IDACORP INC - Quarter Report: 2010 September (Form 10-Q)

audit draft 10-22.docx

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, 2010
	OR
	TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
	EXCHANGE ACT OF 1934
	For the transition period from __________ to __________
		Exact name of registrants as specified	I.R.S. Employer
Commission File		in their charters, address of principal	Identification
Number		executive offices, zip code and telephone number	Number
1-14465		IDACORP, Inc.	82-0505802
1-3198		Idaho Power Company	82-0130980
		1221 W. Idaho Street
		Boise, ID 83702-5627
		(208) 388-2200
		State of Incorporation: Idaho
		Websites: www.idacorpinc.com, www.idahopower.com
		None
Former name, former address and former fiscal year, if changed since last report.

Indicate by check mark whether the registrants (1) have filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrants were required to file such reports), and (2) have been subject to such filing requirements for the past 90 days. Yes X No ___

Indicate by check mark whether the registrants have submitted electronically and posted on their corporate Web sites, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrants were required to submit and post such files). IDACORP, Inc.: Yes X No ___ Idaho Power Company: Yes ___ No ___

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

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

Indicate by check mark whether the registrants are shell companies (as defined in Rule 12b-2 of the Exchange Act).

Yes ___ No X

Number of shares of common stock outstanding as of October 20, 2010:
IDACORP, Inc.:	49,116,468
Idaho Power Company:	39,150,812, all held by IDACORP, Inc.

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

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

COMMONLY USED TERMS

ADITC	-	Accumulated Deferred Investment Tax Credits
AFUDC	-	Allowance for Funds Used During Construction
APCU	-	Annual Power Cost Update
ARRA	-	American Recovery and Reinvestment Act of 2009
BCC	-	Bridger Coal Company, a joint venture of IERCo
BLM	-	United States Bureau of Land Management
CAA	-	Clean Air Act
Cal ISO	-	California Independent System Operator
CalPX	-	California Power Exchange
CAMP	-	Comprehensive Aquifer Management Plan
CO₂	-	Carbon Dioxide
EIS	-	Environmental Impact Statement
EPA	-	United States Environmental Protection Agency
EPS	-	Earnings per share
ESA	-	Endangered Species Act
ESPA	-	Eastern Snake Plain Aquifer
FCA	-	Fixed Cost Adjustment mechanism
FERC	-	Federal Energy Regulatory Commission
GHG	-	Greenhouse gas
HCC	-	Hells Canyon Complex
Ida-West	-	Ida-West Energy, a subsidiary of IDACORP, Inc.
IE	-	IDACORP Energy, a subsidiary of IDACORP, Inc.
IERCo	-	Idaho Energy Resources Co., a subsidiary of Idaho Power Company
IFS	-	IDACORP Financial Services, a subsidiary of IDACORP, Inc.
IPUC	-	Idaho Public Utilities Commission
IRP	-	Integrated Resource Plan
IRS	-	Internal Revenue Service
IWRB	-	Idaho Water Resource Board
kW	-	Kilowatt
LTICP	-	Long-term Incentive and Compensation Plan
MD&A	-	Management’s Discussion and Analysis of Financial Condition and Results of Operations
MW	-	Megawatt
MWh	-	Megawatt-hour
NOx	-	Nitrogen Oxide
O&M	-	Operations and Maintenance
OATT	-	Open Access Transmission Tariff
OPUC	-	Oregon Public Utility Commission
PCA	-	Power Cost Adjustment
PCAM	-	Power Cost Adjustment Mechanism
PURPA	-	Public Utility Regulatory Policies Act of 1978
REC	-	Renewable Energy Certificate
RES	-	Renewable Energy Standard
RH BART	-	Regional Haze - Best Available Retrofit Technology
RPS	-	Renewable Portfolio Standards
SEC	-	Securities and Exchange Commission
SO₂	-	Sulfur Dioxide
SRBA	-	Snake River Basin Adjudication
USBR	-	United States Bureau of Reclamation
Valmy	-	North Valmy Steam Electric Generating Plant
VIEs	-	Variable Interest Entities
WECC	-	Western Electricity Coordinating Council

TABLE OF CONTENTS
				Page
Part I. Financial Information:

	Item 1. Financial Statements (unaudited)
		IDACORP, Inc.:
			Condensed Consolidated Statements of Income	4
			Condensed Consolidated Balance Sheets	5-6
			Condensed Consolidated Statements of Cash Flows	7
			Condensed Consolidated Statements of Comprehensive Income	8
			Condensed Consolidated Statements of Equity	9
		Idaho Power Company:
			Condensed Consolidated Statements of Income	10
			Condensed Consolidated Balance Sheets	11-12
			Condensed Consolidated Statements of Capitalization	13
			Condensed Consolidated Statements of Cash Flows	14
			Condensed Consolidated Statements of Comprehensive Income	15
		Notes to the Condensed Consolidated Financial Statements		16-37
		Reports of Independent Registered Public Accounting Firm		38-39

	Item 2. Management’s Discussion and Analysis of Financial Condition and Results of
			Operations	40-84

	Item 3. Quantitative and Qualitative Disclosures About Market Risk			84-85

	Item 4. Controls and Procedures			85

Part II. Other Information:

	Item 1. Legal Proceedings			85

	Item 1A. Risk Factors			85

	Item 2. Unregistered Sales of Equity Securities and Use of Proceeds			85

	Item 5. Other Information			85-86

	Item 6. Exhibits			88

Signatures				89

Exhibit Index				90

SAFE HARBOR STATEMENT

This report on Form 10-Q contains “forward-looking statements” intended to qualify for the safe harbor from liability established by the Private Securities Litigation Reform Act of 1995. Forward-looking statements should be read with the cautionary statements and important factors included in this Form 10-Q at Part I, Item 2 – “MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS - FORWARD-LOOKING INFORMATION,” and in IDACORP, Inc.’s and Idaho Power Company’s Annual Report on Form 10-K for the year ended December 31, 2009, at Part I, Item 1A – “RISK FACTORS,” as supplemented by the factors included in IDACORP, Inc.’s and Idaho Power Company’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2010 at Part II, Item 1A – “RISK FACTORS.” Forward-looking statements are all statements other than statements of historical fact, including, without limitation, those that are identified by the use of the words “anticipates,” “believes,” “estimates,” “expects,” “intends,” “plans,” “predicts,” “projects,” “may result,” “may continue,” or similar expressions.

PART I – FINANCIAL INFORMATION

Item 1. Financial Statements

IDACORP, Inc.

Condensed Consolidated Statements of Income

(unaudited)

	Three months ended				Nine months ended
	September 30,				September 30,
	2010		2009		2010		2009
	(thousands of dollars except for per share amounts)
Operating Revenues:
Electric utility:
General business	$	266,270	$	277,676	$	674,293	$	663,818
Off-system sales	12,070		23,691		64,245		78,888
Other revenues	30,128		21,761		63,181		50,969
Total electric utility revenues	308,468		323,128		801,719		793,675
Other	889		1,381		2,354		3,042
Total operating revenues	309,357		324,509		804,073		796,717
Operating Expenses:
Electric utility:
Purchased power	62,227		76,274		113,750		136,843
Fuel expense	51,339		49,530		116,083		113,138
Power cost adjustment	(20,934)		1,614		55,461		44,236
Other operations and maintenance	71,939		68,970		219,159		212,103
Energy efficiency programs	19,549		12,202		33,348		24,933
Depreciation	29,137		28,837		86,446		81,631
Taxes other than income taxes	5,645		5,600		17,130		15,749
Total electric utility expenses	218,902		243,027		641,377		628,633
Other expense	1,462		1,879		3,051		3,374
Total operating expenses	220,364		244,906		644,428		632,007
Operating Income	88,993		79,603		159,645		164,710
Other Income, Net	3,550		4,569		11,042		15,548
Earnings of Unconsolidated Equity-Method Investments	3,442		2,866		1,444		648
Interest Expense:
Interest on long-term debt	20,135		18,840		59,003		53,762
Other interest expense, net of AFUDC	(1,390)		(239)		(3,881)		481
Total interest expense, net	18,745		18,601		55,122		54,243
Income Before Income Taxes	77,240		68,437		117,009		126,663
Income Tax Expense (Benefit)	10,115		13,730		(5,210)		25,700
Net Income	67,125		54,707		122,219		100,963
Adjustment for loss (income) attributable to noncontrolling interests	10		(229)		188		(126)
Net Income Attributable to IDACORP, Inc.	$	67,135	$	54,478	$	122,407	$	100,837
Weighted Average Common Shares Outstanding - Basic (000’s)	48,086		47,068		47,917		46,953
Weighted Average Common Shares Outstanding - Diluted (000’s)	48,252		47,141		48,062		46,999
Earnings Per Share of Common Stock:
Earnings Attributable to IDACORP, Inc. - Basic	$	1.40	$	1.16	$	2.55	$	2.15
Earnings Attributable to IDACORP, Inc. - Diluted	$	1.39	$	1.16	$	2.55	$	2.15
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,		December 31,
	2010		2009
Assets	(thousands of dollars)

Current Assets:
Cash and cash equivalents	$	185,313	$	52,987
Receivables:
Customer (net of allowance of $1,507 and $1,805, respectively)	69,263		74,987
Other (net of allowance of $1,436 and $1,073, respectively)	6,405		11,922
Income taxes receivable	37,758		-
Accrued unbilled revenues	46,663		51,272
Materials and supplies (at average cost)	45,331		48,054
Fuel stock (at average cost)	30,052		25,634
Prepayments	9,983		11,111
Deferred income taxes	31,219		31,773
Other	5,901		2,666
Total current assets	467,888		310,406

Investments	198,928		195,298

Property, Plant and Equipment:
Utility plant in service	4,291,987		4,160,178
Accumulated provision for depreciation	(1,602,268)		(1,558,538)
Utility plant in service - net	2,689,719		2,601,640
Construction work in progress	370,950		289,188
Utility plant held for future use	7,082		7,151
Other property, net of accumulated depreciation	19,428		19,029
Property, plant and equipment - net	3,087,179		2,917,008

Other Assets:
American Falls and Milner water rights	22,381		24,226
Company-owned life insurance	26,646		26,654
Regulatory assets	724,977		720,401
Long-term receivables (net of allowance of $1,861 and $2,157, respectively)	3,993		4,217
Other	42,401		40,517
Total other assets	820,398		816,015

Total	$	4,574,393	$	4,238,727

The accompanying notes are an integral part of these statements.

IDACORP, Inc.

Condensed Consolidated Balance Sheets

(unaudited)

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

Current Liabilities:
Current maturities of long-term debt	$	126,615	$	9,340
Notes payable	4,000		53,750
Accounts payable	80,892		83,818
Income taxes accrued	-		3,502
Interest accrued	26,250		20,056
Uncertain tax positions	75,136		1,138
Other	69,557		46,625
Total current liabilities	382,450		218,229

Other Liabilities:
Deferred income taxes	582,808		574,450
Regulatory liabilities	296,861		287,780
Other	302,801		346,994
Total other liabilities	1,182,470		1,209,224

Long-Term Debt	1,488,205		1,409,730

Commitments and Contingencies

Equity:
IDACORP, Inc. shareholders’ equity:
Common stock, no par value (shares authorized 120,000,000;
49,124,529 and 47,925,882 shares issued, respectively)	796,515		756,475
Retained earnings	728,266		649,180
Accumulated other comprehensive loss	(7,517)		(8,267)
Treasury stock (10,012 and 29,191 shares at cost, respectively)	(17)		(53)
Total IDACORP, Inc. shareholders’ equity	1,517,247		1,397,335
Noncontrolling interest	4,021		4,209
Total equity	1,521,268		1,401,544

Total	$	4,574,393	$	4,238,727

The accompanying notes are an integral part of these statements.

IDACORP, Inc.

Condensed Consolidated Statements of Cash Flows

(unaudited)

	Nine months ended
	September 30,
	2010		2009
Operating Activities:	(thousands of dollars)
Net income	$	122,219	$	100,963
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization	91,257		86,485
Deferred income taxes and investment tax credits	37,095		14,797
Changes in regulatory assets and liabilities	50,338		37,721
Pension and postretirement benefit plan expense	10,474		7,756
Contributions to pension and postretirement benefit plans	(64,269)		(4,680)
Earnings of unconsolidated equity-method investments	(1,444)		(648)
Distributions from unconsolidated equity-method investments	1,280		9,415
Allowance for other funds used during construction	(11,878)		(4,629)
Other non-cash adjustments to net income, net	2,104		3,448
Change in:
Accounts receivable and prepayments	9,652		(22,065)
Accounts payable and other accrued liabilities	(5,786)		(24,636)
Taxes accrued/receivable	(34,799)		38,812
Other current assets	2,914		(11,817)
Other current liabilities	21,591		5,850
Other assets	(3,443)		678
Other liabilities	(4,776)		(14,924)
Net cash provided by operating activities	222,529		222,526
Investing Activities:
Additions to property, plant and equipment	(249,437)		(155,591)
Proceeds from the sale of utility assets	18,982		-
Proceeds from the sale of non-utility assets	-		2,250
Investments in affordable housing	(9,337)		(6,176)
Proceeds from the sale of emission allowances and RECs	5,399		2,382
Proceeds from the sale of available-for-sale securities	-		8,956
Other	3,826		683
Net cash used in investing activities	(230,567)		(147,496)
Financing Activities:
Issuance of long-term debt	200,000		100,000
Remarketing of pollution control revenue bonds	-		166,100
Decrease in term loans	-		(170,000)
Retirement of long-term debt	(1,064)		(9,174)
Dividends on common stock	(43,213)		(42,414)
Net change in short-term borrowings	(49,750)		(110,570)
Issuance of common stock	38,086		16,738
Acquisition of treasury stock	(846)		(1,441)
Other	(2,849)		(4,228)
Net cash provided by (used in) financing activities	140,364		(54,989)
Net increase in cash and cash equivalents	132,326		20,041
Cash and cash equivalents at beginning of the period	52,987		8,828
Cash and cash equivalents at end of the period	$	185,313	$	28,869
Supplemental Disclosure of Cash Flow Information:
Cash paid (received) during the period for:
Income taxes	$	836	$	(21,356)
Interest (net of amount capitalized)	$	47,356	$	41,227
Non-cash investing activities
Additions to property, plant and equipment in accounts payable	$	21,551	$	19,990
Investments in affordable housing	$	1,509	$	6,000
The accompanying notes are an integral part of these statements.

