169,295 options were outstanding at September 30, 2011, with expiration dates between 2011 and 2015.

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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, 2009	$ 1,401,544	$ 756,475	$ 649,180	$ (8,267)	$ (53)	$ 1,397,335	$ 4,209
Common stock issued	38,086	38,086
Other common stock changes	1,954	1,954
Net income attributable to IDACORP, Inc.	122,407		122,407
Common stock dividends	(43,321)		(43,321)
Unrealized (loss) gain on securities (net of tax)	218			218
Unfunded pension liability adjustment (net of tax)	532			532
Treasury stock issued	882				882
Treasury stock acquired	(846)				(846)
Net income (loss) attributable to noncontrolling interest	(188)						(188)
Total equity at end of period at Sep. 30, 2010	1,521,268	796,515	728,266	(7,517)	(17)	1,517,247	4,021
Balance at beginning of period at Dec. 31, 2010	1,535,984	807,842	733,879	(9,568)	(40)	1,532,113	3,871
Common stock issued	10,408	10,408
Other common stock changes	2,021	2,021
Net income attributable to IDACORP, Inc.	157,708		157,708
Common stock dividends	(44,714)		(44,714)
Unrealized (loss) gain on securities (net of tax)	(1,401)			(1,401)
Unfunded pension liability adjustment (net of tax)	701			701
Treasury stock issued	1,944				1,944
Treasury stock acquired	(1,933)				(1,933)
Net income (loss) attributable to noncontrolling interest	170						170
Total equity at end of period at Sep. 30, 2011	$ 1,660,888	$ 820,271	$ 846,873	$ (10,268)	$ (29)	$ 1,656,847	$ 4,041

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INCOME TAXES: Level 4 (Details) (USD $)	3 Months Ended			9 Months Ended
	Sep. 30, 2011	Jun. 30, 2011	Sep. 30, 2010	Sep. 30, 2011	Sep. 30, 2010
Income Tax Expense [Line Items]
Income tax at statutory rates (federal and state)	$ 24,123,000		$ 30,204,000	$ 44,407,000	$ 45,824,000
Additional ADITC amortization reversed	6,750,000		0	0	(32,561,000)
Accounting method change	0		(7,374,000)	(3,428,000)	0
Examination settlement - uniform capitalization	(56,898,000)		0	(56,898,000)	0
Other	(19,347,000)		(12,715,000)	(28,218,000)	(18,473,000)
Income tax (benefit) expense	(45,372,000)		10,115,000	(44,137,000)	(5,210,000)
Effective tax rate	(73.50%)		13.10%	(38.90%)	(4.40%)
Examination settlement to be paid	3,900,000			3,900,000
Return of previously made estimated tax payments				13,000,000
Idaho Power Company
Income Tax Expense [Line Items]
Income tax at statutory rates (federal and state)	24,671,000		31,036,000	46,303,000	48,451,000
Additional ADITC amortization reversed	6,750,000		0	0	(32,561,000)
Accounting method change	0		(7,374,000)	(3,428,000)	0
Examination settlement - uniform capitalization	(56,898,000)		0	(56,898,000)	0
Other	(16,299,000)		(8,936,000)	(22,974,000)	(13,674,000)
Income tax (benefit) expense	(41,776,000)		14,726,000	(36,997,000)	2,216,000
Effective tax rate	(66.20%)		18.60%	(31.20%)	1.80%
Return on equity threshold below which additional amortization of ADITC is allowed	9.50%			9.50%
Additional ADITC amortization available for use in 2011	25,000,000			25,000,000
Amount of tax benefits recognized as a result of method settlement		3,400,000		2,000,000
Examination settlement to be paid	$ 8,100,000			$ 8,100,000

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LONG-TERM DEBT:

3 Months Ended

Sep. 30, 2011

Long-term Debt, Unclassified [Abstract]

Long-term Debt

LONG-TERM DEBT

As of September 30, 2011, 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.  As of September 30, 2011, $300 million remained on Idaho Power’s shelf registration for the issuance of first mortgage bonds and debt securities.

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

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CONTINGENCIES:

3 Months Ended

Sep. 30, 2011

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 (i) the remedies or penalties sought are indeterminate, (ii) the proceedings are in the early stages or the substantive issues have not been well developed, or (iii) 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 will change, and the estimates themselves will 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 court decisions, and the adverse party's willingness to negotiate towards a resolution, it may be months or years after the filing of a case 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.

Western Energy Proceedings at the FERC

High prices for electricity, energy shortages, and blackouts in California and in western wholesale markets during 2000 and 2001 caused numerous purchasers of electricity in those markets to initiate proceedings seeking refunds or other forms of relief and the FERC to initiate its own investigations.  Some of these proceedings remain pending before the FERC or are on appeal to the United States Court of Appeals for the Ninth Circuit (Ninth Circuit). Except as to the matters described below under “Pacific Northwest Refund,” Idaho Power and IE believe that settlement releases they have obtained will restrict potential claims that might result from the disposition of the pending Ninth Circuit review petitions and predict that these matters will not have a material adverse effect on their consolidated financial positions, results of operations, or cash flows.

Pacific Northwest Refund:  On July 25, 2001, the FERC issued an order establishing a proceeding 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 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. 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 to be appointed within fifteen days of the issuance of its order.

IE and Idaho Power intend to continue to defend their positions in the Pacific Northwest refund proceedings vigorously. As of the date of this report, it is difficult to meaningfully predict the eventual outcome of this matter given the uncertainties that attended the FERC's earlier orders in this case, the fact that specific claims conforming to the FERC's October 3, 2011 order have not yet been submitted, and that the FERC's order remains subject to rehearing and reconsideration. Idaho Power and IE are unable to predict whether the FERC will order refunds, which contracts would be subject to 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 possible loss or range of possible loss that Idaho Power or IE could incur as a result of this matter.

Sierra Club Lawsuit and EPA Notice of Violation - Boardman

In September 2008, the Sierra Club and four other non-profit corporations filed a complaint against Portland General Electric Company (PGE) in the U.S. District Court for the District of Oregon alleging opacity permit limit and Clean Air Act (CAA) violations at the Boardman coal-fired plant located in Morrow County, Oregon.  The complaint sought, in addition to injunctive remedies, civil penalties of up to $32,500 per day per violation, and reimbursement of plaintiffs' costs of litigation, including reasonable attorneys' fees.  Idaho Power was not a party to this proceeding but has a 10 percent ownership interest in the Boardman plant and may have an obligation to reimburse PGE for costs incurred and losses resulting from the proceeding.  PGE owns 65 percent of the plant and is the operator of the plant. In July 2011, the parties filed a consent decree with the court that resolves all of the plaintiffs' claims. The consent decree provides that PGE will pay $2.5 million to the Oregon Community Foundation to be used for environmentally beneficial projects and will pay $1.0 million of the plaintiff's legal expenses. Further, the consent decree imposes certain SO₂ emission caps on the Boardman coal-fired boiler and would allow continued operation of the Boardman plant through December 31, 2020. The court entered the consent decree on September 13, 2011, following the conclusion of the CAA's statutory review period. Idaho Power considers the matter resolved, and payment of the settlement amount did not have a material adverse effect on Idaho Power's financial position, results of operations, or cash flows.

In September 2010, the United States Environmental Protection Agency (EPA) issued a Notice of Violation to PGE, alleging that PGE had violated the New Source Performance Standards (NSPS) and operating permit requirements under the CAA as a result of modifications made to the Boardman plant in 1998 and 2004.  The Notice of Violation states the maximum civil penalties the EPA is authorized to impose under the CAA for violations of the NSPS (which range from $25,000 to $37,500 per day), but it does not impose any penalties or specify the amount of any proposed penalties with respect to the alleged violations. It is difficult to meaningfully predict the eventual outcome of this matter given the complexity of the environmental statutes and claims cited in the Notice of Violation and the matters at issue, the unspecified nature of the penalty or other remedy sought, and the absence of factual information given the early stage of the proceedings. As of the date of this report, based on available information and the status of this matter, Idaho Power is unable to estimate the possible loss or range of possible loss that Idaho Power could incur as a result of this matter. However, PGE, the plant operator, has stated that based on its understanding of the penalties authorized under the CAA, the maximum penalty that could be imposed for the alleged violations is approximately $60 million, with Idaho Power's share of any such penalty being limited to 10 percent of the amount ultimately assessed, if any. The projects alleged to have triggered the NSPS in the Notice of Violation were also included in the Sierra Club's claims in the litigation described immediately above.

Water Rights - Snake River Basin Adjudication

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

Over time, increased irrigation development and other consumptive uses within the Snake River watershed led to a reduction in flows of the Snake River.  In the late 1970's and early 1980's these reduced flows resulted in a conflict between the exercise of Idaho Power's water rights at certain hydroelectric projects on the Snake River and upstream consumptive diversions.  The Swan Falls Agreement, signed by Idaho Power and the State of Idaho on October 25, 1984, resolved the conflict and provided a level of protection for Idaho Power's hydropower water rights at specified projects on the Snake River through the establishment of minimum stream flows and an administrative process governing future development of water rights that may affect those minimum stream flows.  In 1987, Congress enacted legislation directing the FERC to issue an order approving the Swan Falls settlement together with a finding that the agreement was neither inconsistent with the terms and conditions of Idaho Power's project licenses nor the Federal Power Act.  The FERC entered an order implementing the legislation on March 25, 1988.

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

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

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

U.S. Bureau of Reclamation Proceedings

Idaho Power filed a complaint on October 15, 2007, and an amended complaint on September 30, 2008, in the U.S. District Court of Federal Claims in Washington, D.C. against the U.S. Bureau of Reclamation (USBR).  The complaint relates to a 1923 spaceholder contract right for storage and delivery of water to Idaho Power from American Falls Reservoir, a USBR storage reservoir on the Snake River.  In the complaint, Idaho Power alleged that the USBR breached the contract by the failure to implement certain contract provisions relating to secondary storage capacity and claimed damages for the lost generation resulting from reduced flows downstream of the reservoir, and requested a prospective declaration of the rights and obligations of the parties under the 1923 contract.  The USBR claimed that the referenced provisions of the 1923 contract were abrogated or amended by subsequent contracts associated with the 1976 rebuild of American Falls Reservoir and that the provisions of the 1923 contract no longer apply.  The water rights for, and the operation of, American Falls Reservoir are also the subject of litigation in the SRBA, described above. 