IDACORP, Inc.

Condensed Consolidated Statements of Comprehensive Income

(unaudited)

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

Net Income	$	67,125	$	54,707

Other Comprehensive Income:
Net unrealized holding gains arising during the period,
net of tax of $632 and $734	984		1,143
Unfunded pension liability adjustment, net of tax
of $114 and $87	177		136
Total Comprehensive Income	68,286		55,986
Comprehensive loss (income) attributable to noncontrolling interests	10		(229)
Comprehensive Income Attributable to IDACORP, Inc.	$	68,296	$	55,757

The accompanying notes are an integral part of these statements.

IDACORP, Inc.

Condensed Consolidated Statements of Comprehensive Income

(unaudited)

	Nine months ended
	September 30,
	2010		2009
	(thousands of dollars)

Net Income	$	122,219	$	100,963

Other Comprehensive Income:
Net unrealized holding gains arising during the period,
net of tax of $140 and $898	218		1,399
Unfunded pension liability adjustment, net of tax
of $341 and $261	532		408
Total Comprehensive Income	122,969		102,770
Comprehensive loss (income) attributable to noncontrolling interests	188		(126)
Comprehensive Income Attributable to IDACORP, Inc.	$	123,157	$	102,644

The accompanying notes are an integral part of these statements.

IDACORP, Inc.

Condensed Consolidated Statements of Equity

(unaudited)

	Nine months ended
	September 30,
	2010		2009
	(thousands of dollars)
Common Stock
Balance at beginning of period	$	756,475	$	729,576
Issued	38,086		16,738
Other	1,954		1,088
Balance at end of period	796,515		747,402

Retained Earnings
Balance at beginning of period	649,180		581,605
Net income attributable to IDACORP, Inc.	122,407		100,837
Common stock dividends ($0.90 per share)	(43,321)		(42,413)
Balance at end of period	728,266		640,029

Accumulated Other Comprehensive Income (Loss)
Balance at beginning of period	(8,267)		(8,707)
Unrealized gain on securities (net of tax)	218		1,399
Unfunded pension liability adjustment (net of tax)	532		408
Balance at end of period	(7,517)		(6,900)

Treasury Stock
Balance at beginning of period	(53)		(37)
Issued	882		1,425
Acquired	(846)		(1,441)
Balance at end of period	(17)		(53)
Total IDACORP, Inc. shareholders’ equity at end of period	1,517,247		1,380,478

Noncontrolling Interests
Balance at beginning of period	4,209		4,434
Net (loss) income attributed to noncontrolling interest	(188)		126
Other	-		(249)
Balance at end of period	4,021		4,311
Total equity at end of period	$	1,521,268	$	1,384,789

The accompanying notes are an integral part of these statements.

Idaho Power Company

Condensed Consolidated Statements of Income

(unaudited)

	Three months ended				Nine months ended
	September 30,				September 30,
	2010		2009		2010		2009
	(thousands of dollars)
Operating Revenues:
General business	$	266,270	$	277,676	$	674,293	$	663,818
Off-system sales	12,070		23,691		64,245		78,888
Other revenues	30,128		21,761		63,181		50,969
Total operating revenues	308,468		323,128		801,719		793,675

Operating Expenses:
Operation:
Purchased power	62,227		76,274		113,750		136,843
Fuel expense	51,339		49,530		116,083		113,138
Power cost adjustment	(20,934)		1,614		55,461		44,236
Other operations and maintenance	71,939		68,970		219,159		212,103
Energy efficiency programs	19,549		12,202		33,348		24,933
Depreciation	29,137		28,837		86,446		81,631
Taxes other than income taxes	5,645		5,600		17,130		15,749
Total operating expenses	218,902		243,027		641,377		628,633

Income from Operations	89,566		80,101		160,342		165,042

Other Income (Expense):
Allowance for equity funds used during construction	3,858		2,131		11,878		4,629
Earnings of unconsolidated equity-method investments	5,402		4,328		7,738		6,980
Other (expense) income, net	(766)		1,717		(1,937)		9,662
Total other income	8,494		8,176		17,679		21,271

Interest Charges:
Interest on long-term debt	20,135		18,826		59,003		53,661
Other interest	852		1,302		2,883		4,230
Allowance for borrowed funds used during construction	(2,303)		(1,654)		(7,781)		(4,439)
Total interest charges	18,684		18,474		54,105		53,452

Income Before Income Taxes	79,376		69,803		123,916		132,861

Income Tax Expense	14,726		18,746		2,216		36,194

Net Income	$	64,650	$	51,057	$	121,700	$	96,667

The accompanying notes are an integral part of these statements.

Idaho Power Company
Condensed Consolidated Balance Sheets

(unaudited)

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

Electric Plant:
In service (at original cost)	$	4,291,987	$	4,160,178
Accumulated provision for depreciation	(1,602,268)		(1,558,538)
In service - net	2,689,719		2,601,640
Construction work in progress	370,950		289,188
Held for future use	7,082		7,151
Electric plant - net	3,067,751		2,897,979

Investments and Other Property	113,706		108,299

Current Assets:
Cash and cash equivalents	178,542		21,625
Receivables:
Customer (net of allowance of $1,507 and $1,805, respectively)	69,263		74,987
Other (net of allowance of $144 and $185, respectively)	5,078		10,463
Income taxes receivable	97,576		3,585
Accrued unbilled revenues	46,663		51,272
Materials and supplies (at average cost)	45,331		48,054
Fuel stock (at average cost)	30,052		25,634
Prepayments	9,817		10,960
Deferred income taxes	7,331		7,887
Other	5,334		2,115
Total current assets	494,987		256,582

Deferred Debits:
American Falls and Milner water rights	22,381		24,226
Company-owned life insurance	26,646		26,654
Regulatory assets	724,977		720,401
Other	41,267		39,249
Total deferred debits	815,271		810,530

Total	$	4,491,715	$	4,073,390

The accompanying notes are an integral part of these statements.

Idaho Power Company

Condensed Consolidated Balance Sheets

(unaudited)

	September 30,		December 31,
	2010		2009
Capitalization and Liabilities	(thousands of dollars)

Capitalization:
Common stock equity:
Common stock, $2.50 par value (50,000,000 shares
authorized; 39,150,812 shares outstanding)	$	97,877	$	97,877
Premium on capital stock	668,758		638,758
Capital stock expense	(2,097)		(2,097)
Retained earnings	626,065		547,695
Accumulated other comprehensive loss	(7,517)		(8,267)
Total common stock equity	1,383,086		1,273,966

Long-term debt	1,488,205		1,409,730
Total capitalization	2,871,291		2,683,696

Current Liabilities:
Long-term debt due within one year	121,064		1,064
Accounts payable	80,336		83,128
Notes and accounts payable to related parties	1,351		1,736
Interest accrued	26,250		20,056
Uncertain tax positions	75,136		1,138
Other	68,347		38,864
Total current liabilities	372,484		145,986

Deferred Credits:
Deferred income taxes	650,526		611,749
Regulatory liabilities	296,861		287,780
Other	300,553		344,179
Total deferred credits	1,247,940		1,243,708

Commitments and Contingencies

Total	$	4,491,715	$	4,073,390

The accompanying notes are an integral part of these statements.

Idaho Power Company

Condensed Consolidated Statements of Capitalization

(unaudited)

	September 30,		December 31,
	2010		2009
	(thousands of dollars)
Common Stock Equity:
Common stock	$	97,877	$	97,877
Premium on capital stock	668,758		638,758
Capital stock expense	(2,097)		(2,097)
Retained earnings	626,065		547,695
Accumulated other comprehensive loss	(7,517)		(8,267)
Total common stock equity	1,383,086		1,273,966

Long-Term Debt:
First mortgage bonds:
6.60% Series due 2011	120,000		120,000
4.75% Series due 2012	100,000		100,000
4.25% Series due 2013	70,000		70,000
6.025% Series due 2018	120,000		120,000
6.15% Series due 2019	100,000		100,000
4.50 % Series Due 2020	130,000		130,000
3.40% Series Due 2020	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		-
Total first mortgage bonds	1,415,000		1,215,000
Amount due within one year	(120,000)		-
Net first mortgage bonds	1,295,000		1,215,000

Pollution control revenue bonds:
5.15% Series due 2024	49,800		49,800
5.25% Series due 2026	116,300		116,300
Variable Rate Series 2000 due 2027	4,360		4,360
Total pollution control revenue bonds	170,460		170,460

American Falls bond guarantee	19,885		19,885
Milner Dam note guarantee	7,446		8,509
Note guarantee due within one year	(1,064)		(1,064)
Unamortized premium/discount - net	(3,522)		(3,060)

Total long-term debt	1,488,205		1,409,730

Total Capitalization	$	2,871,291	$	2,683,696
The accompanying notes are an integral part of these statements.

Idaho Power Company

Condensed Consolidated Statements of Cash Flows

(unaudited)

	Nine months ended
	September 30,
	2010		2009
	(thousands of dollars)
Operating Activities:
Net income	$	121,700	$	96,667
Adjustments to reconcile net income to net cash provided by
operating activities:
Depreciation and amortization	90,785		85,922
Deferred income taxes and investment tax credits	67,516		12,419
Changes in regulatory assets and liabilities	50,338		37,721
Pension and postretirement benefit plan expense	10,474		7,756
Contributions to pension and postretirement benefit plans	(64,269)		(4,680)
Earnings of unconsolidated equity-method investments	(7,738)		(6,980)
Distributions from unconsolidated equity-method investments	455		8,340
Allowance for other funds used during construction	(11,878)		(4,629)
Other non-cash adjustments to net income	(729)		1,671
Change in:
Accounts receivables and prepayments	8,830		(21,940)
Accounts payable	(5,652)		(26,283)
Taxes accrued/receivable	(80,853)		41,996
Other current assets	2,914		(11,817)
Other current liabilities	21,590		6,029
Other assets	(3,443)		678
Other liabilities	(4,206)		(14,983)
Net cash provided by operating activities	195,834		207,887
Investing Activities:
Additions to utility plant	(249,437)		(155,591)
Proceeds from the sale of utility assets	18,982		-
Proceeds from the sale of non-utility assets	-		2,250
Proceeds from the sale of emission allowances and RECs	5,399		2,382
Other	3,274		648
Net cash used in investing activities	(221,782)		(150,311)
Financing Activities:
Issuance of long-term debt	200,000		100,000
Remarketing of pollution control revenue bonds	-		166,100
Decrease in term loans	-		(170,000)
Retirement of long-term debt	(1,064)		(1,064)
Dividends on common stock	(43,325)		(42,560)
Net change in short term borrowings	-		(108,950)
Capital contribution from parent	30,000		20,000
Other	(2,746)		(3,909)
Net cash provided by (used in) financing activities	182,865		(40,383)
Net increase in cash and cash equivalents	156,917		17,193
Cash and cash equivalents at beginning of the period	21,625		3,141
Cash and cash equivalents at end of the period	$	178,542	$	20,334

Supplemental Disclosure of Cash Flow Information:
Cash paid (received) during the period for:
Income taxes	$	21,815	$	(11,668)
Interest (net of amount capitalized)	$	46,338	$	40,505
Non-cash investing activities:
Additions to property, plant and equipment in accounts payable	$	21,551	$	19,990
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,
	2010		2009
	(thousands of dollars)

Net Income	$	64,650	$	51,057

Other Comprehensive Income:
Net unrealized holding gains arising during the period,
net of tax of $632 and $734	984		1,143
Unfunded pension liability adjustment, net of tax
of $114 and $87	177		136
Total Comprehensive Income	$	65,811	$	52,336

The accompanying notes are an integral part of these statements.

Idaho Power Company

Condensed Consolidated Statements of Comprehensive Income

(unaudited)

	Nine months ended
	September 30,
	2010		2009
	(thousands of dollars)

Net Income	$	121,700	$	96,667

Other Comprehensive Income:
Net unrealized holding gains arising during the period,
net of tax of $140 and $898	218		1,399
Unfunded pension liability adjustment, net of tax
of $341 and $261	532		408
Total Comprehensive Income	$	122,450	$	98,474

The accompanying notes are an integral part of these statements.

IDACORP, INC. AND IDAHO POWER COMPANY

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(unaudited)

1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES:

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

Nature of Business

IDACORP is a holding company formed in 1998 whose principal operating subsidiary is Idaho Power. IDACORP is subject to the provisions of the Public Utility Holding Company Act of 2005, which provides access to books and records to the Federal Energy Regulatory Commission (FERC) and state utility regulatory commissions and imposes record retention and reporting requirements on IDACORP.

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

Principles of Consolidation

IDACORP’s and Idaho Power’s consolidated financial statements include the accounts of each company, the subsidiaries that the companies control, and any variable interest entities (VIEs) for which the companies are the primary beneficiaries. All intercompany balances have been eliminated in consolidation. Investments in subsidiaries that the companies do not control and investments in VIEs for which the companies are not the primary beneficiaries, but have the ability to exercise significant influence over operating and financial policies, are accounted for using the equity method of accounting.

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

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

Through IERCo, Idaho Power holds a variable interest in BCC, a VIE for which it is not the primary beneficiary. IERCo is not the primary beneficiary because the power to direct the activities that most significantly impact the economic performance of BCC is shared with the joint venture partner. The carrying value of BCC is $91 million at September 30, 2010, and the maximum exposure to loss at BCC is the carrying value, any additional future contributions to the mine, and the $63 million guarantee for reclamation costs at the mine that is discussed further in Note 8 – “Commitments.”

Through IFS, IDACORP also holds variable interests in VIEs for which it is not the primary beneficiary. These VIEs are historic rehabilitation and affordable housing developments 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 $76 million at September 30, 2010.

Financial Statements

In the opinion of IDACORP and Idaho Power, the accompanying unaudited condensed consolidated financial statements contain all adjustments necessary to present fairly their consolidated financial positions as of September 30, 2010, consolidated results of operations for the three and nine months ended September 30, 2010, and 2009, and consolidated cash flows for the nine months ended September 30, 2010, and 2009. These adjustments are of a normal and recurring nature. These financial statements do not contain the complete detail or footnote disclosure concerning accounting policies and other matters that would be included in full-year financial statements and should be read in conjunction with the audited consolidated financial statements included in IDACORP’s and Idaho Power’s Annual Report on Form 10-K for the year ended December 31, 2009. The results of operations for the interim periods are not necessarily indicative of the results to be expected for the full year.

Use of Estimates

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

Reclassifications

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

• Third-party transmission expense was combined with purchased power in IDACORP and Idaho Power’s condensed consolidated statements of income as the balance of the third party transmission expense alone is immaterial;

• Gain on sale of emission allowances was combined with other operations and maintenance in IDACORP and Idaho Power’s condensed consolidated statements of income as the balance of gain on sale of emission allowances alone is immaterial;

• Other operations and maintenance in the operating expenses section of Idaho Power’s condensed consolidated statements of income were combined to be consistent with presentation in IDACORP’s condensed consolidated statements of income;

• Allowance for uncollectible accounts was offset against associated accounts receivable and presented in a parenthetical notation in IDACORP and Idaho Power’s condensed consolidated balance sheets;

• Other accrued taxes, that are not income tax accruals, were removed from taxes accrued and included in other current liabilities in the IDACORP condensed consolidated balance sheets. Taxes accrued and taxes receivable were relabeled in IDACORP and Idaho Power’s condensed consolidated balance sheets to be income taxes accrued and income taxes receivable, respectively, to provide greater comparability between statements;

• Uncertain tax positions have been separately presented and are no longer included within other current liabilities in IDACORP and Idaho Power’s condensed consolidated balance sheets as the uncertain tax positions are significant as of September 30, 2010;

• Excess tax benefits from share-based payment arrangements was combined with other non-cash adjustments to net income in the operating section and with other in the financing section of IDACORP’s condensed consolidated statements of cash flows; and

• Amortization of affordable housing was removed from depreciation and amortization and combined with undistributed earnings of unconsolidated subsidiaries, the total of which was then separated into losses of unconsolidated equity-method investments and distributions from unconsolidated equity method investments in the operating section of IDACORP’s condensed consolidated statements of cash flows.

New Accounting Pronouncements

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

2. INCOME TAXES:

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

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

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

		IDACORP				Idaho Power
		2010		2009		2010		2009
Income tax provision		$	17,489	$	13,730	$	22,100	$	18,746
Accounting method change			(7,374)		-		(7,374)		-
	Income tax expense	$	10,115	$	13,730	$	14,726	$	18,746
Effective tax rate			13.1%		20.1%		18.6%		26.9%

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

		IDACORP				Idaho Power
		2010		2009		2010		2009
Income tax provision		$	26,448	$	25,700	$	33,874	$	36,194
Accounting method change			(32,561)		-		(32,561)		-
Medicare Part D subsidy			903		-		903		-
	Income tax (benefit) expense	$	(5,210)	$	25,700	$	2,216	$	36,194
Effective tax rate			(4.4%)		20.3%		1.8%		27.2%

The decrease in the 2010 estimated annual effective tax rates as compared to the same periods of 2009 is primarily due to Idaho Power’s tax accounting method change for repair-related expenditures (discussed below), and lower pre-tax earnings at IDACORP and Idaho Power, partially offset by a charge related to the federal health care

legislation enacted in the first quarter of 2010. Net regulatory flow-through tax adjustments at Idaho Power and tax credits at IFS for the nine months ended September 30, 2010 were comparable to the same period in 2009.

Tax Accounting Method Change for Repair-Related Expenditures

In June 2010, Idaho Power completed its evaluation of a tax accounting method change for its 2009 tax year that allows a current income tax deduction for repair-related expenditures on its utility assets that are currently capitalized for financial reporting and tax purposes and planned to make this method change following the automatic consent procedures with the filing of IDACORP’s 2009 consolidated federal income tax return in September 2010. Accordingly, in the second quarter of 2010, Idaho Power recorded an estimated net tax benefit of $25.2 million related to the cumulative method change adjustment (tax years 1999 through 2009) and included an annual deduction estimate in its 2010 income tax provision, which resulted in a $3.6 million net tax benefit. In conjunction with recording the estimated tax benefit for the method change adjustment, Idaho Power increased its current liability for uncertain tax positions by $9.7 million.

Idaho Power’s prescribed regulatory accounting treatment requires immediate income recognition for temporary tax differences of this type. A regulatory asset is established to reflect Idaho Power’s ability to recover increased income tax expense when such temporary differences reverse.

If recognized, $14 million of the unrecognized tax benefits for capitalized repairs would affect the effective tax rate. The tax method is currently being audited under IDACORP’s 2009 Compliance Assurance Process (CAP) examination (discussed below) and, on a national level, aspects of the method related to electric utility transmission and distribution property are the subject of an Internal Revenue Service (IRS) Industry Issue Resolution program.

Status of Audit Proceedings and Uniform Capitalization Method Change

In May 2009, IDACORP formally entered the IRS CAP program for its 2009 tax year. The CAP program provides for IRS examination throughout the year. In January 2010, IDACORP was accepted into the CAP program for its 2010 tax year. With the exception of Idaho Power’s capitalized repairs method (discussed above) and uniform capitalization method (discussed below), IDACORP and Idaho Power believe there are no remaining tax uncertainties for the 2009 tax year and expect that the 2009 examination may conclude in the fourth quarter of 2010 or during fiscal year 2011. IDACORP and Idaho Power are unable to predict the outcome of the 2010 examination.

Specifically within the 2009 CAP examination, the IRS began its audit of Idaho Power’s current method of uniform capitalization. In September 2009, the IRS issued Industry Director Directive #5 (IDD), which discusses the IRS’s compliance priorities and audit techniques related to the allocation of mixed service costs in the uniform capitalization methods of electric utilities. Since that time the IRS and Idaho Power have jointly worked through the impact the IDD guidance had on Idaho Power’s uniform capitalization method and reached agreement during the third quarter of 2010. The agreement provided that Idaho Power change its uniform capitalization method to the agreed upon method under the IDD with the filing of IDACORP’s 2009 consolidated federal income tax return. Due to the method change agreement with the IRS, Idaho Power reversed the uncertain tax position liability for its 2009 uniform capitalization deduction resulting in a $1.1 million tax benefit as of September 30, 2010.

The resulting tax deductions available under the agreed upon uniform capitalization method were significantly greater than Idaho Power’s prior method. For the three months ended September 30, 2010, Idaho Power recorded a net tax benefit of $65.3 million related to the cumulative method change adjustment (tax years 1986 through 2009) for this method. The prescribed regulatory accounting treatment for this method is the same as discussed earlier for the capitalized repairs method.

Idaho Power has also provided a current uncertain tax position liability equal to the $65.3 million net tax benefit recorded for the uniform capitalization method change. While Idaho Power has an agreement with the IRS for examination and tax return filing purposes, it is awaiting U.S. Congress Joint Committee on Taxation approval of its method or approval of methods filed by similarly-situated companies under the IDD before concluding that the new method is effectively settled for financial reporting purposes. IDACORP and Idaho Power cannot predict when such approval will materialize, but believe it is possible in the fourth quarter of 2010 or, more likely, in 2011. If recognized, $61 million of the unrecognized tax benefits for uniform capitalization would affect the effective tax rate.

Cash Impacts of Tax Method Changes

IDACORP and Idaho Power will realize federal and state cash benefits associated with the 2009 capitalized repairs and uniform capitalization method changes of $33 million and $42 million, respectively. The majority of this cash benefit has been realized through reductions to cash payments that would have otherwise been owed to the taxing authorities for the 2009 tax year, except for a federal refund of $24 million that is expected to be received in the fourth quarter of 2010. Additionally, approximately $9 million of state cash benefits are expected to be substantially realized through reduced tax payments for the 2010 tax year.

The capitalized repairs and uniform capitalization method changes produced an income statement tax benefit of $44.5 million and $65.3 million respectively, prior to the accrual for uncertain tax positions. A portion of this earnings benefit relates to previously deferred income tax expense being flowed through the income statement which does not deliver any cash benefits. In addition, federal tax credits of $17 million previously recognized were restored due to the reduction of 2009 taxable income by the two method changes. The restored credits were a reduction to cash received in 2010, but will be available to deliver cash benefits in future periods.

Tax Impacts of Health Care Acts

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

3. REGULATORY MATTERS:

Deferred Net Power Supply Costs

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

			Idaho		Oregon⁽¹⁾		Total
Balance at December 31, 2009		$	71,412	$	13,221	$	84,633
Current period net power supply costs deferred			4,459		-		4,459
Prior costs expensed and recovered through rates			(58,572)		(1,348)		(59,920)
SO₂ allowances and REC sales credited to account			(3,250)		-		(3,250)
Interest and other			109		687		796
	Balance at September 30, 2010	$	14,158	$	12,560	$	26,718
⁽¹⁾ Oregon power supply cost deferrals are subject to a statute that specifically limits rate amortizations of deferred costs to six percent of gross Oregon revenue per year (approximately $2 million). Deferrals are amortized sequentially.

Idaho Settlement Agreement and 2010 PCA

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

• A general rate moratorium in effect until January 1, 2012. The moratorium does not apply to other specified revenue requirement proceedings, such as the power cost adjustment (PCA), the fixed cost adjustment (FCA), pension funding, advanced metering infrastructure (AMI), energy efficiency rider, and government imposed fees.

• A specified distribution of the expected reduction in 2010 PCA rates that would reduce customer rates, provide up to a $25 million general increase in annual base rates, and reset base power supply costs for the PCA, effective with the June 1, 2010 PCA rate change. This provision anticipated a significant reduction in PCA rates for the 2010-2011 PCA year.

• A provision to share with Idaho customers 50 percent of any Idaho-jurisdictional earnings in excess of a 10.5 percent return on equity in any calendar year from 2009 to 2011.

• A provision to allow additional amortization of accumulated deferred investment tax credit (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 is permitted to amortize additional ADITC in an amount up to $45 million over the three-year period, but could use no more that $15 million in any one year unless there is a carryover. Carryover amounts are added to the $15 million annual allowance up to a maximum amortization of $25 million in any one year.

Because Idaho Power’s 2009 Idaho-jurisdiction return on year-end equity was between 9.5 and 10.5 percent, the sharing and additional amortization provisions were not triggered. As a result, the ADITC available for additional amortization in 2010 is $25 million. Idaho Power recorded additional ADITC amortization of $4.5 million in the first quarter of 2010, but reversed the entire $4.5 million in the second quarter based on updated estimates of annual 2010 return on equity. Idaho Power did not record any additional ADITC amortization in the third quarter of 2010. If additional ADITC amortization is not utilized in the fourth quarter of 2010, the ADITC available for additional amortization in 2011 will be $25 million.

On May 28, 2010, the IPUC issued an order approving a $146.9 million decrease in the PCA, along with a base rate increase of $88.7 million. The base rate increase reflects a $63.7 million increase in base power supply costs and a $25 million increase in general rates. The net effect of these two rate adjustments was an overall decrease in Idaho jurisdiction customer rates of $58.2 million, or 6.49 percent, effective June 1, 2010.

Other Idaho 2010 Filings and Orders

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

• Fixed Cost Adjustment: Idaho Power’s FCA filing for the 2009 calendar year proposed to collect $6.3 million for one year, a $3.6 million annual increase over the current rates at the time of filing. The $6.3 million reflects amounts accrued in 2009 under the mechanism. Beginning June 1, 2010, Idaho Power implemented the rate increase to residential and small general service customers. The IPUC also extended the FCA pilot program for two years, through December 31, 2011.

• Pension: Idaho Power filed a request to recover $5.4 million of pension contributions that it was required to make on or before September 15, 2010. In accordance with prior IPUC orders, Idaho Power had been deferring its Idaho-jurisdiction pension expense to a regulatory asset. On February 17, 2010, the IPUC approved a recovery methodology that would permit Idaho Power to include in future rate cases a reasonable recovery and amortization of cash contributions to the pension plan. The IPUC approved Idaho Power’s request to increase rates by $5.4 million, effective June 1, 2010. Including the $3.6 million remaining of the $5.4 million of regulatory assets approved for recovery discussed above, as of September 30, 2010, Idaho Power had $56.3 million of Idaho jurisdiction regulatory assets associated with deferred pension expenses that, based on its evaluation, are probable of recovery.

• AMI: The IPUC approved Idaho Power’s application for a $2.4 million annual increase in base rates for costs related to AMI, with the rate increase effective June 1, 2010.

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

In two separate orders issued in February 2009 and April 2010, the IPUC approved for ratemaking purposes energy efficiency rider expenditures, totaling $29 million, Idaho Power made from 2002 through 2007.

Retirement Plan Prudency Filing: The IPUC’s May 28, 2010 order approving Idaho Power’s request to increase rates for pension contribution recovery provided that the allowance of recovery of a $5.4 million contribution for 2009 does not guarantee that the IPUC will similarly approve future recovery of contributions, without further justification. The order reiterated Idaho Power’s authorization to continue regulatory treatment of current pension expenses. On October 1, 2010, Idaho Power filed an application with the IPUC requesting an order accepting Idaho Power’s 2011 retirement benefits package, but without seeking specific recovery of additional contributions to Idaho Power’s retirement benefit plans.

Oregon Regulatory Matters

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

Oregon Power Cost Recovery Mechanisms: Idaho Power’s power cost recovery mechanism in Oregon has two components -- the power cost adjustment mechanism (PCAM) and the annual power cost update. On February 26, 2010, Idaho Power filed its PCAM application for the 2009 year with the OPUC. The filing stated that actual net power supply costs were within the deadband, which is the range of deviations within which Idaho Power absorbs power supply cost increases or decreases, resulting in no request for a deferral. On April 15, 2010, Idaho Power filed with the OPUC a stipulation combining its March power supply cost forecast and 2009 October update. The stipulation was approved on May 24, 2010, and resulted in an overall increase of $2.2 million in Oregon rates, effective June 1, 2010. On October 15, 2010, Idaho Power filed its October power cost update with the OPUC, requesting an increase in base rates of $1.6 million.