During the pendency of the proceedings, Idaho Power worked with the USBR and Idaho interests (including the State of Idaho and upstream water users) in an effort to resolve the contested contract issues that are common to both the SRBA and the pending federal case with the USBR.  These efforts were focused on a recognition in state policy and the Idaho State Water Plan that will promote more efficient operation of the upper Snake River reservoir system to optimize the use of Snake River flows for hydroelectric generation downstream while recognizing and protecting in-reservoir spaceholder contract rights.  These discussions resulted in a resolution passed by the Idaho Water Resource Board in March 2011 that established a standing committee, referred to as the Upper Snake River Advisory Committee (USRAC). The USRAC is comprised of a member of the Idaho Water Resource Board, representatives of Idaho Power, the USBR, and the Committee of Nine, a committee comprised of upstream water users that hold USBR contract rights to reservoir space that advises the State of Idaho and the USBR on reservoir operations. The USRAC is tasked with collaboratively working to identify and implement measures to optimize the operation and management of the reservoir system above Milner Dam to benefit existing and future beneficial uses, including hydropower below Milner Dam. This collaborative process will include a review of existing water bank and rental pool procedures to encourage and facilitate opportunities for the rental, acquisition, and transfer of reservoir storage water and water rights for beneficial uses, including hydropower. The passage of the resolution and establishment of the USRAC has effectively resolved the critical issues outstanding in the pending litigation pertaining to the 1923 contract. While Idaho Power is unable to predict the ultimate impact of the collaborative process, as of the date of this report it does not expect the outcome of the process will have a material adverse effect on its financial position, results of operations, or cash flows.

Other Legal Proceedings

IDACORP and Idaho Power are parties to legal claims, actions, and proceedings in addition to those discussed above.  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

Sep. 30, 2011

Notes Payable [Abstract]

Notes Payable

NOTES PAYABLE

Credit Facilities

On October 26, 2011, each of IDACORP and Idaho Power entered into a Second Amended and Restated Credit Agreement with Wells Fargo Bank, National Association, as administrative agent, swingline lender, and LC issuer; JPMorgan Chase Bank, N.A., as syndication agent and LC issuer; KeyBank National Association and Union Bank, N.A., as documentation agents; Wells Fargo Securities, LLC, J.P. Morgan Securities Inc., Keybanc Capital Markets, and Union Bank, N.A. as joint lead arrangers and joint book runners; and the other financial institutions party thereto, as lenders. The new credit agreements amend and restate IDACORP's and Idaho Power's existing $100 million and $300 million, respectively, credit facilities dated April 25, 2007, that were to expire on April 25, 2012. The credit facilities will be used for general corporate purposes and commercial paper backup. IDACORP's credit agreement provides for the issuance 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 agreement provides for 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 agreements mature on October 26, 2016, though 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 September 30, 2011, no loans were outstanding under either IDACORP's or Idaho Power's facilities then in effect.  At September 30, 2011, Idaho Power had regulatory authority to incur up to $450 million of short-term indebtedness.

 Balances and interest rates of IDACORP’s short-term borrowings were as follows at September 30, 2011 and December 31, 2010 (in thousands of dollars):

	September 30, 2011			December 31, 2010
Commercial paper outstanding	$	51,500		$	66,900
Weighted-average annual interest rate	0.42		%	0.43		%

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

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FAIR VALUE MEASUREMENTS: Level 3 (Tables)

3 Months Ended

Sep. 30, 2011

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 September 30, 2011 and December 31, 2010 (in thousands of dollars).  IDACORP’s and Idaho Power’s assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy.  There were no transfers between levels for the periods presented. 

	Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)		Total
September 30, 2011
IDACORP
Assets:
Derivatives	$	3,826	$	80	$	—	$	3,906
Money market funds	100		—		—		100
Trading securities:  Equity securities	3,239		—		—		3,239
Available-for-sale securities:  Equity securities	21,346		—		—		21,346
Liabilities:
Derivatives	$	130	$	977	$	—	$	1,107
Idaho Power
Assets:
Derivatives	$	3,826	$	80	$	—	$	3,906
Money market funds	100		—		—		100
Trading securities:  Equity securities	3,239		—		—		3,239
Available-for-sale securities:  Equity securities	21,346		—		—		21,346
Liabilities:
Derivatives	$	130	$	977	$	—	$	1,107
December 31, 2010
IDACORP
Assets:
Derivatives	$	573	$	—	$	—	$	573
Money market funds	151,975		—		—		151,975
Trading securities:  Equity securities	5,361		—		—		5,361
Available-for-sale securities:  Equity securities	24,561		—		—		24,561
Liabilities:
Derivatives	$	—	$	508	$	—	$	508
Idaho Power
Assets:
Derivatives	$	573	$	—	$	—	$	573
Money market funds	151,173		—		—		151,173
Trading securities:  Equity securities	4,746		—		—		4,746
Available-for-sale securities:  Equity securities	24,561		—		—		24,561
Liabilities:
Derivatives	$	—	$	508	$	—	$	508

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 September 30, 2011 and December 31, 2010, using available market information and appropriate valuation methodologies.  The use of different market assumptions and/or estimation methodologies may have a material effect on the estimated fair value amounts.  Cash and cash equivalents, deposits, customer and other receivables, notes payable, accounts payable, interest accrued, and taxes accrued are reported at their carrying value as these are a reasonable estimate of their fair value.  The estimated fair values for notes receivable and long-term debt are based upon quoted market prices of the same or similar issues or discounted cash flow analysis as appropriate. 

	September 30, 2011				December 31, 2010
	Carrying		Estimated		Carrying		Estimated
	Amount		Fair Value		Amount		Fair Value
	(thousands of dollars)
IDACORP
Assets:
Notes receivable	$	2,946	$	2,946	$	2,946	$	2,946
Liabilities:
Long-term debt	1,492,330		1,729,623		1,614,299		1,622,924
Idaho Power
Liabilities:
Long-term debt	$	1,491,727	$	1,729,022	$	1,612,790	$	1,621,425

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REGULATORY MATTERS:

3 Months Ended

Sep. 30, 2011

Regulatory Matters Disclosures [Abstract]

Regulatory Matters

REGULATORY MATTERS

Recent and Pending Idaho Regulatory Matters

Idaho General Rate Case

On June 1, 2011, Idaho Power filed with the IPUC a general rate case and proposed rate schedules for its Idaho jurisdiction, Case No. IPC-E-11-08. The filing was based on a 2011 test year and requested approximately $82.6 million in additional Idaho jurisdiction annual revenues in base rates, a 9.9 percent overall average rate increase for Idaho customers. The filing requested an authorized rate of return on equity of 10.5 percent (an overall 8.17 percent rate of return in the Idaho jurisdiction) on an Idaho retail rate base of approximately $2.4 billion, and the following additional items:

• Authority to treat demand response incentive payments (payments Idaho Power has made in connection with certain energy efficiency activities) as power supply expenses and establish a base or "normal" level of cost recovery for those payments in base rates. Idaho Power included approximately $11.3 million associated with forecasted fixed demand response incentive payments for 2011 in the Idaho jurisdictional revenue requirement calculations included in the general rate case application, which would be subject to true-up under the Idaho PCA mechanism.

• Approval of the current fixed cost adjustment (FCA) mechanism pilot program as a permanent rate mechanism for residential and small commercial class customers. The FCA allows Idaho Power to recover the difference between certain fixed costs recovered and the fixed costs authorized for recovery in Idaho Power's most recent rate case.  

• An updated load change adjustment rate (LCAR) of $19.28 per megawatt-hour (MWh). The LCAR adjusts power supply cost recovery within the Idaho power cost adjustment (PCA) formula by adjusting recovery upwards or downwards for differences between actual load and the load used in calculating base rates.

On September 23, 2011, Idaho Power, the Staff of the IPUC, 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. The settlement stipulation is subject to approval by the IPUC.

The settlement stipulation provides that Idaho Power would implement revised tariff schedules designed to recover $34.0 million in additional annual revenue from Idaho jurisdictional base rates effective January 1, 2012, representing a 4.07 percent overall average increase in Idaho Power's annual Idaho jurisdictional base rate revenues. The $34.0 million of additional annual revenue is inclusive of approximately $11.3 million of base level demand response incentive payments (made in connection with certain energy efficiency activities) to be tracked as part of the Idaho PCA mechanism. The settlement stipulation also provides that approximately $23 million of Idaho jurisdictional revenue associated with the recovery of power supply expenses from PURPA projects would not be included in base rates, but would instead be eligible for 100 percent recovery through the PCA mechanism. The settlement stipulation also provides for a 7.86 percent authorized rate of return on an Idaho jurisdictional rate base of approximately $2.4 billion, and for the IPUC to allow Idaho Power to earn an authorized rate of return of 7.86 percent in any Idaho Power regulatory matter until subsequently changed by IPUC order.

The settlement stipulation provides for an LCAR of $18.16 per MWh, compared to the rate of $19.67 per MWh in effect on the date of filing of the general rate case, to become effective on the date that Idaho Power's new base rates become effective. The settlement stipulation provides that the determination of whether the FCA pilot program should be made permanent and the appropriate percentage amount for Idaho Power's energy efficiency rider would be examined in subsequent proceedings.

The parties to the settlement stipulation have requested that the IPUC issue an order approving the agreed-upon rates effective January 1, 2012. If the IPUC were to deny the settlement stipulation or materially change its terms, no party would be bound by the terms of the stipulation. Idaho Power is unable to predict whether the IPUC will approve the settlement stipulation or the ultimate outcome of the general rate case proceedings.