Annual OATT Update

On August 26, 2010, Idaho Power submitted its annual Final Information Filing for its Open Access Transmission Tariff (OATT) on its Open Access Same-Time Information System Internet platform. The new rate submitted by Idaho Power was $19.60 per kW/year, an increase over the prior $15.83 per kW/year OATT rate, and was effective as of October 1, 2010 for a period of one year. For the nine months ended September 30, 2010, revenues from the transmission rate for service under the OATT were $11 million. In September 2010, Idaho Power made corrections to its OATT rates for the period beginning October 1, 2007 through September 30, 2010 that resulted in the issuance of refunds, including interest, to transmission customers of $0.5 million.

4. LONG-TERM DEBT:

As of September 30, 2010, IDACORP had approximately $547 million remaining on a shelf registration statement filed with the Securities and Exchange Commission (SEC) that can be used for the issuance of debt securities or common stock.

In May 2010, Idaho Power registered with the SEC the sale of 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. On August 30, 2010, Idaho Power issued $100 million of 3.40% First Mortgage Bonds, Secured Medium-Term Notes, Series I due 2020 and $100 million of 4.85% First Mortgage Bonds, Secured Medium-Term Notes, Series I due 2040 under the shelf registration statement. As of September 30, 2010, $300 million remained on Idaho Power’s shelf registration for the issuance of first mortgage bonds and debt securities.

5. NOTES PAYABLE:

Credit Facilities

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

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

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

		September 30, 2010		December 31, 2009
IDACORP
	Commercial paper outstanding	$	4,000	$	53,750
	Weighted-average annual interest rate		0.46%		0.41%

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

6. COMMON STOCK:

IDACORP Common Stock

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

		Shares issued
Balance at December 31, 2009		47,925,882
Continuous equity program		768,612
Dividend reinvestment and stock purchase plan		110,769
Employee savings plan		81,322
Long-term incentive and compensation plan (LTICP) ⁽¹⁾		224,651
Restricted stock plan		13,293
	Balance at September 30, 2010	49,124,529
⁽¹⁾ Included in the LTICP activity are 15,800 shares that were issued pursuant to the exercise of stock options on December 30, 2009, and settled on January 4, 2010.

IDACORP enters into sales agency agreements as a means of selling its common stock from time to time. Under the current agreement IDACORP sold 768,612 shares in September 2010 at an average price of $35.21 for aggregate net proceeds of approximately $27 million. As of September 30, 2010, there were approximately 1.4 million shares remaining available to be sold under the current sales agency agreement.

Idaho Power Common Stock

On June 28, 2010 and on September 30, 2010, IDACORP contributed $10 million and $20 million, respectively, of additional equity to Idaho Power. No additional shares of Idaho Power common stock were issued.

Restrictions on Dividends

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

Idaho Power’s ability to pay dividends on its common stock held by IDACORP and IDACORP’s ability to pay dividends on its common stock are limited to the extent payment of such dividends would violate the covenants in their respective credit facilities or Idaho Power’s Revised Code of Conduct. At September 30, 2010, the leverage ratios for IDACORP and Idaho Power were 52 percent and 54 percent, respectively. Based on these restrictions, IDACORP’s and Idaho Power’s dividends were limited to $646 million and $517 million, respectively, at September 30, 2010. There are additional covenants, subject to exceptions, that prohibit or restrict specified investments or acquisitions, mergers, or 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, 2010, IDACORP and Idaho Power were in compliance with all facility covenants.

7. EARNINGS PER SHARE:

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

				Three months ended				Nine months ended
				September 30,				September 30,
				2010		2009		2010		2009
Numerator:
	Net income attributable to IDACORP, Inc.			$	67,135	$	54,478	$	122,407	$	100,837
Denominator:
	Weighted-average common shares outstanding - basic				48,086		47,068		47,917		46,953
	Effect of dilutive securities:
		Options			30		15		37		12
		Restricted Stock			136		58		108		34
			Weighted-average common shares outstanding - diluted		48,252		47,141		48,062		46,999
Basic earnings per share				$	1.40	$	1.16	$	2.55	$	2.15
Diluted earnings per share				$	1.39	$	1.16	$	2.55	$	2.15

The diluted EPS computation excludes 321,891 and 337,242 options for the three and nine months ended September 30, 2010, respectively, because the options’ exercise prices were greater than the average market price of the common stock during that period. For the same periods in 2009, the computation excludes 548,957 and 640,674 options for the same reason. In total, 417,796 options were outstanding at September 30, 2010, with expiration dates between 2011 and 2015.

8. COMMITMENTS:

Purchase Obligations

The following items are material changes to purchase obligations outside of the ordinary course of business during the nine months ended September 30, 2010:

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

• In 2010, Idaho Power entered into several purchased power agreements with wind and other alternate energy developers. Payments by Idaho Power under these agreements are expected to total approximately $493 million from 2011 to 2031.

• In April 2010, Idaho Power entered into multiple service agreements with Northwest Pipeline for rate schedule TF-1, Firm Transportation. Payments by Idaho Power under these service agreements are expected to total approximately $32 million from 2011 to 2042.

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

Guarantees

Idaho Power has agreed to guarantee the performance of reclamation activities and obligations at BCC, of which IERCo owns a one-third interest. This guarantee, which is renewed each December, was $63 million at September 30, 2010. BCC has a reclamation trust fund set aside specifically for the purpose of paying these reclamation costs. BCC continually assesses the adequacy of the reclamation trust fund and its estimate of future reclamation costs. To ensure that the reclamation trust fund maintains adequate reserves, BCC has the ability to add a per-ton surcharge to coal sales. In 2010, BCC began applying a nominal surcharge to coal sales in order to maintain adequate reserves in the reclamation trust fund. Because of the existence of the fund and the ability to apply a per-ton surcharge, the estimated fair value of this guarantee is minimal.

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

9. CONTINGENCIES:

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

Western Energy Proceedings at the FERC

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

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

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

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

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

On November 19, 2009, the FERC issued an order to implement the Ninth Circuit’s remand. The remand order established a trial-type hearing in which participants will be permitted to submit information regarding (i) specified tariff violations committed by any public utility seller from January 1, 2000 to October 2, 2000 resulting in a transaction that set a market clearing price for the trading period when the violation occurred, and (ii) claims for refunds for multi-day transactions and energy exchange transactions entered into during the refund period (October 2, 2000 to June 20, 2001). Numerous parties, including IE and Idaho Power, filed motions to clarify the FERC’s order. After designating a presiding administrative law judge to establish hearing procedures in July 2010, on August 19, 2010, the FERC’s Chief Administrative Law Judge suspended the hearing procedures and, in response to a solicitation from the FERC, on September 22, 2010, IE and Idaho Power, along with a number of other parties, submitted comments to the FERC regarding the scope of the proceedings. Although IE and Idaho Power are unable to predict when or how the FERC will rule on these motions and the later comments, the effect of the remand order for IE and Idaho Power is confined to the minority of market participants that are not bound by the IE-Idaho Power-California Parties’ settlement described above. IE and Idaho Power believe the remanded proceedings will not have a material adverse effect on their consolidated financial positions, results of operations, or cash flows.

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

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

The orders establishing the scope of the show cause proceedings are presently the subject of review petitions in the Ninth Circuit. In August 2010, at the request of IE and Idaho Power, the petitioners in all but one of the petitions for review of the FERC’s orders establishing the scope of the show cause proceedings filed to withdraw their petitions as they relate to IE and Idaho Power. Although IE and Idaho Power are unable to predict how or when the Ninth Circuit will act on the requested withdrawals or the review petitions, in light of the settlement described above and the withdrawal requests, IE and Idaho Power believe this matter will not have a material adverse effect on their consolidated financial positions, results of operations, or cash flows.

On June 25, 2003, the FERC also issued an order instituting an investigation of anomalous bidding behavior and practices in the western wholesale markets for the time period May 1, 2000 through October 1, 2000, but the FERC terminated its investigations as to Idaho Power on May 12, 2004. California government agencies and California investor-owned utilities have appealed the FERC’s termination of this investigation as to Idaho Power and more than 30 other market participants. On August 12, 2010, in response to a request by IE and Idaho Power, the California government agencies and California investor-owned utilities filed a request to withdraw their petition for review solely as it relates to IE and Idaho Power. IE and Idaho Power are unable to predict the outcome of these petitions for review proceedings or the withdrawal request, but believe that the settlement releases govern any potential claims that might arise and that this matter will not have a material adverse effect on their consolidated financial positions, results of operations, or cash flows.

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

In separate filings, the California Parties, which no longer include the California Electricity Oversight Board, and the City of Tacoma, Washington (Tacoma) and the Port of Seattle, Washington (Port of Seattle) asked the FERC to reorganize and restructure the case to enable them to pursue claims that all spot market sales in the Cal ISO and CalPX markets and in the Pacific Northwest from January 1, 2000 through June 20, 2001 should be subject to refund and repriced, because market manipulation and tariff violations affected spot market prices. Their requests would expand the scope of the refund period in the Pacific Northwest proceeding from the December 25, 2000 through June 20, 2001 period previously considered by the FERC. On May 22, 2009, the California Parties filed a motion with the FERC to sever claims regarding sales originating in the Pacific Northwest to CDWR from the remainder of the Pacific Northwest proceedings and to consolidate their claims regarding these sales with ongoing proceedings in cases that IE and Idaho Power have settled, as well as with a new complaint filed on May 22, 2009 by the California Attorney General against parties with whom the California Parties have not settled (Brown Complaint). IE and Idaho Power, along with a number of other parties, filed their opposition to the motion of the California Parties. Many other parties also filed responses to the motion of the California Parties. Tacoma and the Port of Seattle jointly filed a motion on August 4, 2009 with the FERC in connection with the California refund proceeding, the Lockyer remand pending before the FERC (involving claims of failure to file quarterly transaction reports with the FERC, from which IE and Idaho Power previously were dismissed), the Brown Complaint, and the Pacific Northwest refund remand proceeding. The Tacoma and the Port of Seattle motion asks the FERC to require refunds from all sellers in the Pacific Northwest spot markets for the expanded period (January 1, 2000 through June 20, 2001). IE and Idaho Power joined with a number of other sellers in the Pacific Northwest markets during 2000 and 2001 in opposing the motion of Tacoma and the Port of Seattle. On April 19, 2010, the California Parties filed a motion with the FERC renewing the requests contained in their May 22, 2009 motion and on May 3, 2010, IE and Idaho Power joined with a number of other parties opposing the renewal request. On July 21, 2010, the Port of Seattle and Tacoma once again filed a motion requesting that the FERC either summarily dispose of the case or set it for hearing, and the California Parties, answering a pleading in the Brown Complaint, renewed their request for consolidation. The FERC has not acted on the Ninth Circuit remand or the motions.

IE and Idaho Power intend to vigorously defend their positions in these proceedings but are unable to predict the outcome of these matters or estimate the impact these matters may have on their consolidated financial positions, results of operations, or cash flows.

Sierra Club Lawsuit 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 violations at the Boardman coal-fired plant located in Morrow County, Oregon. The complaint also alleged violations of the Clean Air Act (CAA), related federal regulations, and the Oregon State Implementation Plan relating to PGE’s construction and operation of the plant. The complaint sought a declaration that PGE had violated opacity limits, a permanent injunction ordering PGE to comply with such limits, injunctive relief requiring PGE to remediate alleged environmental damage and ongoing impacts, civil penalties of up to $32,500 per day per violation, and reimbursement of plaintiffs’ costs of litigation, including reasonable attorneys’ fees. Idaho Power is not a party to this proceeding but has a 10 percent ownership interest in the Boardman plant. PGE owns 65 percent of the plant and is the operator of the plant.

On September 28, 2010, the U.S. Environmental Protection Agency (EPA) issued a Notice of Violation to PGE, alleging that PGE has violated the New Source Performance Standards (NSPS) and operating permit requirements under the CAA, as a result of modifications made to the plant in 1998 and 2004. The Notice of Violation states the maximum civil penalties the EPA is authorized to impose under the CAA for violations of the NSPS (which range from $25,000 to $37,500 per day), but does not impose any penalties, or specify the amount of any proposed penalties with respect to the alleged violations.

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

Snake River Basin Adjudication

Idaho Power is engaged in the Snake River Basin Adjudication (SRBA), a general stream adjudication commenced in 1987, to define the nature and extent of water rights in the Snake River Basin in Idaho, including the water rights of Idaho Power.

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

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

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

U.S. Bureau of Reclamation Proceedings

Idaho Power filed a complaint on October 15, 2007, and an amended complaint on September 30, 2008, in the U.S. District Court of Federal Claims in Washington, D.C. against the U.S. Bureau of Reclamation (USBR). The complaint relates to a 1923 contract right for delivery of water to Idaho Power’s hydropower projects on the Snake River, to recover damages from the USBR for the lost generation resulting from reduced flows, and for a prospective declaration of contractual rights and obligations of the parties. Over the past several months, Idaho Power has been working with the U.S. and Idaho interests (including the State of Idaho and upstream water users) in an effort to resolve certain state water right issues pending in the SRBA that are common to both the SRBA and

the pending federal case. Current discussions primarily relate to modification to state policy and the Idaho water plan that promote more efficient operation of the upper Snake River reservoir system to optimize the release and shaping of Snake River flows for hydroelectric generation downstream during the high-load winter months. In an effort to promote efficiency, the parties have agreed to present certain legal issues associated with the 1923 contract to the court in the SRBA case that are expected to resolve issues in the pending federal case. The SRBA court has scheduled the presentation of these issues to the court in December 2010. Idaho Power and the USBR have agreed to stay further proceedings in the federal case pending the resolution of these issues in the SRBA case. Idaho Power is unable to predict the outcome of this matter or what effect it may have on its financial position, results of operations, or cash flows.

Oregon Trail Heights Fire

On August 25, 2008, a fire ignited beneath an Idaho Power distribution line in Boise, Idaho. It was fanned by high winds and spread rapidly, resulting in one death, the destruction of 10 homes, and damage or alleged fire-related losses to approximately 30 others. Following the investigation, the Boise Fire Department determined that the fire was linked to a piece of line hardware on one of Idaho Power’s distribution poles and that high winds contributed to the fire and its resultant damage. Idaho Power has received notices of claims from a number of the homeowners and their insurers and has reached settlements with most of the individuals or their insurers who have alleged damages resulting from the fire. Idaho Power is insured up to policy limits against liability for claims in excess of its self-insured retention. Idaho Power has accrued a reserve for any loss that is probable and reasonably estimable, including insurance deductibles, and believes this matter will not have a material adverse effect on its consolidated financial position, results of operations, or cash flows.

Other Legal Proceedings

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

10. BENEFIT PLANS:

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

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

							Senior Management				Postretirement
			Pension Plan				Security Plan				Benefits
			2010		2009		2010		2009		2010		2009
Service cost			$	4,417	$	4,129	$	385	$	402	$	340	$	306
Interest cost				7,279		6,966		751		714		898		892
Expected return on plan assets				(7,270)		(5,991)		-		-		(641)		(538)
Amortization of transition obligation				-		-		-		-		510		510
Amortization of prior service cost				163		162		59		58		(133)		(134)
Amortization of net loss				1,918		2,215		232		164		143		211
	Net periodic benefit cost			6,507		7,481		1,427		1,338		1,117		1,247
Costs not recognized due to the
	effects of regulation ⁽¹⁾			(4,624)		(7,481)		-		-		-		-
	Net periodic benefit cost
		recognized for financial
		reporting ⁽²⁾	$	1,883	$	-	$	1,427	$	1,338	$	1,117	$	1,247
⁽¹⁾Under IPUC order, income statement recognition of pension plan costs has been deferred until costs are recovered through rates. See Note 3 – “Regulatory Matters” for information on Idaho Power’s 2010 pension rate filing.
⁽²⁾Net periodic benefit costs for the pension plan are recognized for the Oregon jurisdiction and non-regulated subsidiaries, and beginning in June 2010, for the Idaho and FERC jurisdictions.

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

							Senior Management				Postretirement
			Pension Plan				Security Plan				Benefits
			2010		2009		2010		2009		2010		2009
Service cost			$	13,253	$	12,386	$	1,156	$	1,207	$	1,020	$	916
Interest cost				21,839		20,898		2,253		2,141		2,693		2,674
Expected return on plan assets				(19,847)		(17,974)		-		-		(1,921)		(1,611)
Amortization of transition obligation				-		-		-		-		1,530		1,530
Amortization of prior service cost				488		488		175		174		(401)		(401)
Amortization of net loss				5,756		6,643		698		494		430		632
	Net periodic benefit cost			21,489		22,441		4,282		4,016		3,351		3,740
Costs not recognized due to the
	effects of regulation⁽¹⁾			(18,650)		(22,441)		-		-		-		-
	Net periodic benefit cost
		recognized for financial
		reporting ⁽²⁾	$	2,839	$	-	$	4,282	$	4,016	$	3,351	$	3,740
⁽¹⁾ Under IPUC order, income statement recognition of pension plan costs has been deferred until costs are recovered through rates. See Note 3 – “Regulatory Matters” for information on Idaho Power’s 2010 pension rate filing.
⁽²⁾Net periodic benefit costs for the pension plan are recognized for the Oregon jurisdiction and non-regulated subsidiaries, and beginning in June 2010, for the Idaho and FERC jurisdictions.

Pension Contribution

On September 15, 2010, Idaho Power contributed $60 million to its pension plan. The contribution was in excess of the $6 million minimum contribution required to be made in 2010 for the 2009 plan 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. Unless Idaho Power elects an alternative amortization schedule under the new legislation discussed below, minimum required contributions to the pension plan are estimated to be $2 million, $44 million, $37 million, and $36 million in 2011, 2012, 2013, and 2014, respectively, after giving effect to the September 2010 contribution. Idaho Power may elect to make contributions earlier than the required dates.

Benefit Plan-Related Legislation

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

In June 2010, the Preservation of Access to Care for Medicare Beneficiaries and Pension Relief Act of 2010 was signed into law, which permits employers to choose between two alternative funding options for defined benefit pension plans for any two plan years between 2008 and 2011, either (i) amortizing the funding shortfall for the applicable years over 15 years or (ii) paying interest only on the applicable plan years’ funding shortfall for two plan years followed by amortization of the actual shortfall for 7 years. If an alternate funding option is elected, it would reduce near-term required contributions to the plan by spreading them over a longer time period. The legislation does not eliminate Idaho Power’s obligation to fully fund the pension plan. In addition, the legislation outlines penalties in the form of increased pension contributions from an employer that elects one of the funding relief options at the same time that employer (or entities within its ERISA-controlled group) awards “excess employee compensation” (generally compensation over $1 million per year paid to an employee), grants “excessive” dividends, or effects specified stock redemptions. Idaho Power will evaluate the legislation and its alternatives further prior to electing an alternative, if any. See Note 3 - “Regulatory Matters” for a discussion of Idaho Power’s recovery of pension plan contributions through the ratemaking process.

11. INVESTMENTS IN DEBT AND EQUITY SECURITIES:

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

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

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

September 30, 2010

December 31, 2009

Gross

Unrealized

Fair

Unrealized

Fair

Gain

Loss

Value

Gain

Loss

Value

Available-for-sale securities

3,347

17,066

2,989

18,842

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

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

	Three months ended				Nine months ended
	September 30,				September 30,
	2010		2009		2010		2009

Proceeds from sales	$	-	$	15	$	-	$	9,030
Gross realized gains from sales		-		-		-		11
Gross realized losses from sales		-		-		-		35

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. With the exception of forward contracts for the purchase of natural gas for use at Idaho Power’s natural gas generation facilities, Idaho Power’s physical forward contracts, including renewable energy certificates, qualify for the normal purchases and normal sales exception. Because of Idaho Power’s power cost adjustment mechanisms, unrealized gains and losses associated with the changes in fair value of these derivative instruments are recorded as regulatory assets or liabilities.

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

Derivative Commodity Contracts
		September 30,
Commodity	Units	2010	2009
Electricity purchases	MWh	443,250	604,650
Electricity sales	MWh	237,000	473,750
Natural gas purchases	MMBtu	325,500	1,147,000
Diesel purchases	Gallons	208,980	225,564

The following tables present the fair values and locations of derivative instruments recorded in the balance sheets at September 30, 2010 and December 31, 2009 (in thousands of dollars):

Commodity Derivatives			Asset Derivatives			Liability Derivatives
			Balance Sheet	Fair		Balance Sheet	Fair
September 30, 2010			Location	Value		Location	Value
Current:
	Financial swaps		Other current assets	$	999	Other current assets	$	497
	Financial swaps		Other current liabilities		3,136	Other current liabilities		6,301
	Forward contracts		Other current liabilities		-	Other current liabilities		549
Long-term:
	Financial swaps		Other assets		71	Other assets		22
		Total		$	4,206		$	7,369

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

The following table presents the gains and losses on derivatives for the three and nine months ended September 30, 2010 and 2009 (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, 2010:
	Financial swaps	Off-system sales	$	2,332
	Financial swaps	Purchased power		(6,749)
	Financial swaps	Fuel expense		(101)
	Forward contracts	Fuel expense		(721)
Three months ended September 30, 2009:
	Financial swaps	Off-system sales		1,017
	Financial swaps	Purchased power		(876)
	Financial swaps	Fuel expense		(986)
	Forward contracts	Fuel expense		(5,794)
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)
Nine months ended September 30, 2009:
	Financial swaps	Off-system sales		3,304
	Financial swaps	Purchased power		3,296
	Financial swaps	Fuel expense		(986)
	Forward contracts	Fuel expense		(5,794)
⁽¹⁾ Excludes changes in fair value of derivatives, which are recorded on the balance sheet as regulatory assets or regulatory liabilities.

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

Credit Risk

At September 30, 2010, 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. The majority of Idaho Power’s contracts are under the form of the Western Systems Power Pool agreement that provides for adequate assurances if a counterparty has debt that is downgraded to below investment grade by at least one rating agency. Idaho Power also requires North American Energy Standards Board contracts as necessary for physical gas transactions, and International Swaps and Derivatives Association, Inc. contracts as needed for financial transactions.

Credit-Contingent Features

Certain of Idaho Power's derivative instruments contain provisions that require Idaho Power's unsecured debt to maintain an investment grade credit rating from 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 are in a liability position at September 30, 2010, was $7 million. Idaho Power had posted $4 million of collateral related to this

amount. If the credit-risk-related contingent features underlying these agreements were triggered on September 30, 2010, Idaho Power would have been required to post $0.6 million of additional cash collateral to its counterparties.

13. FAIR VALUE MEASUREMENTS:

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

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

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

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

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

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

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

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

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

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

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

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

		Quoted Prices in		Significant		Significant
		Active Markets		Other		Unobservable
		for Identical		Observable		Inputs
		Assets (Level 1)		Inputs (Level 2)		(Level 3)		Total
September 30, 2010
IDACORP
Assets:
	Derivatives	$	551	$	-	$	-	$	551
	Money market funds		87,802		-		-		87,802
	Trading securities: Equity securities		4,996		-		-		4,996
	Available-for-sale securities: Equity securities		17,066		-		-		17,066
Liabilities:
	Derivatives	$	(32)	$	(549)	$	-	$	(581)
Idaho Power
Assets:
	Derivatives	$	551	$	-	$	-	$	551
	Money market funds		85,000		-		-		85,000
	Trading securities: Equity securities		4,428		-		-		4,428
	Available-for-sale securities: Equity securities		17,066		-		-		17,066
Liabilities:
	Derivatives	$	(32)	$	(549)	$	-	$	(581)

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

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

		September 30, 2010					December 31, 2009
		Carrying			Estimated		Carrying		Estimated
		Amount			Fair Value		Amount		Fair Value
		(thousands of dollars)
IDACORP
Assets:
	Notes receivable	$	2,946	$		2,946	$	2,946	$	2,946
Liabilities:
	Long-term debt		1,618,342			1,732,023		1,422,130		1,406,815
Idaho Power
Liabilities:
	Long-term debt	$	1,612,790	$		1,726,508	$	1,413,854	$	1,398,681

14. SEGMENT INFORMATION:

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

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

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

		Utility		All				Consolidated
		Operations		Other		Eliminations		Total
Three months ended September 30, 2010:
	Revenues	$	308,468	$	889	$	-	$	309,357
	Income attributable to IDACORP, Inc.		64,650		2,485		-		67,135
Total assets at September 30, 2010			4,491,715		102,985		(20,307)		4,574,393
Three months ended September 30, 2009:
	Revenues	$	323,128	$	1,381	$	-	$	324,509
	Income attributable to IDACORP, Inc.		51,057		3,421		-		54,478
Nine months ended September 30, 2010:
	Revenues	$	801,719	$	2,354	$	-	$	804,073
	Income attributable to IDACORP, Inc.		121,700		707		-		122,407
Nine months ended September 30, 2009:
	Revenues	$	793,675	$	3,042	$	-	$	796,717
	Income attributable to IDACORP, Inc.		96,667		4,170		-		100,837

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, 2010, and the related condensed consolidated statements of income and comprehensive income for the three-month and nine-month periods ended September 30, 2010 and 2009, and of equity and cash flows for the nine-month periods ended September 30, 2010 and 2009. These interim financial statements are the responsibility of the Company’s management.

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

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

We have previously audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheet of IDACORP, Inc. and subsidiaries as of December 31, 2009, and the related consolidated statements of income, comprehensive income, equity, and cash flows for the year then ended (not presented herein); and in our report dated February 23, 2010, we expressed an unqualified opinion on those consolidated financial statements, which included an explanatory paragraph related to the adoption of accounting guidance for noncontrolling interests in consolidated financial statements and guidance for accounting for uncertainty in income taxes. In our opinion, the information set forth in the accompanying condensed consolidated balance sheet as of December 31, 2009 is fairly stated, in all material respects, in relation to the consolidated balance sheet from which it has been derived.

/s/ DELOITTE & TOUCHE LLP

Boise, Idaho

October 28, 2010

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Shareholder of Idaho Power Company

Boise, Idaho

We have reviewed the accompanying condensed consolidated balance sheet and statement of capitalization of Idaho Power Company and subsidiary (the “Company”) as of September 30, 2010, and the related condensed consolidated statements of income and comprehensive income for the three-month and nine-month periods ended September 30, 2010 and 2009, and of cash flows for the nine-month periods ended September 30, 2010 and 2009. These interim financial statements are the responsibility of the Company’s management.

We have previously audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheet and statement of capitalization of Idaho Power Company and subsidiary as of December 31, 2009, and the related consolidated statements of income, comprehensive income, retained earnings, and cash flows for the year then ended (not presented herein); and in our report dated February 23, 2010, we expressed an unqualified opinion on those consolidated financial statements, which included an explanatory paragraph related to the adoption of guidance for accounting for uncertainty in income taxes. In our opinion, the information set forth in the accompanying condensed consolidated balance sheet and statement of capitalization as of December 31, 2009 is fairly stated, in all material respects, in relation to the consolidated balance sheet and statement of capitalization from which it has been derived.

/s/ DELOITTE & TOUCHE LLP

Boise, Idaho

October 28, 2010

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

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

INTRODUCTION

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

IDACORP is a holding company formed in 1998 whose principal operating subsidiary is Idaho Power. IDACORP is subject to the provisions of the Public Utility Holding Company Act of 2005, which provides certain access to books and records to the Federal Energy Regulatory Commission (FERC) and state utility regulatory commissions and imposes certain record retention and reporting requirements on IDACORP. IDACORP’s 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 491,000 general business customers as of September 30, 2010. Idaho Power is regulated by the FERC and the state regulatory commissions of Idaho and Oregon. Idaho Power is the parent of Idaho Energy Resources Co. (IERCo), a joint venturer in Bridger Coal Company (BCC), which mines and supplies coal to the Jim Bridger generating plant owned in part by Idaho Power. Idaho Power generates revenues and cash flows primarily from the sale and distribution of electricity to customers in its Oregon and Idaho service territory, as well as from the wholesale sale and transmission of electricity. Idaho Power’s revenues and income from operations are subject to fluctuations during the year due to the impacts of seasonal weather conditions on demand for electricity, price changes, customer usage patterns (which are affected in large part by the condition of the local economy), and the availability and price of purchased power and fuel. Idaho Power is a dual peaking utility that typically experiences its highest retail energy sales during the summer irrigation and cooling season, with a lower peak in the winter that generally results from heating demand. IDACORP’s and Idaho Power’s financial condition is also affected by regulatory decisions, through which Idaho Power seeks to recover its costs, including purchased power and fuel costs, on a timely basis, and to earn an authorized return on investment, and by the ability to obtain financing through the issuance of debt and/or equity securities.