January 2010 Idaho Settlement Agreement and 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 of any Idaho jurisdiction earnings exceeding a return on year-end equity of 10.5 percent in the Idaho jurisdiction.  Recognition of tax benefits in the third quarter of 2011, discussed in further detail in Note 2, had a significant impact on Idaho Power's estimate of return on 2011 year-end equity and contributed to triggering of the sharing mechanism under the January 2010 settlement agreement. As a result of the terms of the settlement agreement, Idaho Power also recorded an $18.1 million regulatory liability, reflecting 50 percent of Idaho Power's estimated Idaho jurisdictional earnings over a 10.5 percent return on year-end equity required to be shared with customers.

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, with the following terms:

• If Idaho Power's Idaho jurisdiction return on year-end equity for 2012 or 2013 is less than 9.5 percent, then Idaho Power may continue to use up to $45 million of deferred investment tax credits to help achieve a minimum 9.5 percent return on year-end equity in the Idaho jurisdiction in those years. Idaho Power may use an aggregate of $45 million of additional ADITC in 2012 and 2013, comprised of up to a maximum of $25 million of additional ADITC in 2012 and any unused portion carried forward to 2013.

• If Idaho Power's Idaho jurisdictional return on year-end equity for 2012 or 2013 exceeds 10.0 percent, the amount exceeding 10.0 percent would be shared equally between Idaho Power and its customers in the applicable year.

• Idaho Power would allocate to customers 50 percent of Idaho Power's share of estimated 2011 Idaho jurisdictional earnings over a 10.5 percent return on year-end equity, reflected as a reduction in customer rates or an offset to amounts that would otherwise be collected from rates.

The application provides that it is independent and separate from the 2011 general rate case proceeding and the associated settlement stipulation, and further provides that Idaho Power will withdraw the application in the event Idaho Power's base rate revenues are not increased in accordance with the terms of the general rate case settlement stipulation. The application also states that Idaho Power's proposal to apply a one-time adjustment to the 2011 sharing calculation is contingent on the completion of a signed settlement stipulation agreeing to the extension and modification of the ADITC amortization and sharing mechanisms, as described above, on or before December 31, 2011.

Idaho Power Cost Adjustment Order

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

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

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

On May 31, 2011, the IPUC issued an order approving Idaho Power's requested $40.4 million Idaho PCA rate decrease, with the new PCA rates effective for the period from June 1, 2011 to May 31, 2012. The reduction to Idaho PCA rates was net of $10.0 million of Idaho Power’s energy efficiency rider deferral balance that the IPUC had previously authorized for recovery in Idaho Power’s Idaho PCA rates.

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

On May 31, 2011, the IPUC issued an order revising the LCAR used in PCA calculations to $19.67 per MWh (through a June 1, 2011 errata), effective as of April 1, 2011. The September 23, 2011 general rate case settlement stipulation, if approved, would result in an LCAR of $18.16 per MWh, effective January 1, 2012.

Fixed Cost Adjustment Mechanism

On March 15, 2011, Idaho Power filed an application with the IPUC requesting authorization to implement revised FCA rates for electric service from June 1, 2011 through May 31, 2012.  Idaho Power's application requested an aggregate increase of $3.0 million in FCA rates for the residential and small general service customer classes in its Idaho jurisdiction. On May 31, 2011, the IPUC issued an order approving Idaho Power's application, with the $3.0 million FCA rate increase to be effective for the period from June 1, 2011 to May 31, 2012. On October 19, 2011, Idaho Power filed an application with the IPUC requesting that the FCA pilot program become a permanent rate mechanism for residential and small general service customer classes. The FCA pilot program is set to expire on December 31, 2011.

Recovery of Defined Benefit Pension Plan Contributions

In September 2010, Idaho Power elected to make a $60 million contribution to its defined benefit pension plan, rather than the minimum required funding amount, to bring the defined benefit pension plan to a more funded position, potentially reducing future required contributions and Pension Benefit Guaranty Corporation premiums.  On March 15, 2011, Idaho Power filed an application with the IPUC requesting an increase in the amount included in base rates for recovery of the Idaho-allocated portion of Idaho Power's cash contributions to its defined benefit pension plan from the then-current amount of $5.4 million to approximately $17.1 million annually. The requested increase was intended to recover the balance of the Idaho jurisdictional allocation of the $60 million pension contribution over a three year period.  On May 19, 2011, the IPUC approved Idaho Power’s application, with new rates effective on June 1, 2011.

Energy Efficiency and Demand Response Programs

Idaho Power has implemented and/or manages a wide range of opportunities for its customers to participate in energy efficiency and demand response programs.  On August 18, 2011, the IPUC issued an order approving Idaho Power's March 2011 application requesting that the IPUC designate Idaho Power's 2010 Idaho energy efficiency rider expenditures of approximately $42 million as prudently incurred expenses.

On October 22, 2010, Idaho Power filed an application with the IPUC requesting acceptance of the company's demand-side resources (DSR) business model, which included a request for authorization to (a) move demand response incentive payments out of the energy efficiency rider and into the Idaho PCA on a prospective basis beginning on June 1, 2011, and thus subject to a true-up under the PCA mechanism; (b) establish a regulatory asset for the direct incentive payments associated with Idaho Power's energy efficiency program for large commercial and industrial customers, beginning January 1, 2011, so that Idaho Power may capitalize the direct incentive payments associated with the program, include the costs associated with the program incentive payments in its rate base, and thus earn a rate of return on a portion of its DSR activities; and (c) change the carrying charge on the existing energy efficiency rider balancing account (from the then-current interest rate of 1.0 percent to Idaho Power's authorized rate of return). On April 1, 2011, the IPUC issued an order stating that certain issues raised in the application are more properly considered in a general rate case proceeding. However, the IPUC noted in its order that Idaho Power's energy efficiency rider balance includes approximately $10 million in expenditures that have been previously approved by the IPUC for recovery, and thus authorized recovery of $10 million of the rider balance in Idaho Power's Idaho PCA rates, beginning June 1, 2011. The IPUC did not approve a change to the energy efficiency rider balance carrying charge.

On May 17, 2011, the IPUC issued an order stating that it will allow Idaho Power to account for specified direct incentive payments associated with Idaho Power's energy efficiency program for large commercial and industrial customers as a regulatory asset beginning January 1, 2011, but with an amortization period to be determined later by the IPUC.

In its June 1, 2011 general rate case filing, Idaho Power requested authorization to treat demand response incentive payments as power supply costs and establish a base or "normal" level of cost recovery of approximately $11.3 million for those demand response incentive payments in rates. The Idaho general rate case settlement stipulation filed with the IPUC on September 23, 2011 provides that the $11.3 million of base level demand response incentive payments would be tracked as part of the Idaho PCA mechanism.

Transmission Rate Refunds and Shortfall Filing

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

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

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 requests a $5.8 million increase in annual Oregon jurisdictional revenues which, if approved, would result in a 14.7 percent overall average rate increase for customers in the Oregon jurisdiction. The filing requests an authorized rate of return on equity of 10.5 percent with an Oregon retail rate base of approximately $121.9 million, and a rate of return on capital of 8.17 percent. Idaho Power is unable to predict the outcome of the general rate case but anticipates that new rates, if approved by the OPUC, would not become effective until June 1, 2012.

Oregon Power Cost Adjustment Mechanism Filings

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

The APCU allows Idaho Power to reestablish its Oregon base net power supply costs annually, separate from a general rate case, and to forecast net power supply costs for the upcoming water year.  The APCU has two components:  the “October Update,” Idaho Power's calculation of estimated normalized net power supply costs for the following April through March test period, and the “March Forecast,” Idaho Power's forecast of expected net power supply costs for the same test period, updated for a number of variables including the most recent stream flow data and future wholesale electric prices. On May 31, 2011, the OPUC approved Idaho Power's March 2011 request for a $0.9 million annual decrease in amounts collected through Oregon jurisdiction customer rates, with new rates effective June 1, 2011. On October 20, 2011, Idaho Power filed the October Update portion of the APCU, requesting a $1.4 million increase in amounts collected through Oregon jurisdiction customer rates, effective June 1, 2012.

The PCAM is a true-up filed annually in February.  The filing calculates the deviation between actual net power supply costs incurred for the preceding calendar year and the net power supply costs recovered through the APCU for the same period.  Under the PCAM, Idaho Power is subject to a portion of the business risk or benefit associated with this deviation through application of an asymmetrical deadband (or range of deviations) within which Idaho Power absorbs cost increases or decreases.  On February 28, 2011, Idaho Power submitted its 2010 PCAM true-up, stating that actual net power supply costs were within the deadband, resulting in no deferral. 

Annual OATT Update

On September 1, 2011, Idaho Power filed its 2011 Final Informational Filing (FIF) for its OATT with the FERC and posted the FIF on its Open Access Same-Time Information System (OASIS) Internet platform, for rates that became effective on October 1, 2011 for a one-year period. The FIF is the computation of Idaho Power’s transmission formula rate for service under its OATT, which is updated annually. The new rate posted by Idaho Power was $19.79 per kW/yr, reflective of a $107 million net annual transmission revenue requirement. The previous OATT rate was $19.60 per kW/yr.

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Condensed Consolidated Statements of Comprehensive Income (USD $) In Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2011	Sep. 30, 2010	Sep. 30, 2011	Sep. 30, 2010
Net Income	$ 107,414	$ 67,125	$ 157,878	$ 122,219
Other Comprehensive Income:
Net unrealized holding gains (losses) arising during the period, net of tax	(1,961)	984	(1,401)	218
Unfunded pension liability adjustment, net of tax	234	177	701	532
Total Comprehensive Income	105,687	68,286	157,178	122,969
Comprehensive (income) loss attributable to noncontrolling interests	(347)	10	(170)	188
Comprehensive Income Attributable to IDACORP, Inc.	105,340	68,296	157,008	123,157
Idaho Power Company
Net Income	104,872	64,650	155,420	121,700
Other Comprehensive Income:
Net unrealized holding gains (losses) arising during the period, net of tax	(1,961)	984	(1,401)	218
Unfunded pension liability adjustment, net of tax	234	177	701	532
Total Comprehensive Income	$ 103,145	$ 65,811	$ 154,720	$ 122,450

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Condensed Consolidated Statements of Equity (Parenthetical) (USD $)	3 Months Ended		9 Months Ended
	Sep. 30, 2011	Sep. 30, 2010	Sep. 30, 2011	Sep. 30, 2010
Common stock dividends, per share	$ 0.30	$ 0.30	$ 0.90	$ 0.90

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EARNINGS PER SHARE: Level 4 (Details) (USD $) In Thousands, except Share data	3 Months Ended		9 Months Ended
	Sep. 30, 2011	Sep. 30, 2010	Sep. 30, 2011	Sep. 30, 2010
Numerator:
Net income attributable to IDACORP, Inc.	$ 107,067	$ 67,135	$ 157,708	$ 122,407
Denominator:
Weighted Average Common Shares Outstanding - Basic	49,520,000	48,086,000	49,411,000	47,917,000
Options	12,000	30,000	15,000	37,000
Restricted Stock	90,000	136,000	73,000	108,000
Weighted Average Common Shares Outstanding - Diluted	49,622,000	48,252,000	49,499,000	48,062,000
Earnings Attributable to IDACORP, Inc. - Basic	$ 2.16	$ 1.40	$ 3.19	$ 2.55
Earnings Attributable to IDACORP, Inc. - Diluted	$ 2.16	$ 1.39	$ 3.19	$ 2.55
Antidilutive securities excluded from computation of earnings per share	134,772	321,891	183,840	337,242
Options outstanding	169,295		169,295

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DERIVATIVE FINANCIAL INSTRUMENTS: Level 3 (Tables)

3 Months Ended

Sep. 30, 2011

Derivative Financial Instruments [Abstract]

Schedule of Derivative Instruments [Table Text Block]

Idaho Power had the following volumes of derivative commodity forward contracts and swaps outstanding at September 30, 2011 and 2010:

		September 30,
Commodity	Units	2011	2010
Electricity purchases	MWh	197,800	443,250
Electricity sales	MWh	1,038,095	237,000
Natural gas purchases	MMBtu	2,292,738	325,500
Natural gas sales	MMBtu	77,500	—
Diesel purchases	Gallons	266,375	208,980

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

The following tables present the fair values and locations of derivative instruments not designated as hedging instruments recorded on the balance sheets at September 30, 2011 and December 31, 2010 (in thousands of dollars):

	Asset Derivatives			Liability Derivatives
	Balance Sheet	Fair		Balance Sheet	Fair
	Location	Value		Location	Value
September 30, 2011
Current:
Financial swaps	Other current assets	$	4,192	Other current assets	$	900
Financial swaps	Other current liabilities	—		Other current liabilities	356
Forward contracts	Other current assets	80		Other current liabilities	406
Long-term:
Financial swaps	Other assets	559		Other assets	25
Financial swaps				Other liabilities	344
Total		$	4,831		$	2,031
December 31, 2010
Current:
Financial swaps	Other current assets	$	930	Other current assets	$	356
Financial swaps	Other current liabilities	2,440		Other current liabilities	4,172
Forward contracts				Other current liabilities	508
Long-term:
Financial swaps	Other liabilities	100		Other liabilities	138
Total		$	3,470		$	5,174

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

The following table presents the gains and losses on derivatives not designated as hedging instruments for the three and nine months endedSeptember 30, 2011 and 2010 (in thousands of dollars):

	Location of Gain/(Loss)	Gain/(Loss)
	on Derivatives	on Derivatives
Commodity Derivatives	Recognized in Income	Recognized in Income(1)
Three months ended September 30, 2011:
Financial swaps	Off-system sales	$	441
Financial swaps	Purchased power	(6,982		)
Financial swaps	Fuel expense	115
Financial swaps	Other operations and maintenance	120
Three months ended September 30, 2010:
Financial swaps	Off-system sales	$	2,332
Financial swaps	Purchased power	(6,749		)
Financial swaps	Fuel expense	(101		)
Forward contracts	Fuel expense	(721		)
Nine months ended September 30, 2011:
Financial swaps	Off-system sales	$	6,947
Financial swaps	Purchased power	(6,954		)
Financial swaps	Fuel expense	501
Financial swaps	Other operations and maintenance	347
Nine months ended September 30, 2010:
Financial swaps	Off-system sales	$	3,284
Financial swaps	Purchased power	(9,135		)
Financial swaps	Fuel expense	(101		)
Forward contracts	Fuel expense	(721		)
(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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Condensed Consolidated Statements of Capitalization Statement (USD $) In Thousands	Sep. 30, 2011	Dec. 31, 2010
Common Stock Equity:
Common stock	$ 820,271	$ 807,842
Retained earnings	846,873	733,879
Accumulated other comprehensive loss	(10,268)	(9,568)
Total equity	1,660,888	1,535,984
Pollution control revenue bonds:
Total long-term debt	1,487,468	1,488,287
Idaho Power Company
Common Stock Equity:
Common stock	97,877	97,877
Premium on capital stock	688,758	688,758
Capital stock expense	(2,097)	(2,097)
Retained earnings	740,911	630,259
Accumulated other comprehensive loss	(10,268)	(9,568)
Total equity	1,515,181	1,405,229
First mortgage bonds:
Total first mortgage bonds	1,295,000	1,415,000
Amount due within one year	0	(120,000)
First mortgage bonds	1,295,000	1,295,000
Pollution control revenue bonds:
5.15% Series due 2024	49,800	49,800
5.25% Series due 2026	116,300	116,300
Variable Rate Series 2000 due 2027	4,360	4,360
Total pollution control revenue bonds	170,460	170,460
American Falls bond guarantee	19,885	19,885
Milner Dam note guarantee	6,382	7,446
Note guarantee due within one year	(1,064)	(1,064)
Unamortized premium/discount - net	(3,195)	(3,440)
Total long-term debt	1,487,468	1,488,287
Total capitalization	3,002,649	2,893,516
Idaho Power Company | 6.60% Series due 2011
First mortgage bonds:
First mortgage bonds	0	120,000
Idaho Power Company | 4.75% Series due 2012
First mortgage bonds:
First mortgage bonds	100,000	100,000
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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CONTINGENCIES: Level 4 (Details) (Idaho Power Company, USD $)	Sep. 30, 2011
September 2008 Sierra Club complaint
Loss Contingencies Disclosure
Litigation settlement amount	$ 2,500,000
Litigation settlement amount legal expenses	1,000,000
Penalties sought per violation per day, maximum	32,500
Percent of Idaho Power ownership interest in Boardman	10.00%
Percent of majority owner ownership interest in Boardman	65.00%
September 2010 EPA notice of violation
Loss Contingencies Disclosure
Penalties sought per violation per day, maximum	37,500
Penalties sought per violation per day, minimum	25,000
Maximum penalty that could be imposed	$ 60,000,000

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EARNINGS PER SHARE: Level 3 (Tables)

3 Months Ended

Sep. 30, 2011

Earnings Per Share, Basic and Diluted [Abstract]

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

The following table presents the computation of IDACORP’s basic and diluted earnings per share (EPS) for the three and nine months endedSeptember 30, 2011 and 2010 (in thousands, except for per share amounts):

	Three months ended September 30,				Nine months ended September 30,
	2011		2010		2011		2010
Numerator:
Net income attributable to IDACORP, Inc.	$	107,067	$	67,135	$	157,708	$	122,407
Denominator:
Weighted-average common shares outstanding - basic	49,520		48,086		49,411		47,917
Effect of dilutive securities:
Options	12		30		15		37
Restricted Stock	90		136		73		108
Weighted-average common shares outstanding - diluted	49,622		48,252		49,499		48,062
Basic earnings per share	$	2.16	$	1.40	$	3.19	$	2.55
Diluted earnings per share	$	2.16	$	1.39	$	3.19	$	2.55

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SEGMENT INFORMATION: Level 3 (Tables)

3 Months Ended

Sep. 30, 2011

Segment Information [Abstract]

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

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

	Utility Operations		All Other		Eliminations			Consolidated Total
Three months ended September 30, 2011:
Revenues	$	308,045	$	1,585	$	—		$	309,630
Net income attributable to IDACORP, Inc.	104,872		2,195		—			107,067
Total assets as of September 30, 2011	4,719,173		124,273		(16,511		)	4,826,935
Three months ended September 30, 2010:
Revenues	$	308,468	$	889	$	—		$	309,357
Net income attributable to IDACORP, Inc.	64,650		2,485		—			67,135
Nine months ended September 30, 2011:
Revenues	$	793,031	$	3,076	$	—		$	796,107
Net income attributable to IDACORP, Inc.	155,420		2,288		—			157,708
Nine months ended September 30, 2010:
Revenues	$	801,719	$	2,354	$	—		$	804,073
Net income attributable to IDACORP, Inc.	121,700		707		—			122,407

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COMMITMENTS: Level 4 (Details) (USD $)	3 Months Ended	9 Months Ended
	Sep. 30, 2011 Bridger Coal Company	Sep. 30, 2011 Idaho Power Company
Guarantor Obligations
IERCo ownership interest in BCC	33.00%
IERCo guarantee of BCC reclamation obligation	$ 63,000,000
Total reclamation obligation of BCC	189,000,000
Guarantor Obligations Total Reclamation Trust Fund	74,000,000
Long-term Purchase Commitment
Long-term Purchase Commitment, Amount		128,000,000
Reduction of Long-term Purchase Commitment, Amount		$ 1,300,000,000

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

3 Months Ended

Sep. 30, 2011

Investments in Debt and Equity Securities [Abstract]

Available-for-sale Securities [Table Text Block]

The following table summarizes investments in debt and equity securities by IDACORP and Idaho Power as of September 30, 2011 and December 31, 2010 (in thousands of dollars): 

	September 30, 2011						December 31, 2010
	Gross Unrealized Gain		Gross Unrealized Loss		Fair Value		Gross Unrealized Gain		Gross Unrealized Loss		Fair Value
Available-for-sale securities	$	2,612	$	37	$	21,346	$	4,876	$	—	$	24,561

Schedule of Unrealized Loss on Investments [Table Text Block]

The following table summarizes the security that was in an unrealized loss position at September 30, 2011, but for which no other-than-temporary impairment was recognized (in thousands of dollars):

	Less than 12 months				12 months or longer
	Aggregate Unrealized Loss		Aggregate Related Fair Value		Aggregate Unrealized Loss		Aggregate Related Fair Value
Available-for-sale securities	$	37	$	1,222	$	—	$	—

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COMMITMENTS:

3 Months Ended

Sep. 30, 2011

Commitments [Abstract]

Commitments

COMMITMENTS

Purchase Obligations

The following items are the only material changes to long-term purchase commitments during the nine months endedSeptember 30, 2011:

• In 2011, Idaho Power entered into several power purchase agreements with wind and other alternative energy developers.  Payments pursuant to these agreements are expected to total approximately $128 million from 2011 to 2037.