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

While reading the MD&A, please refer to the accompanying condensed consolidated financial statements of IDACORP and Idaho Power. This discussion updates the MD&A included in the Annual Report on Form 10-K for the year ended December 31, 2009, and the Quarterly Reports on Form 10-Q for the quarters ended March 31, 2010 and June 30, 2010, and should be read in conjunction with the discussions in those reports.

FORWARD-LOOKING INFORMATION

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

actual results or outcomes to differ materially from those expressed. In addition to any assumptions and other factors and matters referred to specifically in connection with such forward-looking statements, factors that could cause actual results or outcomes to differ materially from those discussed in forward-looking statements include those factors discussed in IDACORP, Inc.’s and Idaho Power Company’s 2009 Annual Report on Form 10-K, particularly Item 1A – “Risk Factors,” as updated by Part II, Item 1A of IDACORP, Inc.’s and Idaho Power Company’s Quarterly Report on Form 10-Q for the interim period ended June 30, 2010, and the following important factors:

• The effect of regulatory decisions by the Idaho Public Utilities Commission, the Oregon Public Utility Commission, and the Federal Energy Regulatory Commission affecting Idaho Power Company’s ability to recover costs and/or earn a reasonable rate of return, including, but not limited to, the recovery or disallowance of costs that have been deferred, financings, allowed rates of return, electricity pricing and price structures, acquisition and disposal of assets and facilities, and current or prospective wholesale and retail competition;

• Changes in the political landscape and compliance with state and federal laws, policies, and regulations, including new interpretations and enforcement initiatives by regulatory and oversight bodies, which include the Federal Energy Regulatory Commission, the North American Electric Reliability Corporation, the Western Electricity Coordinating Council, the Idaho Public Utilities Commission, the Oregon Public Utility Commission, and the Department of Energy of existing policies and regulations that affect the cost of compliance, investigations and audits, penalties, and costs of remediation that may or may not be recoverable through rates;

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

• Litigation and regulatory proceedings, including those resulting from the energy situation in the western United States and the Snake River Basin water rights adjudication, and penalties, settlements, or awards that influence business and profitability;

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

• Increases in capital expenditures and potential reductions in generation capacity as a result of regulatory conditions that may be imposed on hydroelectric power generating plant license renewals, or the non-renewal of such licenses;

• Global climate change and regional weather variations affecting customer demand and hydroelectric generation;

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

• Construction of power generation, transmission, and distribution facilities, including an inability to obtain required governmental permits and approvals, rights-of-way, and siting, and risks related to contracting, construction, and start-up;

• Delays and cost increases in connection with the construction or modification of generating facilities and other capital projects, which could result in the disallowance of recovery of certain costs pursuant to the rate determination process;

• Operation of power generating facilities, including performance below expected levels, breakdown or failure of equipment, forced outages, availability of electrical transmission capacity, and the availability of water for hydroelectric power generation, natural gas, coal, and diesel for power generation at thermal plants, and wind conditions for wind power generation, and the transmission infrastructures associated with those power generation facilities;

• Changes in operating expenses and capital expenditures, including costs and availability of materials, fuel, and commodities, and their impact on Idaho Power Company’s ability to meet required loads and on the wholesale energy market in the western United States;

• Blackouts or other disruptions of Idaho Power Company’s transmission system or the western interconnected transmission system;

• Population growth rates and changes in residential, commercial, and industrial growth and demographic patterns within Idaho Power Company’s service area;

• The continuing effects of weak economies in the states of Idaho and Oregon and in the United States, including decreased demand for electricity and reduced revenue from sales of excess energy during periods of low wholesale market prices, impaired financial soundness of vendors and service providers, and elevated levels of uncollectible customer accounts;

• Market prices and demand for energy, including structural market changes;

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

• The effectiveness of Idaho Power Company’s risk management policies concerning the creditworthiness of third parties;

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

• Increases in the costs associated with Idaho Power Company’s energy commodity and other derivative instruments, and potential higher costs of hedging activities due to governmental regulation;

• Performance of the stock market, interest rates, credit spreads, inflation, and other financial market conditions, as well as changes in government regulations, which affect, among other things, the cost of capital and the ability to access the capital markets, indebtedness obligations, the amount and timing of required contributions to pension plans, and the reported costs of providing pension and other postretirement benefits;

• Increases in health care costs and the resulting effect on medical benefits paid for employees;

• Increasing costs of insurance, changes in coverage terms, and the ability to obtain insurance on reasonable terms or at all;

• The occurrence of events that affect homeland security, and acts of war or terrorism;

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

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

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

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

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

EXECUTIVE OVERVIEW

Third Quarter 2010 Financial Results

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

	Three months ended				Nine months ended
	September 30,				September 30,
	2010		2009		2010		2009
Net income attributable to IDACORP, Inc.	$	67,135	$	54,478	$	122,407	$	100,837
Average outstanding shares – diluted (000’s)		48,252		47,141		48,062		46,999
Earnings per diluted share	$	1.39	$	1.16	$	2.55	$	2.15

The following table presents a reconciliation of net income attributable to IDACORP, Inc. for the three- and nine-month periods ended September 30, 2009 to the same periods in 2010 (items are in millions and are before tax unless otherwise noted):

				Three months						Nine months
				ended						ended
Net income attributable to IDACORP, Inc. - September 30, 2009						$	54.5				$	100.8
Change in Idaho Power net income before taxes:
	Rate and other regulatory changes, including power cost and
			fixed cost adjustment mechanisms	$	12.1			$	21.0
	Reduced sales volumes				(2.7)				(15.1)
	Oregon 2007 excess power cost deferral recorded in 2009				-				(6.4)
	Increased transmission revenues				1.0				3.8
	Increased depreciation expense				(0.3)				(4.8)
	Decreased life insurance gains				(0.5)				(4.3)
	Other				-				(3.2)
Decrease in income tax expense					4.0				34.0
Total increase in Idaho Power net income							13.6					25.0
Decreased earnings at holding company (net of tax)							(0.3)					(2.4)
Other net decreases, net of tax							(0.7)					(1.0)
		Net income attributable to IDACORP, Inc. - September 30, 2010				$	67.1				$	122.4

Idaho Power’s operating income increased $9 million for the quarter and decreased $5 million year-to-date as compared to the same periods in 2009. For the quarter, regulatory changes, resulting primarily from a January 2010 Idaho-jurisdiction settlement agreement, contributed $12 million to the increase and were partially offset by $2.7 million of sales volume reductions due in large part to mild weather. Year-to-date, the regulatory changes contributed $21 million and were partially offset by reductions in sales volumes of $15.1 million. Idaho Power’s operating income also decreased due to a $6.4 million Oregon excess power cost recovery recorded in 2009 that did not recur in 2010.

For the quarter and the year-to-date, sales volumes in customer categories other than irrigation decreased five percent compared to the same periods in 2009. Irrigation sales increased nine percent for the quarter and one percent year to-date compared to the same periods in 2009. Relatively low precipitation in Idaho Power’s service territory during the third quarter of 2010 contributed to increased sales to irrigation customers, who rely on electric power to operate irrigation systems. Mild weather contributed to the reduced electricity demand for other customers, who rely on electric power for cooling systems during the summer months. Other contributing factors include increased energy conservation and economic conditions. While there are some indicators that the economic conditions in Idaho Power’s service area are improving, overall economic conditions in the service area continue to be weak, evidenced by unemployment levels that are still relatively high and nominal customer growth year-to-date. Volume decreases were partially offset by the fixed cost adjustment (FCA) mechanism and lower power supply costs.

Other items influencing the change in Idaho Power’s net income included:

• Other transmission revenue increased $1 million and $3.8 million for the quarter and the year-to-date, respectively, due to increased transmission system revenues.

• Depreciation expense increased $0.3 million and $4.8 million for the quarter and the year-to-date, respectively, mainly due to the acceleration of depreciation expense for non-AMI meters related to Idaho Power’s conversion to Advanced Metering Infrastructure (AMI). Idaho Power has an IPUC order to collect an offsetting amount through rates.

• Other income for the quarter and the year-to-date was reduced by lower life insurance benefits, as gains recorded in 2009 did not recur in 2010.

Holding company earnings decreased $0.3 million for the quarter and $2 million year-to-date primarily due to the effects of intra-period tax allocations. In accordance with interim reporting requirements, IDACORP uses its consolidated group annual effective tax rate to determine income tax expense for the quarter, which resulted in an intra-period allocation of expense. IDACORP records this intra-period allocation at the holding company.

A decrease in the estimated annual effective tax rate, primarily resulting from a tax accounting method change for repair-related expenditures on utility assets for the 2009 tax year, significantly impacted IDACORP’s and Idaho Power’s 2010 year-to-date results. As of September 30, 2010, Idaho Power recorded a net tax benefit of $32.6 million related to the cumulative effect of the method change (tax years 1999 through 2009) and has included an annual deduction estimate in its 2010 income tax provision, which resulted in a $6.7 million net tax benefit. Idaho Power has recorded a current liability for uncertain tax positions of $14.0 million relating to the tax accounting method change for repair-related expenditures.

During the third quarter of 2010, Idaho Power also recorded a net tax benefit of $65.3 million related to Idaho Power’s method of uniform capitalization, as a result of an agreement Idaho Power reached with the Internal Revenue Service (IRS). The agreement provided that Idaho Power change its uniform capitalization method to the agreed upon method under IRS Industry Director Directive #5 with the filing of IDACORP’s 2009 consolidated federal income tax return, which IDACORP filed in September 2010. However, Idaho Power has provided a current uncertain tax position liability equal to the $65.3 million net tax benefit recorded for the uniform capitalization method change, and thus the method change had no impact on IDACORP’s or Idaho Power’s operating income in the third quarter of 2010. While Idaho Power has an agreement with the IRS for examination and tax return filing purposes, it is awaiting U.S. Congress Joint Committee on Taxation approval of its method or approval of methods filed by other similarly-situated companies under Industry Director Directive #5 before concluding that the new method is effectively settled for financial reporting purposes.

Based on its current estimates, and excluding the potential impact of the uniform capitalization method change, Idaho Power believes its return on equity in the Idaho retail jurisdiction will exceed 9.5 percent on year-end equity and does not expect the need to amortize additional accumulated deferred investment tax credits (ADITC) for 2010 as allowed under a provision of the January 2010 settlement agreement with the IPUC. The agreement allows an additional amortization of up to $25 million of ADITC only if Idaho Power’s actual rate of return on year-end equity is below 9.5 percent. Idaho Power can carry over the credit to future periods, making them available to benefit customers or shareholders in the future. Because Idaho Power does not anticipate recording additional ADITC amortization in 2010, it expects to have available $25 million of additional ADITC amortization for use in 2011.

Another provision of the settlement agreement provides that if Idaho Power’s return on year-end equity exceeds 10.5 percent in any year from 2009 to 2011, Idaho Power is required to share with Idaho customers 50 percent of any Idaho-jurisdiction earnings in excess of a 10.5 percent return on year-end equity.

Regulatory Matters

The prices that the IPUC and the Oregon Public Utility Commission (OPUC) authorize Idaho Power to charge for its retail services and the tariff rate that the Federal Energy Regulatory Commission (FERC) permits Idaho Power to charge for transmission are major factors in determining IDACORP’s and Idaho Power’s results of operations and financial condition. The IPUC and OPUC have the authority to disallow recovery of any costs that they consider unreasonable or imprudently incurred, and the FERC formula rates may be insufficient for recovery of costs incurred. Idaho Power has a number of pending or recently completed regulatory filings and resulting orders, including the following:

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

Idaho 2010 PCA: On May 28, 2010, the IPUC issued an order approving a $146.9 million decrease in the 2010 PCA, along with a base rate increase of $88.7 million, both effective June 1, 2010. The net effect of these two rate adjustments is an overall decrease in customer rates of $58.2 million, or 6.49 percent. The base rate increase reflects a $63.7 million increase in base power supply costs and a $25 million increase in general rates.

The IPUC’s order identified the use of the load growth adjustment rate (LGAR) in times of load decline as an area of contention. The LGAR is an element of the PCA formula that is intended to eliminate recovery of power supply expenses associated with load growth resulting from changing weather conditions, a growing customer base, or changing customer use patterns. On September 28, 2010, representatives of Idaho Power attended an IPUC workshop to discuss the LGAR mechanism. Idaho Power expects that the IPUC Staff will circulate a proposal relating to the LGAR in the near term; however, Idaho Power is unable to predict whether the proposal will result in any changes to the LGAR mechanism.

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

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

• Pension: The IPUC approved Idaho Power’s March 2010 request to increase rates by $5.4 million for recovery of Idaho Power’s pension plan contribution for the 2009 plan year, and Idaho Power began amortizing the related costs in June 2010.

• Advanced Metering Infrastructure: The IPUC approved Idaho Power’s March 2010 application requesting authority to increase base rates for identified customer classes by $2.4 million to recover costs relating to the AMI project.

On October 1, 2010, Idaho Power filed an application with the IPUC requesting acceptance of Idaho Power’s 2011 retirement benefit plans. If the IPUC accepts the plans, Idaho Power expects to file for recovery of the costs of the benefits package, including its $54 million pension pre-funding contribution made in September 2010.

On October 22, 2010, Idaho Power filed an application with the IPUC requesting acceptance of the company’s demand-side resources business model, which included a request for authorization to move demand response incentive payments out of the energy efficiency rider and into the PCA on a prospective basis beginning on June 1, 2011; 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; and change the carrying charge on the existing energy efficiency rider balancing account.

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

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

Annual OATT Update: On August 26, 2010, Idaho Power submitted its annual Final Information Filing (FIF) for its Open Access Transmission Tariff (OATT) on its Open Access Same-Time Information System (OASIS) Internet platform. The FIF is the computation of Idaho Power’s transmission rate for service under its OATT, which is updated annually. The new rate submitted by Idaho Power was $19.60 per kW/year, an increase from the prior $15.83 per kW/year OATT rate, and was effective as of October 1, 2010 for a period of one year. For the nine months ended September 30, 2010, revenues from the transmission rate for service under the OATT were $11 million.