• The IPUC issued orders on June 8, 2011 that disapproved 13 wind power purchase agreements. The orders were subject to a 21-day reconsideration period and reconsiderations were denied by the IPUC on July 27, 2011. At this time, Idaho Power considers all of these agreements to be terminated, though two of the projects have filed appeals with the Idaho Supreme Court. Payments pursuant to these 13 agreements were expected to total approximately $1.3 billion over the terms of the agreements and had previously been reported as purchase obligations.

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 September 30, 2011, representing IERCo's one-third share of BCC's total reclamation obligation of $189 million.  BCC has a reclamation trust fund set aside specifically for the purpose of paying these reclamation costs.  At September 30, 2011, the value of the reclamation trust fund totaled $74 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 September 30, 2011, management believes the likelihood is remote that IDACORP or Idaho Power would be required to perform under such indemnification provisions or otherwise incur any significant losses with respect to such indemnification obligations.  Neither IDACORP nor Idaho Power has recorded any liability on their respective condensed consolidated balance sheets with respect to these indemnification obligations.

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SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES:

3 Months Ended

Sep. 30, 2011

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 is regulated by the Federal Energy Regulatory Commission (FERC) and the state regulatory commissions of Idaho and Oregon.  Idaho Power is the parent of Idaho Energy Resources Co. (IERCo), a joint venturer in Bridger Coal Company (BCC), which mines and supplies coal to the Jim Bridger generating plant owned in part by Idaho Power.

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

Principles of Consolidation

IDACORP’s and Idaho Power’s consolidated financial statements include the accounts of each company, the subsidiaries that the companies control, and any variable interest entities (VIEs) for which the companies are the primary beneficiaries.  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 $16 million of intercompany long-term debt, which is eliminated in consolidation.  EEC has borrowed amounts from Ida-West to fund a portion of its required capital contributions to Marysville.  The loans are payable from EEC’s share of distributions and are secured by the stock of EEC and EEC’s interest in Marysville.  Ida-West is the primary beneficiary because the ownership of the intercompany note and the EEC note result in it controlling the entity.  Creditors of Marysville have no recourse to the general credit of IDACORP and there are no other arrangements that could require IDACORP to provide financial support to Marysville or expose IDACORP to losses.

Through IERCo, Idaho Power holds a variable interest in BCC, a VIE for which it is not the primary beneficiary.  IERCo is not the primary beneficiary because the power to direct the activities that most significantly impact the economic performance of BCC is shared with the joint venture partner.  The carrying value of BCC is $91 million at September 30, 2011, 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 – “Commitments.”

Through IFS, IDACORP also holds variable interests in VIEs for which it is not the primary beneficiary.  These VIEs are affordable housing developments and other real estate investments in which IFS holds limited partnership interests ranging from 5 to 99 percent.  As a limited partner, IFS does not control these entities and they are not consolidated.  These investments were acquired between 1996 and 2010.  IFS’s maximum exposure to loss in these developments is limited to its net carrying value, which was $66 million at September 30, 2011.

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 positions as of September 30, 2011, consolidated results of operations for the three and nine months endedSeptember 30, 2011 and 2010, and consolidated cash flows for the nine months endedSeptember 30, 2011 and 2010.  These adjustments are of a normal and recurring nature.  These financial statements do not contain the complete detail or footnote disclosure concerning accounting policies and other matters that would be included in full-year financial statements and should be read in conjunction with the audited consolidated financial statements included in IDACORP’s and Idaho Power’s Annual Report on Form 10-K for the year ended December 31, 2010.  The results of operations for the interim periods are not necessarily indicative of the results to be expected for the full year.

Use of Estimates

The preparation of condensed consolidated financial statements in accordance with generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and 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.

Reclassifications

Certain prior year amounts have been reclassified to conform to the current year presentation, including amounts related to regulatory assets and liabilities in the condensed consolidated balance sheets.  Net income, cash flows, and shareholders' equity were not affected by these reclassifications.

New Accounting Pronouncements

The Financial Accounting Standards Board (FASB) has issued the following accounting guidance, which is effective for periods beginning after December 15, 2011:

• In May 2011, the FASB issued guidance to provide a consistent definition of fair value and ensure that the fair value measurement and disclosure requirements are similar between generally accepted accounting principles in the United States and International Financial Reporting Standards. The guidance changes certain fair value measurement principles and enhances the disclosure requirements, particularly for Level 3 fair value measurements. IDACORP and Idaho Power are currently assessing the impact of the guidance but do not believe that the adoption of this guidance will have a material effect on their consolidated financial statements.

• In June 2011, the FASB issued guidance on the presentation of comprehensive income in an entity's financial statements. The guidance requires that comprehensive income be presented either in one continuous statement or in two separate but consecutive statements presenting the components of net income and its total, the components of other comprehensive income and its total, and total comprehensive income. The guidance also requires that reclassification adjustments from other comprehensive income to net income be presented in both the components of net income and the components of other comprehensive income. IDACORP and Idaho Power do not expect the adoption of this guidance to have a material effect on their consolidated financial statements.

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INVESTMENTS IN DEBT AND EQUITY SECURITIES:

3 Months Ended

Sep. 30, 2011

Investments [Abstract]

Investments in Debt and Equity Securities

INVESTMENTS IN DEBT AND EQUITY SECURITIES

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

The following table summarizes investments in debt and equity securities by IDACORP and Idaho Power as of September 30, 2011 and December 31, 2010 (in thousands of dollars): 

	September 30, 2011						December 31, 2010
	Gross Unrealized Gain		Gross Unrealized Loss		Fair Value		Gross Unrealized Gain		Gross Unrealized Loss		Fair Value
Available-for-sale securities	$	2,612	$	37	$	21,346	$	4,876	$	—	$	24,561

At the end of each reporting period, IDACORP and Idaho Power analyze securities in loss positions to determine whether they have experienced a decline in market value that is considered other-than-temporary.  At September 30, 2011, one security was in an unrealized loss position. The following table summarizes the security that was in an unrealized loss position at September 30, 2011, but for which no other-than-temporary impairment was recognized (in thousands of dollars):

	Less than 12 months				12 months or longer
	Aggregate Unrealized Loss		Aggregate Related Fair Value		Aggregate Unrealized Loss		Aggregate Related Fair Value
Available-for-sale securities	$	37	$	1,222	$	—	$	—

No other-than-temporary impairment was recognized for the security due to the limited severity and duration of the unrealized loss position. At December 31, 2010, no securities were in an unrealized loss position.

There were no sales of available-for-sale securities during the three and nine months endedSeptember 30, 2011 or 2010.

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COMMON STOCK: Level 4 (Details) (USD $) In Millions, except Share data, unless otherwise specified	9 Months Ended
	Sep. 30, 2011
Shareholders' equity [Line Items]
Aggregate shares of common stock issued pursuant to IDACORP's share plans	354,590
Available shares remaining under current sales agency agreement	1,200,000
Shares issued under sales agency agreement during the period	0
Maximum leverage ratio requirement	0.65
Leverage ratio	0.48
Amount dividends were limited to based on covenant restrictions	$ 827
Idaho Power Company
Shareholders' equity [Line Items]
Maximum leverage ratio requirement	0.65
Percentage of capital threshold below which Idaho Power will not pay dividends to IDACORP	0.35
Leverage ratio	0.50
Amount dividends were limited to based on covenant restrictions	$ 714
Shares of preferred stock outstanding	0

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BENEFIT PLANS: Level 3 (Tables)

3 Months Ended

9 Months Ended

Sep. 30, 2011

Sep. 30, 2011

Benefit plans [Abstract]

Schedule of Defined Benefit Plans Disclosures [Table Text Block]

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

	Pension Plan						Senior Management Security Plan				Postretirement Benefits
	2011			2010			2011		2010		2011			2010
Service cost	$	5,120		$	4,417		$	487	$	385	$	330		$	340
Interest cost	7,581			7,279			773		751		859			898
Expected return on plan assets	(7,968		)	(7,270		)	—		—		(660		)	(641		)
Amortization of transition obligation	—			—			—		—		510			510
Amortization of prior service cost	130			163			61		59		(105		)	(133		)
Amortization of net loss	2,168			1,918			323		232		144			143
Net periodic benefit cost	7,031			6,507			1,644		1,427		1,078			1,117
Costs not recognized due to the effects of regulation (1)	(2,371		)	(4,624		)	—		—		—			—
Net periodic benefit cost recognized for financial reporting (1)	$	4,660		$	1,883		$	1,644	$	1,427	$	1,078		$	1,117
(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.  See Note 3 – “Regulatory Matters” for information on Idaho Power’s 2011 Idaho pension rate order, which increased Idaho jurisdiction recovery to $17.1 million annually, effective June 1, 2011.

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

	Pension Plan						Senior Management Security Plan				Postretirement Benefits
	2011			2010			2011		2010		2011			2010
Service cost	$	15,359		$	13,253		$	1,463	$	1,156	$	992		$	1,020
Interest cost	22,742			21,839			2,319		2,253		2,576			2,693
Expected return on plan assets	(23,903		)	(19,847		)	—		—		(1,981		)	(1,921		)
Amortization of transition obligation	—			—			—		—		1,530			1,530
Amortization of prior service cost	389			488			183		175		(316		)	(401		)
Amortization of net loss	6,505			5,756			969		698		433			430
Net periodic benefit cost	21,092			21,489			4,934		4,282		3,234			3,351
Costs not recognized due to the effects of regulation (1)	(11,981		)	(18,650		)	—		—		—			—
Net periodic benefit cost recognized for financial reporting (1)	$	9,111		$	2,839		$	4,934	$	4,282	$	3,234		$	3,351
(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.  See Note 3 – “Regulatory Matters” for information on Idaho Power’s 2011 Idaho pension rate order, which increased Idaho-jurisdiction recovery to $17.1 million annually, effective June 1, 2011.

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Condensed Consolidated Statements of Cash Flows (USD $) In Thousands	9 Months Ended
	Sep. 30, 2011	Sep. 30, 2010
Operating Activities:
Net Income	$ 157,878	$ 122,219
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization	92,646	91,257
Deferred income taxes and investment tax credits	(54,340)	37,095
Changes in regulatory assets and liabilities	55,044	50,338
Pension and postretirement benefit plan expense	17,279	10,474
Contributions to pension and postretirement benefit plans	(20,194)	(64,269)
(Earnings) losses of unconsolidated equity-method investments	3,657	(1,444)
Distributions from unconsolidated equity-method investments	2,375	1,280
Allowance for equity funds used during construction	(18,264)	(11,878)
Other non-cash adjustments to net income, net	3,731	2,104
Change in:
Accounts receivable and prepayments	(12,121)	9,652
Accounts payable and other accrued liabilities	(2,209)	(5,786)
Taxes accrued/receivable	31,472	(34,799)
Other current assets	(24,556)	2,914
Other current liabilities	1,375	21,591
Other assets	4,595	(3,443)
Other liabilities	(3,458)	(4,776)
Net cash provided by operating activities	234,910	222,529
Investing Activities:
Additions to property, plant and equipment	(266,991)	(249,437)
Proceeds from the sale of utility assets	0	18,982
Proceeds from the sale of emission allowances and RECs	5,163	5,399
Investments in affordable housing	(955)	(9,337)
Other	2,435	3,826
Net cash used in investing activities	(260,348)	(230,567)
Financing Activities:
Issuance of long-term debt	0	200,000
Retirement of long-term debt	(121,064)	(1,064)
Dividends on common stock	(44,808)	(43,213)
Net change in short-term borrowings	(15,400)	(49,750)
Issuance of common stock	10,408	38,086
Acquisition of treasury stock	(1,933)	(846)
Other	872	(2,849)
Net cash (used in) provided by financing activities	(171,925)	140,364
Net (decrease) increase in cash and cash equivalents	(197,363)	132,326
Cash and cash equivalents at beginning of the period	228,677	52,987
Cash and cash equivalents at end of the period	31,314	185,313
Cash paid (received) during the period for:
Income taxes	(11,543)	836
Interest (net of amount capitalized)	52,505	47,356
Non-cash investing activities:
Additions to property, plant and equipment in accounts payable	22,715	21,551
Investments in affordable housing	0	1,509
Idaho Power Company
Operating Activities:
Net Income	155,420	121,700
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization	92,232	90,785
Deferred income taxes and investment tax credits	(56,078)	67,516
Changes in regulatory assets and liabilities	55,044	50,338
Pension and postretirement benefit plan expense	17,279	10,474
Contributions to pension and postretirement benefit plans	(20,194)	(64,269)
(Earnings) losses of unconsolidated equity-method investments	(1,172)	(7,738)
Distributions from unconsolidated equity-method investments	1,075	455
Allowance for equity funds used during construction	(18,264)	(11,878)
Other non-cash adjustments to net income, net	1,383	(729)
Change in:
Accounts receivable and prepayments	(12,213)	8,830
Accounts payable and other accrued liabilities	(2,120)	(5,652)
Taxes accrued/receivable	35,496	(80,853)
Other current assets	(24,556)	2,914
Other current liabilities	1,375	21,590
Other assets	4,595	(3,443)
Other liabilities	(2,702)	(4,206)
Net cash provided by operating activities	226,600	195,834
Investing Activities:
Additions to property, plant and equipment	(266,991)	(249,437)
Proceeds from the sale of utility assets	0	18,982
Proceeds from the sale of emission allowances and RECs	5,163	5,399
Other	1,820	3,274
Net cash used in investing activities	(260,008)	(221,782)
Financing Activities:
Issuance of long-term debt	0	200,000
Retirement of long-term debt	(121,064)	(1,064)
Dividends on common stock	(44,768)	(43,325)
Capital contribution from parent	0	30,000
Other	0	(2,746)
Net cash (used in) provided by financing activities	(165,832)	182,865
Net (decrease) increase in cash and cash equivalents	(199,240)	156,917
Cash and cash equivalents at beginning of the period	224,233	21,625
Cash and cash equivalents at end of the period	24,993	178,542
Cash paid (received) during the period for:
Income taxes	(6,689)	21,815
Interest (net of amount capitalized)	52,148	46,338
Non-cash investing activities:
Additions to property, plant and equipment in accounts payable	$ 22,715	$ 21,551

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DERIVATIVE FINANCIAL INSTRUMENTS:

3 Months Ended

Sep. 30, 2011

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.

The following tables present the fair values and locations of derivative instruments not designated as hedging instruments recorded on the balance sheets at September 30, 2011 and December 31, 2010 (in thousands of dollars):

	Asset Derivatives			Liability Derivatives
	Balance Sheet	Fair		Balance Sheet	Fair
	Location	Value		Location	Value
September 30, 2011
Current:
Financial swaps	Other current assets	$	4,192	Other current assets	$	900
Financial swaps	Other current liabilities	—		Other current liabilities	356
Forward contracts	Other current assets	80		Other current liabilities	406
Long-term:
Financial swaps	Other assets	559		Other assets	25
Financial swaps				Other liabilities	344
Total		$	4,831		$	2,031
December 31, 2010
Current:
Financial swaps	Other current assets	$	930	Other current assets	$	356
Financial swaps	Other current liabilities	2,440		Other current liabilities	4,172
Forward contracts				Other current liabilities	508
Long-term:
Financial swaps	Other liabilities	100		Other liabilities	138
Total		$	3,470		$	5,174

The following table presents the gains and losses on derivatives not designated as hedging instruments for the three and nine months endedSeptember 30, 2011 and 2010 (in thousands of dollars):

	Location of Gain/(Loss)	Gain/(Loss)
	on Derivatives	on Derivatives
Commodity Derivatives	Recognized in Income	Recognized in Income(1)
Three months ended September 30, 2011:
Financial swaps	Off-system sales	$	441
Financial swaps	Purchased power	(6,982		)
Financial swaps	Fuel expense	115
Financial swaps	Other operations and maintenance	120
Three months ended September 30, 2010:
Financial swaps	Off-system sales	$	2,332
Financial swaps	Purchased power	(6,749		)
Financial swaps	Fuel expense	(101		)
Forward contracts	Fuel expense	(721		)
Nine months ended September 30, 2011:
Financial swaps	Off-system sales	$	6,947
Financial swaps	Purchased power	(6,954		)
Financial swaps	Fuel expense	501
Financial swaps	Other operations and maintenance	347
Nine months ended September 30, 2010:
Financial swaps	Off-system sales	$	3,284
Financial swaps	Purchased power	(9,135		)
Financial swaps	Fuel expense	(101		)
Forward contracts	Fuel expense	(721		)
(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 - “Fair Value Measurements” for additional information concerning the determination of fair value for Idaho Power’s assets and liabilities from price risk management activities.

Idaho Power had the following volumes of derivative commodity forward contracts and swaps outstanding at September 30, 2011 and 2010:

		September 30,
Commodity	Units	2011	2010
Electricity purchases	MWh	197,800	443,250
Electricity sales	MWh	1,038,095	237,000
Natural gas purchases	MMBtu	2,292,738	325,500
Natural gas sales	MMBtu	77,500	—
Diesel purchases	Gallons	266,375	208,980

Credit Risk

At September 30, 2011, Idaho Power did not have material credit exposure from financial instruments, including derivatives.  Idaho Power monitors credit risk exposure through reviews of counterparty credit quality, corporate-wide counterparty credit exposure, and corporate-wide counterparty concentration levels.  Idaho Power manages these risks by establishing appropriate credit and concentration limits on transactions with counterparties and requiring contractual guarantees, cash deposits, or letters of credit from counterparties or their affiliates, as deemed necessary.  Idaho Power’s physical power contracts are under Western Systems Power Pool agreements, physical gas contracts are under North American Energy Standards Board contracts, and financial transactions are under International Swaps and Derivatives Association, Inc. contracts. These contracts all contain adequate assurance clauses requiring collateralization if a counterparty has debt that is downgraded below investment grade by at least one rating agency. 

Credit-Contingent Features

Certain of Idaho Power's derivative instruments contain provisions that require Idaho Power's unsecured debt to maintain an investment grade credit rating from Moody's Investors Service and Standard & Poor's Ratings Services.  If Idaho Power's unsecured debt were to fall below investment grade, it would be in violation of these provisions, and the counterparties to the derivative instruments could request immediate payment or demand immediate and ongoing full overnight collateralization on derivative instruments in net liability positions.  The aggregate fair value of all derivative instruments with credit-risk-related contingent features that were in a liability position at September 30, 2011, was $2.0 million.  Idaho Power posted $1.6 million of collateral related to this amount.  If the credit-risk-related contingent features underlying these agreements were triggered on September 30, 2011, Idaho Power would have been required to post $0.9 million of additional cash collateral to its counterparties.