Integrated Resource Plan (IRP): On October 11, 2010, the OPUC issued an order acknowledging Idaho Power’s 2009 IRP. The order directed Idaho Power, in connection with its next IRP filing, to undertake additional analysis and expand the contents with specified items, including an analysis of its Boardman to Hemingway transmission project.

Liquidity and Capital Requirements

IDACORP and Idaho Power expect to continue financing capital requirements with a combination of internally generated funds and externally financed capital. In May 2010, Idaho Power registered with the SEC the sale of 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 for the issuance and sale of up to $500 million aggregate principal amount of first mortgage bonds. On August 30, 2010, Idaho Power issued $200 million of first mortgage bonds. In September 2010, IDACORP issued 768,612 shares of its common stock at an average price of $35.21 for aggregate net proceeds of $27 million, under an existing shelf registration statement. On June 28, 2010 and September 30, 2010, IDACORP contributed $10 million and $20 million, respectively, of additional equity to Idaho Power.

Idaho Power is in a period of significant infrastructure development and has several major projects in development, including the following:

• Langley Gulch Power Plant: Langley Gulch is a natural gas-fired combined cycle combustion turbine (CCCT) generating plant with a summer nameplate capacity of approximately 300 megawatts (MW) and a winter capacity of approximately 330 MW. Construction of the plant is underway and is contracted to achieve commercial operation in November 2012. The contract contains incentives intended to advance the in-service date to July 2012. The total cost estimate for the project including allowance for funds used during construction (AFUDC) is $427 million, $146 million of which Idaho Power has incurred from the inception of the project through September 30, 2010.

• Transmission Projects: Idaho Power is pursuing the development of the Boardman-Hemingway line, a proposed 500-kiloVolt (kV) line between a station near Boardman, Oregon, and the Hemingway station, near Boise, Idaho. Idaho Power estimates total construction costs of $600 million and expects its share of the project to be between 30 and 50 percent. Idaho Power and PacifiCorp are discussing joint development of the project. Idaho Power and PacifiCorp are also pursuing the joint development of Gateway West, a project to build transmission lines between Windstar, a station located near Douglas, Wyoming, and the Hemingway station. The current estimated cost for Idaho Power’s share of the project is between $300 million and $500 million.

• Transmission Equipment Purchase and Sale Arrangements: In May 2010, Idaho Power sold to PacifiCorp a 59.0 percent interest in the 500-kV portions of transmission-related and interconnection equipment located at Idaho Power’s Hemingway station near Boise, Idaho; and PacifiCorp sold to Idaho Power a 20.8 percent interest in the 345-kV portions of transmission-related and interconnection equipment located at PacifiCorp’s Populus station.

• AMI / Smart Grid (American Recovery and Reinvestment Act of 2009 (ARRA)): Under the ARRA, in April 2010 Idaho Power finalized the grant of $47 million from the Department of Energy. This grant will match a $47 million investment by Idaho Power in smart grid technology, including AMI. Idaho Power has received approximately $15 million from the DOE as of September 30, 2010 and expects to bill and collect monthly over the estimated three-year term of the grant.

Other Issues

Water Management Issues: Power generation at Idaho Power’s hydroelectric power plants on the Snake River depends on the state water rights held by Idaho Power and the long-term sustainability of the Snake River, tributary spring flows, and the Eastern Snake Plain Aquifer (ESPA). Idaho Power continues to participate in water management issues in Idaho that may affect those water rights and resources.

Relicensing of Hydroelectric Projects: Idaho Power is actively pursuing relicensing of the Hells Canyon Complex (HCC) and Swan Falls hydroelectric projects. 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.

Environmental Matters: Long-term climate change could significantly affect Idaho Power’s business, and climate change regulations are expected to have major implications for Idaho Power and the energy industry. Idaho Power has established guidelines with goals to reduce the carbon dioxide (CO₂) emission intensity of its utility operations, intended to further prepare Idaho Power for potential legislative and/or regulatory restrictions on greenhouse gas (GHG) emissions while minimizing the costs of complying with such restrictions on Idaho Power's customers.

Idaho Power’s thermal facilities are subject to federal and/or state-promulgated (1) ambient air quality standards, including those for precursors to ozone and fine particulate matter, (2) laws and regulations limiting mercury emissions, (3) regional haze – best available retrofit technology requirements, and (4) new source review and performance standards. Idaho Power’s environmental compliance costs will continue to be significant for the foreseeable future and could increase substantially, particularly in light of proposed additional regulation at the federal and state levels.

Boardman Coal Plant: On April 2, 2010, Portland General Electric (PGE) submitted a petition to the Oregon Environmental Quality Commission (OEQC) seeking rule revisions to allow the utility to meet new environmental standards by closing the Boardman power plant in 2020. Included in the petition was a plan to install new controls and make operational changes during the remaining years the plant is in service. On June 17, 2010, the OEQC directed the Oregon Division of Environmental Quality (ODEQ) to explore additional options for early closure. On June 28, 2010, the ODEQ issued three proposals that contemplate early closure of the plant by 2020, 2018, or 2015-2016, which the ODEQ estimated would involve a capital cost of $321 million, $103 million, and $36 million, respectively. In August 2010, PGE submitted to the ODEQ a new plan that would close the Boardman plant in 2020, but contemplates additional emission reductions and would increase the aggregate cost of emissions controls relative to PGE’s previous 2020 closure plan. The ODEQ solicited public comment and held a number of public hearings on the ODEQ’s and PGE’s emission control and closure proposals throughout the month of September 2010. A final ruling is expected to be submitted to the OEQC in December 2010.

On September 28, 2010, the U.S. Environmental Protection Agency (EPA) issued a Notice of Violation to PGE, alleging that PGE has violated the New Source Performance Standards under Section III of the Clean Air Act (CAA) and operating permit requirements under Title V of the CAA at the Boardman coal-fired plant as a result of modifications made to the plant in 1998 and 2004. The Notice of Violation states the maximum civil penalties the EPA is authorized to impose under the CAA for violations of the NSPS (which range from $25,000 to $37,500 per day), but does not impose any penalties, or specify the amount of any proposed penalties with respect to the alleged violations. In the Notice of Violation, the EPA has offered PGE an opportunity to confer with the EPA about the violations cited and to present information on the specific findings of the EPA. Idaho Power intends to participate in those discussions, but at this time is unable to predict the outcome of this matter or its potential impact on Idaho Power.

Health Care Acts: The Patient Protection and Affordable Care Act and the related Health Care and Education Reconciliation Act were enacted in March 2010. The enactment of the legislation required Idaho Power to record a $0.9 million charge to income tax expense in the first quarter of 2010. Idaho Power is evaluating what other impacts, if any, the health care legislation may have on its and IDACORP’s future results of operations, cash flows, or financial positions, and if benefit plan structure changes may be necessary.

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

Pension Contribution: On September 15, 2010, Idaho Power contributed $60 million to its pension plan. The contribution was in excess of the $6 million minimum contribution required to be made in September 2010 for the 2009 plan year. Idaho Power elected to contribute more than the minimum requirement in order to bring the pension plan to a more funded position, reduce future required contributions, and reduce Pension Benefit Guaranty Corporation premiums. Unless Idaho Power elects to use an alternative amortization schedule available under new legislation, minimum required contributions to the pension plan are estimated to be $2 million, $44 million, $37 million, and $36 million in 2011, 2012, 2013, and 2014, respectively, after giving effect to the $54 million pension pre-funding contribution made in September 2010. Idaho Power may elect to make contributions earlier than the required dates.

Key Operating and Financial Metrics

IDACORP’s and Idaho Power’s outlook for 2010 full year metrics is as follows:

	2010 Estimates
	Current	Previous
Idaho Power Operation & Maintenance Expense (millions)	No change	$295-$305
Idaho Power Capital Expenditures (millions)⁽¹⁾	No change	$355-$365
Idaho Power Hydroelectric Generation (million MWh)⁽²⁾	7.0-7.5	7.0-8.0
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, the Hemingway-Bowmont transmission line, the Hemingway station, and expenditures for the siting and permitting of major transmission expansions for the Boardman to Hemingway and Gateway West transmission projects. The range does not include expenditures relating to the $47 million awarded to Idaho Power from the Department of Energy through the ARRA.
⁽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.

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 ended September 30, 2010. In this analysis, the results for 2010 are compared to the same periods in 2009.

Introduction

To provide further context to the discussion that follows, important business, economic, and other factors that have affected, and that IDACORP and Idaho Power expect will continue to affect, IDACORP’s and Idaho Power’s results of operations and financial condition are discussed below.

Regulated Rates and Cost Recovery. Idaho Power is under the retail jurisdiction (as to rates, service, accounting, and other general matters of utility operation) of the IPUC and the OPUC, and has authority to charge market-based rates for wholesale energy sales under its FERC tariff and to provide transmission services under its OATT. The prices that the IPUC and OPUC authorize Idaho Power to charge for its retail services and the tariff rate that the FERC permits Idaho Power to charge for transmission are major factors in determining IDACORP’s and Idaho Power’s results of operations and financial condition. The IPUC and OPUC have the authority to disallow recovery of any costs that they consider unreasonable or imprudently incurred, and the FERC formula rates may be insufficient for recovery of actual costs incurred. While the IPUC and OPUC have established through the ratemaking process an authorized rate of return for Idaho Power, the regulatory process does not provide assurance that Idaho Power will be able to achieve the authorized rate. Further, while the IPUC and OPUC are required to establish rates that are fair, just, and reasonable, they have significant discretion in applying this standard. Disallowance of cost recovery would have a negative effect on earnings and cash flows and could result in downgrades of IDACORP’s and Idaho Power’s credit ratings, which could increase the companies’ cost of capital and adversely impact access to the capital markets. Idaho Power has continued to focus on timely recovery of its costs through filings with the IPUC and OPUC.

Idaho Power has PCA mechanisms that provide for annual adjustments to the rates charged to its Idaho and Oregon retail customers. The PCA tracks Idaho Power’s actual net power supply costs (primarily fuel and purchased power less off-system sales) and compares these amounts to net power supply costs currently being recovered in retail rates. Most of the variance between these two amounts is deferred for future recovery from or refund to customers. Because of the PCA mechanism, the primary financial impact of power supply cost variations is on the timing of cash flows. If costs rise above the level currently recovered in retail rates it will adversely affect Idaho Power’s operating cash flow and liquidity until those costs are recovered from customers. Idaho Power also has an FCA mechanism that is designed to remove Idaho Power’s disincentive to invest in energy efficiency programs by separating (or decoupling) the recovery of fixed costs from the variable kilowatt-hour charge and linking it instead to a set amount per customer.

Idaho Power utilizes a rate structure that divides a customer’s energy usage into separate tiers and/or time periods based on how many kilowatt-hours of energy a customer uses and the time during which the energy was consumed,

and increases the cost of power consumed depending on the applicable tier and time of consumption. Customers will typically pay more for energy during periods of high demand and when the amount of usage is large enough to implicate higher rate tiers. These tiers are established by the IPUC and OPUC and are intended to promote energy efficiency and help customers identify opportunities to manage their energy usage and power bill. This rate structure can have a significant impact on Idaho Power’s results of operations compared to a flat rate structure, as revenues are more negatively impacted when customers’ usage does not reach the expected rate tier brackets and, conversely, positively impacted when customers use energy in higher tier pricing brackets and during peak demand times when power rates to customers are higher. Idaho Power also believes that the tiered rate structure may negatively impact customer perception of the company and the collectability of accounts when customers experience unexpectedly large bills due to reaching higher tier pricing brackets during months when demand for power for electric heating and cooling systems is high.

Economic Conditions. Economic conditions within and outside of Idaho Power’s service area can impact consumer demand for electricity, collectability of accounts, the volume of off-system sales due to power demand, and Idaho Power’s need for purchased power. Beginning in 2008 and through 2010 to date, economic conditions in Idaho Power’s service area have been relatively weak. Unemployment rates are high relative to historic unemployment levels and customer growth has been slow relative to prior years. Idaho Power anticipates that the residential, commercial, and industrial customer growth rate will increase when economic conditions within its service area improve.

Weather Conditions and Associated Impacts. Energy sales to Idaho Power’s customers vary from season to season primarily as a result of weather conditions and agricultural growing conditions. Relatively high and low temperatures result in greater energy usage for heating and cooling. During the growing season, irrigation customers use electricity to operate irrigation pumps. Increased precipitation during the growing season reduces electricity sales to these customers.

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

Fuel and Power Supply. In addition to hydroelectric generation, Idaho Power relies on coal, natural gas, and other fuels to fuel its generation facilities. Increases in demand for natural gas, including increases in demand due to greater industry reliance on natural gas for power generation, may result in market price increases, short-term price volatility, and/or supply availability issues. Operation of the Langley Gulch power plant that Idaho Power is currently constructing will increase Idaho Power’s demand for natural gas, and thus its exposure to volatility in natural gas prices.

Recently, Idaho Power has experienced an increase in coal prices. For 2010 year-to-date, fuel expense at the Bridger plant increased $8 million due to continued production cost increases at BCC and higher coal contract prices, and fuel expense at the Boardman plant increased $2 million due to a 53 percent increase in production. In order to help ensure the continued supply of coal for the Bridger plant, in July 2010 BCC received approval from the U.S. Bureau of Land Management (BLM) to modify its existing federal coal lease to include 560 acres of adjacent coal lands for mine development, and BCC plans to increase lease holdings on bordering private lands for a total increase of approximately 2,000 acres.

Delivery of coal and natural gas depends upon gas pipelines, rail lines, rail cars, and roadways. Any disruption in fuel supply may require Idaho Power to find alternative fuel sources at potentially higher costs, to produce power

from higher cost generation facilities, or to purchase power from other sources at higher costs. The incremental power cost is currently included in the PCA mechanisms that allow Idaho Power to recover most of these costs.

Idaho Power relies in part on purchased power to meet load requirements, and a significant component of Idaho Power’s infrastructure development is intended to increase Idaho Power’s own generation capacity and to ensure transmission capacity is sufficient to meet demand requirements. To help reduce power demand, Idaho Power has several energy efficiency programs in place and in development, targeting savings across the entire year and across a wide range of customer segments. The emphasis of these programs is to reduce energy consumption, especially during periods of high demand, and delay the need to build new supply-side alternatives. Energy efficiency activities are currently funded through a rider mechanism on customer bills in both Idaho and Oregon and are subject to disallowance if imprudently incurred.