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INVESTMENTS IN DEBT AND EQUITY SECURITIES: Level 4 (Details) (USD $)	3 Months Ended		9 Months Ended
	Sep. 30, 2011	Sep. 30, 2010	Sep. 30, 2011	Sep. 30, 2010	Dec. 31, 2010
Summary of investments in debt and equity securities
Available-for-sale Securities, Gross Unrealized Gain	$ 2,612,000		$ 2,612,000		$ 4,876,000
Available-for-sale Securities, Gross Unrealized Loss	37,000		37,000		0
Available-for-sale Securities, Fair Value	21,346,000		21,346,000		24,561,000
Number of securities in an unrealized loss position (whole numbers)	1		1		0
Proceeds from sales	0	0	0	0
Available-for-sale Securities, Continuous Unrealized Loss Position, Less than 12 Months, Aggregate Losses	37,000		37,000
Available-for-sale Securities, Continuous Unrealized Loss Position, Less than Twelve Months, Fair Value	1,222,000		1,222,000
Available-for-sale Securities, Continuous Unrealized Loss Position, 12 Months or Longer, Aggregate Losses	0		0
Available-for-sale Securities, Continuous Unrealized Loss Position, Twelve Months or Longer, Fair Value	0		0
Other than Temporary Impairment Recognized	$ 0

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SEGMENT INFORMATION:

3 Months Ended

Sep. 30, 2011

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

	Utility Operations		All Other		Eliminations			Consolidated Total
Three months ended September 30, 2011:
Revenues	$	308,045	$	1,585	$	—		$	309,630
Net income attributable to IDACORP, Inc.	104,872		2,195		—			107,067
Total assets as of September 30, 2011	4,719,173		124,273		(16,511		)	4,826,935
Three months ended September 30, 2010:
Revenues	$	308,468	$	889	$	—		$	309,357
Net income attributable to IDACORP, Inc.	64,650		2,485		—			67,135
Nine months ended September 30, 2011:
Revenues	$	793,031	$	3,076	$	—		$	796,107
Net income attributable to IDACORP, Inc.	155,420		2,288		—			157,708
Nine months ended September 30, 2010:
Revenues	$	801,719	$	2,354	$	—		$	804,073
Net income attributable to IDACORP, Inc.	121,700		707		—			122,407

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Condensed Consolidated Statements of Comprehensive Income (Parenthetical) (USD $) In Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2011	Sep. 30, 2010	Sep. 30, 2011	Sep. 30, 2010
Net unrealized holding gains (losses) arising during the period, tax	$ (1,259)	$ 632	$ (900)	$ 140
Unfunded pension liability adjustment, tax	150	114	450	341
Idaho Power Company
Net unrealized holding gains (losses) arising during the period, tax	(1,259)	632	(900)	140
Unfunded pension liability adjustment, tax	$ 150	$ 114	$ 450	$ 341

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COMMON STOCK:

3 Months Ended

Sep. 30, 2011

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

Common Stock

COMMON STOCK

IDACORP Common Stock

During the nine months endedSeptember 30, 2011, IDACORP issued an aggregate of 354,590 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, which expires in November 2011, is with BNY Mellon Capital Markets, LLC. As of September 30, 2011, there were approximately 1.2 million shares remaining available to be sold under the current sales agency agreement. No shares were issued under the sales agency agreement during the nine months endedSeptember 30, 2011.

Restrictions on Dividends

A covenant under IDACORP’s credit facility and Idaho Power’s credit facility requires IDACORP and Idaho Power to maintain leverage ratios of consolidated indebtedness to consolidated total capitalization, as defined therein, of no more than 65 percent at the end of each fiscal quarter. Idaho Power’s 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 September 30, 2011, the leverage ratios for IDACORP and Idaho Power were 48 percent and 50 percent, respectively.  Based on these restrictions, IDACORP’s and Idaho Power’s dividends were limited to $827 million and $714 million, respectively, at September 30, 2011.  There are additional facility covenants, subject to exceptions, that prohibit or restrict specified investments or acquisitions, mergers, or the sale or disposition of property without consent; the creation of specified forms of liens; and any agreements restricting dividend payments to the company from any material subsidiary.  At September 30, 2011, 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.

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
	Sep. 30, 2011
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	16
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	91
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	$ 66

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BENEFIT PLANS:

3 Months Ended

Sep. 30, 2011

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

	Pension Plan						Senior Management Security Plan				Postretirement Benefits
	2011			2010			2011		2010		2011			2010
Service cost	$	5,120		$	4,417		$	487	$	385	$	330		$	340
Interest cost	7,581			7,279			773		751		859			898
Expected return on plan assets	(7,968		)	(7,270		)	—		—		(660		)	(641		)
Amortization of transition obligation	—			—			—		—		510			510
Amortization of prior service cost	130			163			61		59		(105		)	(133		)
Amortization of net loss	2,168			1,918			323		232		144			143
Net periodic benefit cost	7,031			6,507			1,644		1,427		1,078			1,117
Costs not recognized due to the effects of regulation (1)	(2,371		)	(4,624		)	—		—		—			—
Net periodic benefit cost recognized for financial reporting (1)	$	4,660		$	1,883		$	1,644	$	1,427	$	1,078		$	1,117
(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.  See Note 3 – “Regulatory Matters” for information on Idaho Power’s 2011 Idaho pension rate order, which increased Idaho jurisdiction recovery to $17.1 million annually, effective June 1, 2011.

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

	Pension Plan						Senior Management Security Plan				Postretirement Benefits
	2011			2010			2011		2010		2011			2010
Service cost	$	15,359		$	13,253		$	1,463	$	1,156	$	992		$	1,020
Interest cost	22,742			21,839			2,319		2,253		2,576			2,693
Expected return on plan assets	(23,903		)	(19,847		)	—		—		(1,981		)	(1,921		)
Amortization of transition obligation	—			—			—		—		1,530			1,530
Amortization of prior service cost	389			488			183		175		(316		)	(401		)
Amortization of net loss	6,505			5,756			969		698		433			430
Net periodic benefit cost	21,092			21,489			4,934		4,282		3,234			3,351
Costs not recognized due to the effects of regulation (1)	(11,981		)	(18,650		)	—		—		—			—
Net periodic benefit cost recognized for financial reporting (1)	$	9,111		$	2,839		$	4,934	$	4,282	$	3,234		$	3,351
(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.  See Note 3 – “Regulatory Matters” for information on Idaho Power’s 2011 Idaho pension rate order, which increased Idaho-jurisdiction recovery to $17.1 million annually, effective June 1, 2011.

In September 2011, Idaho Power contributed $18.5 million to its pension plan. The contribution was in excess of the $6 million minimum contribution requirement for the 2011 calendar year. Idaho Power elected to contribute more than the minimum requirement in order to bring the pension plan to a more funded position, to reduce future required contributions, and to reduce Pension Benefit Guaranty Corporation premiums.

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Condensed Consolidated Statements of Income Statement (USD $) In Thousands, except Per Share data	3 Months Ended		9 Months Ended
	Sep. 30, 2011	Sep. 30, 2010	Sep. 30, 2011	Sep. 30, 2010
Operating Revenues:
General business	$ 252,313	$ 266,270	$ 649,881	$ 674,293
Off-system sales	24,083	12,070	74,648	64,245
Other revenues	31,649	30,128	68,502	63,181
Total electric utility revenues	308,045	308,468	793,031	801,719
Other	1,585	889	3,076	2,354
Total operating revenues	309,630	309,357	796,107	804,073
Operating Expenses:
Purchased power	66,141	62,227	127,658	113,750
Fuel expense	41,195	51,339	90,801	116,083
Power cost adjustment	(10,189)	(20,934)	36,618	55,461
Other operations and maintenance	84,562	71,939	240,695	219,159
Energy efficiency programs	18,504	19,549	31,011	33,348
Depreciation	30,115	29,137	89,272	86,446
Taxes other than income taxes	7,302	5,645	21,696	17,130
Total electric utility expenses	237,630	218,902	637,751	641,377
Other	607	1,462	2,573	3,051
Total operating expenses	238,237	220,364	640,324	644,428
Operating Income	71,393	88,993	155,783	159,645
Other Income (Expense):
Other (expense) income, net	6,010	3,550	15,589	11,042
Earnings (Losses) of Unconsolidated Equity-Method Investments	2,085	3,442	(3,657)	1,444
Interest Expense:
Interest on long-term debt	19,499	20,135	59,850	59,003
Other interest, net of AFUDC	(2,053)	(1,390)	(5,876)	(3,881)
Total interest expense, net	17,446	18,745	53,974	55,122
Income Before Income Taxes	62,042	77,240	113,741	117,009
Income Tax (Benefit) Expense	(45,372)	10,115	(44,137)	(5,210)
Net Income	107,414	67,125	157,878	122,219
Adjustment for (income) loss attributable to noncontrolling interests	(347)	10	(170)	188
Net Income Attributable to IDACORP, Inc.	107,067	67,135	157,708	122,407
Weighted Average Common Shares Outstanding - Basic (000’s)	49,520	48,086	49,411	47,917
Weighted Average Common Shares Outstanding - Diluted (000’s)	49,622	48,252	49,499	48,062
Earnings Per Share of Common Stock:
Earnings Attributable to IDACORP, Inc. - Basic	$ 2.16	$ 1.40	$ 3.19	$ 2.55
Earnings Attributable to IDACORP, Inc. - Diluted	$ 2.16	$ 1.39	$ 3.19	$ 2.55
Dividends Declared Per Share of Common Stock	$ 0.30	$ 0.30	$ 0.90	$ 0.90
Idaho Power Company
Operating Revenues:
General business	252,313	266,270	649,881	674,293
Off-system sales	24,083	12,070	74,648	64,245
Other revenues	31,649	30,128	68,502	63,181
Total electric utility revenues	308,045	308,468	793,031	801,719
Operating Expenses:
Purchased power	66,141	62,227	127,658	113,750
Fuel expense	41,195	51,339	90,801	116,083
Power cost adjustment	(10,189)	(20,934)	36,618	55,461
Other operations and maintenance	84,562	71,939	240,695	219,159
Energy efficiency programs	18,504	19,549	31,011	33,348
Depreciation	30,115	29,137	89,272	86,446
Taxes other than income taxes	7,302	5,645	21,696	17,130
Total electric utility expenses	237,630	218,902	637,751	641,377
Operating Income	70,415	89,566	155,280	160,342
Other Income (Expense):
Allowance for equity funds used during construction	6,570	3,858	18,264	11,878
Other (expense) income, net	(293)	(766)	(2,669)	(1,937)
Earnings (Losses) of Unconsolidated Equity-Method Investments	3,741	5,402	1,172	7,738
Total other income	10,018	8,494	16,767	17,679
Interest Expense:
Interest on long-term debt	19,499	20,135	59,850	59,003
Other interest	1,026	852	3,551	2,883
Allowance for borrowed funds used during construction	(3,188)	(2,303)	(9,777)	(7,781)
Total interest expense, net	17,337	18,684	53,624	54,105
Income Before Income Taxes	63,096	79,376	118,423	123,916
Income Tax (Benefit) Expense	(41,776)	14,726	(36,997)	2,216
Net Income	$ 104,872	$ 64,650	$ 155,420	$ 121,700

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REGULATORY MATTERS: Level 4 (Details) (USD $)									12 Months Ended
	Sep. 23, 2011 Current Rate Case Idaho	Jun. 01, 2011 Current Rate Case Idaho	Nov. 02, 2011 Settlement Agreement and Sharing Mechanism	Sep. 30, 2011 Settlement Agreement and Sharing Mechanism	Jan. 13, 2010 Settlement Agreement and Sharing Mechanism	Sep. 30, 2011 Idaho Power Cost Adjustment	May 31, 2011 Idaho Load Change Adjustment	Sep. 30, 2011 Idaho Fixed Cost Adjustment	Dec. 31, 2010 Idaho Pension Recovery	Sep. 30, 2011 Idaho Pension Recovery	Sep. 30, 2011 Energy Efficiency and Demand Response Programs	Sep. 30, 2011 Transmission Rate Refunds and Shortfall Filing	Sep. 30, 2011 Current Rate Case Oregon	Oct. 20, 2011 Oregon Power Cost Adjustment	Sep. 30, 2011 Oregon Power Cost Adjustment	Sep. 30, 2011 Oregon Open Access Same Time Information System	Jun. 30, 2011 Oregon Open Access Same Time Information System
Rate Case
Increase (Decrease) in Rates	$ 34,000,000	$ 82,600,000				$ (40,400,000)		$ 3,000,000		$ 17,100,000	$ 42,000,000	$ 13,300,000	$ 5,800,000	$ 1,400,000	$ (900,000)	$ 107,000,000
Percentage Increase (Decrease) in Rates	4.07%	9.90%											14.70%
Authorized Return on Equity in Rate Case, Minimum		10.50%	9.50%		9.50%								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
Authorized Return on Equity in Rate Case, Maximum			10.00%		10.50%
Regulatory Liabilities				18,100,000
Percentage to be Shared with Customers			50.00%		50.00%
Authorized Rate of Return in Rate Case	7.86%	8.17%											8.17%
Total Retail Rate Base	2,400,000,000												121,900,000
Load Change Adjustment Rate or Open Access Same Time Draft Rate	18.16	19.28					19.67									19.79	19.60
Demand Response Incentive Payments Included in Rate Filing	11,300,000					10,000,000
Power Purchased from PURPA Projects Included in Rate Case	23,000,000
Defined Benefit Plan, Contributions by Employer									60,000,000
Existing Interest Rate on Energy Efficiency Rider Balance											1.00%
Regulatory Assets										5,400,000		4,700,000
Base Deferral Amount to be Collected												$ 2,100,000

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DERIVATIVE FINANCIAL INSTRUMENTS: Level 4 (Details) (USD $)																				3 Months Ended		9 Months Ended		3 Months Ended		9 Months Ended		3 Months Ended		9 Months Ended		3 Months Ended	9 Months Ended				3 Months Ended	9 Months Ended
	Sep. 30, 2011	Dec. 31, 2010	Sep. 30, 2011 Electricity purchases	Sep. 30, 2010 Electricity purchases	Sep. 30, 2011 Electricity sales	Sep. 30, 2010 Electricity sales	Sep. 30, 2011 Natural gas purchases	Sep. 30, 2010 Natural gas purchases	Sep. 30, 2011 Natural gas sales	Sep. 30, 2010 Natural gas sales	Sep. 30, 2011 Diesel purchases	Sep. 30, 2010 Diesel purchases	Sep. 30, 2011 Financial swaps Other current assets	Dec. 31, 2010 Financial swaps Other current assets	Sep. 30, 2011 Financial swaps Other current liabilities	Dec. 31, 2010 Financial swaps Other current liabilities	Sep. 30, 2011 Financial swaps Other liabilities	Dec. 31, 2010 Financial swaps Other liabilities	Sep. 30, 2011 Financial swaps Other assets	Sep. 30, 2011 Financial swaps Off-system sales	Sep. 30, 2010 Financial swaps Off-system sales	Sep. 30, 2011 Financial swaps Off-system sales	Sep. 30, 2010 Financial swaps Off-system sales	Sep. 30, 2011 Financial swaps Purchased power	Sep. 30, 2010 Financial swaps Purchased power	Sep. 30, 2011 Financial swaps Purchased power	Sep. 30, 2010 Financial swaps Purchased power	Sep. 30, 2011 Financial swaps Fuel Expense	Sep. 30, 2010 Financial swaps Fuel Expense	Sep. 30, 2011 Financial swaps Fuel Expense	Sep. 30, 2010 Financial swaps Fuel Expense	Sep. 30, 2011 Financial swaps Other operating and maintenance	Sep. 30, 2011 Financial swaps Other operating and maintenance	Sep. 30, 2011 Forward contracts Other current assets	Sep. 30, 2011 Forward contracts Other current liabilities	Dec. 31, 2010 Forward contracts Other current liabilities	Sep. 30, 2010 Forward contracts Fuel Expense	Sep. 30, 2010 Forward contracts Fuel Expense
Derivative
Derivative, Nonmonetary Notional Amount			197,800	443,250	1,038,095	237,000	2,292,738	325,500	77,500	0	266,375	208,980
Fair Value
Derivative Asset, Fair Value, Gross Asset													$ 4,192,000	$ 930,000					$ 559,000															$ 80,000
Derivative Asset, Fair Value, Gross Liability															0	2,440,000		100,000
Derivative Asset, Fair Value, Net	4,831,000	3,470,000
Derivative Liability, Fair Value, Gross Asset													900,000	356,000					25,000
Derivative Liability, Fair Value, Gross Liability															356,000	4,172,000	344,000	138,000																	406,000	508,000
Derivative Liability, Fair Value, Net	2,031,000	5,174,000
Derivatives in a net liability position	2,000,000
Collateral Already Posted, Aggregate Fair Value	1,600,000
Additional Collateral, Aggregate Fair Value	900,000
Derivative Instruments, Gain (Loss)
Derivative Instruments, Gain Recognized in Income																				441,000	2,332,000	6,947,000	3,284,000					115,000		501,000		120,000	347,000
Derivative Instruments, Loss Recognized in Income																								$ (6,982,000)	$ (6,749,000)	$ (6,954,000)	$ (9,135,000)		$ (101,000)		$ (101,000)						$ (721,000)	$ (721,000)

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FAIR VALUE MEASUREMENTS: Level 4 (Details) (USD $) In Thousands	Sep. 30, 2011	Dec. 31, 2010
Fair Value Disclosures
Asset derivatives	$ 3,906	$ 573
Money market funds	100	151,975
Trading securities: Equity securities	3,239	5,361
Available-for-sale securities: Equity securities	21,346	24,561
Liability derivatives	1,107	508
Idaho Power Company | Carrying Amount
Fair Value Disclosures
Long-term debt	1,491,727	1,612,790
Carrying Amount
Fair Value Disclosures
Notes receivable	2,946	2,946
Long-term debt	1,492,330	1,614,299
Idaho Power Company | Estimated Fair Value
Fair Value Disclosures
Long-term debt	1,729,022	1,621,425
Estimated Fair Value
Fair Value Disclosures
Notes receivable	2,946	2,946
Long-term debt	1,729,623	1,622,924
Idaho Power Company
Fair Value Disclosures
Asset derivatives	3,906	573
Money market funds	100	151,173
Trading securities: Equity securities	3,239	4,746
Available-for-sale securities: Equity securities	21,346	24,561
Liability derivatives	1,107	508
Idaho Power Company | Quoted Prices in Active Markets for Identical Assets (Level 1)
Fair Value Disclosures
Asset derivatives	3,826	573
Money market funds	100	151,173
Trading securities: Equity securities	3,239	4,746
Available-for-sale securities: Equity securities	21,346	24,561
Liability derivatives	130	0
Idaho Power Company | Significant Other Observable Inputs (Level 2)
Fair Value Disclosures
Asset derivatives	80	0
Money market funds	0	0
Trading securities: Equity securities	0	0
Available-for-sale securities: Equity securities	0	0
Liability derivatives	977	508
Idaho Power Company | 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
Quoted Prices in Active Markets for Identical Assets (Level 1)
Fair Value Disclosures
Asset derivatives	3,826	573
Money market funds	100	151,975
Trading securities: Equity securities	3,239	5,361
Available-for-sale securities: Equity securities	21,346	24,561
Liability derivatives	130	0
Significant Other Observable Inputs (Level 2)
Fair Value Disclosures
Asset derivatives	80	0
Money market funds	0	0
Trading securities: Equity securities	0	0
Available-for-sale securities: Equity securities	0	0
Liability derivatives	977	508
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

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LONG-TERM DEBT: Level 4 (Details) (USD $) In Millions	3 Months Ended
	Sep. 30, 2011
Parent Company [Member]
Debt Instrument [Line Items]
Amount remaining on self registration	$ 539
Idaho Power Company
Debt Instrument [Line Items]
Amount of first mortgage bonds and debt securities registered with the SEC	500
Amount remaining on self registration	300
First mortgage bonds repaid at maturity during the period	$ 120