Idaho Power 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. To mitigate a portion of the risk in these arrangements, Idaho Power has procedures that monitor compliance with risk management policies and programs, including verification of transactions, regular portfolio reporting of various risk management metrics, and daily counterparty credit risk analysis, and may establish credit and concentration limits on transactions with counterparties and require contractual guarantees, cash deposits, or letters of credit from counterparties or their affiliates, as deemed necessary.

Regulatory Compliance Costs and Expenditures. Idaho Power is subject to extensive federal and state laws, policies, and regulations, as well as regulatory actions and regulatory audits. Compliance with these requirements directly influences Idaho Power’s operating environment and may significantly increase Idaho Power’s operating costs. Further, potential monetary and non-monetary penalties for violation of applicable laws may be substantial. For instance, monetary penalties for violations of FERC regulations may be as high as $1 million per day per violation. Accordingly, Idaho Power has in place numerous compliance policies and initiatives, and frequently evaluates, updates, and supplements these policies and initiatives.

Idaho Power is also subject to a substantial body of rapidly changing regulations by federal, state, and local authorities governing the protection of the environment. Environmental laws and regulations may, among other things, increase the cost of operating power generation plants and constructing new facilities; require that Idaho Power install additional pollution control devices at existing generating plants; or require that Idaho Power shut down certain power generation plants. For instance, the Boardman coal-fired power plant, in which Idaho Power owns a ten percent interest, is the subject of proceedings with Oregon regulators relating to the installation of costly emission controls and the potential early shut-down of the facility, and in September 2010 the EPA issued a Notice of Violation to PGE, the operator of the Boardman plant, alleging CAA violations. Compliance with environmental laws and regulations will result in increases to capital expenditures and operating expenses. Idaho Power intends to seek recovery of such costs through the ratemaking process.

Idaho Power is involved in renewing federal licenses for some of its hydroelectric projects, including its largest hydroelectric generation source, the HCC. Relicensing involves numerous environmental issues. 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 expects that relicensing costs could be substantial but will be submitted to regulators for recovery through the ratemaking process.

Tax-Related Projects. In September 2010, Idaho Power adopted a tax accounting method change for repair-related expenditures on utility assets concurrent with the filing of IDACORP’s 2009 consolidated federal income tax return. Also in the third quarter of 2010, Idaho Power reached an agreement with the IRS, subject to subsequent review by the U.S. Congress Joint Committee on Taxation, regarding the allocation of mixed service costs in its method of uniform capitalization. The ultimate resolution of these tax matters and the associated regulatory treatment may have a substantial impact on IDACORP’s and Idaho Power’s financial condition and results of operations.

Results for the Three and Nine Months Ended September 30, 2010

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

		Three months ended				Nine months ended
		September 30,				September 30,
		2010		2009		2010		2009
Idaho Power – Utility operations		$	64,650	$	51,057	$	121,700	$	96,667
IDACORP Financial Services			(384)		245		(321)		574
Ida-West Energy			1,123		1,208		2,310		2,780
IDACORP Energy			(55)		(125)		96		(176)
Holding company			1,801		2,093		(1,378)		992
	Net income attributable to IDACORP, Inc.	$	67,135	$	54,478	$	122,407	$	100,837
Average common shares outstanding (diluted, in 000’s)			48,252		47,141		48,062		46,999
Earnings per diluted share		$	1.39	$	1.16	$	2.55	$	2.15

Utility Operations

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

		Three months ended		Nine months ended
		September 30,		September 30,
		2010	2009	2010	2009
General business sales		4,078	4,139	10,314	10,674
Off-system sales		235	734	1,602	2,406
	Total energy sales	4,313	4,873	11,916	13,080
Hydroelectric generation		1,687	2,013	5,887	6,574
Coal generation		1,961	1,923	4,988	4,988
Natural gas and other generation		117	193	138	215
	Total system generation	3,765	4,129	11,013	11,777
Purchased power		928	1,183	1,902	2,383
Line losses		(380)	(439)	(999)	(1,080)
	Total energy supply	4,313	4,873	11,916	13,080

For the three months ended September 30, 2010, hydroelectric generation comprised 45 percent of Idaho Power’s total system generation and 36 percent of its total energy supply. Based on current reservoir levels, forecasted stream flow, and other conditions relevant to its estimate of hydroelectric generation capacity, Idaho Power expects to generate between 7.0 and 7.5 million MWh from its hydroelectric facilities in 2010, compared to 8.1 million MWh in 2009. Idaho Power’s modeled median annual hydroelectric generation is 8.6 million MWh, based on hydrologic conditions for the period 1928 through 2009 and adjusted to reflect the current level of water resource development. Most of the incremental increase in power supply costs that typically result from reduced hydroelectric generation is recovered through the PCA.

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

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

			Three months ended				Nine months ended
			September 30,				September 30,
			2010		2009		2010		2009
Revenue
	Residential		$	99,701	$	104,040	$	295,266	$	288,243
	Commercial			63,466		68,195		176,990		173,152
	Industrial			35,907		39,812		105,975		104,164
	Irrigation			70,540		68,907		104,328		105,584
	Deferred revenue related to Hells
		Canyon relicensing AFUDC⁽⁴⁾		(3,344)		(3,278)		(8,266)		(7,325)
		Total	$	266,270	$	277,676	$	674,293	$	663,818
MWh
	Residential			1,182		1,267		3,624		3,850
	Commercial			1,002		1,043		2,813		2,893
	Industrial			780		806		2,280		2,342
	Irrigation			1,114		1,023		1,597		1,589
		Total		4,078		4,139		10,314		10,674
Customers (average)
	Residential			407,777		405,355		407,224		404,785
	Commercial			64,471		64,105		64,357		64,099
	Industrial			124		128		126		126
	Irrigation			18,637		18,855		18,625		18,729
		Total		491,009		488,443		490,332		487,739
Customers (period end)
	Residential							407,914		405,481
	Commercial							64,535		64,181
	Industrial							123		128
	Irrigation							18,611		18,845
		Total						491,183		488,635
Heating degree-days⁽¹⁾				70		54		3,111		3,227
Cooling degree-days⁽²⁾				779		980		886		1,188
Precipitation (inches)⁽³⁾				0.39		1.88		9.01		7.45
⁽¹⁾Heating and cooling degree-days are common measures used in the utility industry to analyze the demand for electricity. They indicate when a customer would likely use electricity for heating and air conditioning. A degree-day measures how much the average of the daily high and low temperature varies from 65 degrees. Each degree of temperature above 65 degrees is counted as one cooling degree-day, and each degree of temperature below 65 degrees is counted as one heating degree-day. Normal heating degree-days for the quarter and year-to-date are 137 and 3,478 degree days, respectively.
⁽²⁾Normal cooling degree-days for the quarter and year-to-date are 646 and 802, respectively.
⁽³⁾Normal precipitation for the quarter and year-to-date is 1.20 and 8.20 inches, respectively.
⁽⁴⁾As part of its February 1, 2009 general rate case order, the IPUC allowed Idaho Power to recover AFUDC for the HCC relicensing asset even though the relicensing process is not yet complete and the relicensing asset has not been placed in service. Idaho Power is collecting approximately $10.6 million annually, but is deferring revenue recognition of the amounts collected until the license is issued and the relicensing asset is placed in service.

General business revenue decreased $11 million in the third quarter of 2010 and increased $10 million year-to-date compared to the same periods in 2009. The changes are primarily attributable to the effects of rate changes and to a lesser extent reductions in customer usage attributable to mild weather and economic conditions. These factors are discussed in more detail below:

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

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

Rate changes negatively impacted general business revenue by $7 million for the quarter due to decreased PCA revenues of $42 million, partially offset by a $35 million increase in base retail rates. For the year-to-date, rates have positively impacted general business revenue by $35 million, due to increases in base retail rates of $58 million, partially offset by PCA rate decreases of $23 million.

• Usage: A decrease in usage reduced general business revenue $4 million for the quarter and $26 million year-to-date, due primarily to relatively mild weather, which decreases power demand for cooling purposes during the summer months. Sales to residential customers declined seven percent for the quarter and six percent year-to-date relative to the same periods in 2009. Idaho Power believes the decline in total MWh sales is due in part to the continued weakness of the economy and energy conservation practices in its service area. A slow economic recovery could result in continued low demand.

• Customers: Slow growth in customer count contributed to a decrease of $1 million in general business revenue for the quarter and a $2 million increase year-to-date compared to the same periods in 2009. For both the quarter and the year-to-date, total customer growth increased 0.5 percent compared to the same periods in 2009.

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 ended September 30, 2010 and 2009:

	Three months ended				Nine months ended
	September 30,				September 30,
	2010		2009		2010		2009
Revenue	$	12,070	$	23,691	$	64,245	$	78,888
MWh sold		235		734		1,602		2,406
Revenue per MWh	$	51.36	$	32.28	$	40.10	$	32.79

Off-system sales revenue decreased $12 million, or 49 percent, for the third quarter of 2010 and $15 million, or 19 percent, year-to-date as compared to the same periods of 2009 due to less favorable hydroelectric generating conditions, which reduced surplus power available for sale. Hydroelectric generation decreased 16 percent for the third quarter of 2010 and 10 percent year-to-date as compared to the same periods of 2009.

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

		Three months ended				Nine months ended
		September 30,				September 30,
		2010		2009		2010		2009
Transmission services		$	10,579	$	9,559	$	29,833	$	26,036
Energy efficiency			19,549		12,202		33,348		24,933
	Total	$	30,128	$	21,761	$	63,181	$	50,969

Transmission services revenue increased $1 million for the third quarter due to increased transmission facility revenues, and increased $4 million year-to-date due to increased transmission facility revenues and increased wheeling revenue.

Energy efficiency activities are currently funded through a rider mechanism on customer bills. Energy efficiency program expenditures are reported as an operating expense with an equal amount of revenues recorded in other revenues, resulting in no net impact on earnings. The cumulative variance between expenditures and amounts collected through the rider is recorded as a regulatory asset or liability pending future collection from or obligation to customers. A liability balance indicates that Idaho Power has collected more than it has spent and an asset balance indicates that Idaho Power has spent more than it has collected. For the quarter and the year-to-date 2010 as compared to the same periods in 2009, Idaho Power has increased its energy efficiency program expenses and matching revenues $7 million and $8 million, respectively. On September 30, 2010, Idaho Power’s energy efficiency rider balance was a regulatory asset of $17 million, and Idaho Power expects the balance to remain at this level through year end.

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

	Three months ended				Nine months ended
	September 30,				September 30,
	2010		2009		2010		2009
Purchased power expense	$	62,227	$	76,274	$	113,750	$	136,843
MWh purchased		928		1,183		1,902		2,383
Cost per MWh purchased	$	67.05	$	64.48	$	59.81	$	57.42

Purchased power expense decreased $14 million, or 18 percent, for the quarter and decreased $23 million, or 17 percent, year-to-date compared to the same periods in 2009, primarily due to lower system loads.

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

			Three months ended				Nine months ended
			September 30,				September 30,
			2010		2009		2010		2009
Expense
	Coal		$	43,418	$	35,613	$	105,248	$	96,386
	Natural gas and other			7,921		13,917		10,835		16,752
		Total fuel expense	$	51,339	$	49,530	$	116,083	$	113,138
MWh generated
	Coal			1,961		1,923		4,988		4,988
	Natural gas and other			117		193		138		215
		Total MWh generated		2,078		2,116		5,126		5,203
Cost per MWh
	Coal		$	22.14	$	18.52	$	21.10	$	19.32
	Natural gas and other			67.70		72.11		78.51		77.92
	Weighted average, all sources			24.71		23.41		22.65		21.74

Fuel expense increased $2 million, or four percent, for the quarter and $3 million, or three percent year-to-date, as compared to the same periods in 2009. For the quarter, increased coal prices at Bridger and increased production at the Boardman and Valmy plants increased expenses $8 million. This increase was partially offset by a $6 million decrease in expense at the gas-fired turbine plants, which are peaking facilities, due to lower peak loads and lower natural gas prices. For the year-to-date, fuel expense at the Bridger plant increased $8 million due to continued production cost increases at BCC and higher coal contract prices, and fuel expense at the Boardman plant increased $2 million due to a 53 percent increase in production. These increases were partially offset by decreased expense of $6 million at the gas-fired turbine plants due to lower generation.

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

		Three months ended				Nine months ended
		September 30,				September 30,
		2010		2009		2010		2009
Idaho power supply cost deferred		$	(27,742)	$	(34,501)	$	(4,459)	$	(36,505)
Oregon power supply cost deferred			(593)		-		-		(6,358)
Amortization of prior year authorized balances			7,401		36,115		59,920		87,099
	Total power cost adjustment	$	(20,934)	$	1,614	$	55,461	$	44,236

Changes in the PCA and the Oregon power cost adjustment mechanism (PCAM) decreased expenses $23 million for the quarter and increased expenses $11 million for the year-to-date compared to 2009. For the quarter, the amortization of the prior year’s deferral decreased $29 million and was partially offset by a decrease of $7 million in the current year deferral, the combined result of changes in forecast rates and base and actual power supply costs. Year-to-date, the current year Idaho-jurisdiction deferral decreased $32 million due to changes in forecast rates and base and actual power supply costs and was partially offset by a $27 million decrease in the amortization of the prior year’s deferral. In addition, in the second quarter of 2009, Idaho Power recorded the effect of an order from the OPUC that allows Idaho Power to defer for future recovery $6.4 million of costs incurred in prior years.

Other operations and maintenance expenses: Other operations and maintenance (Other O&M) expense increased $3 million for the quarter and $7 million year-to-date as compared to the same periods in 2009. One factor in the increases was an increase in pension expense of $1.6 million and $2.5 million for the quarter and year to date, respectively. Effective June 1, 2010, Idaho Power has an Idaho Public Utilities Commission (IPUC) order that allowed it to begin collection of $5.4 million of defined benefit plan contributions through rates, and a corresponding amount is recorded as expense. Several other items affected year-to-date expense, including a $1 million increase in other labor, a $1 million increase in coal plant maintenance due to the scope of maintenance outages, and a $1 million increase in transmission O&M due to increased maintenance at stations.

Income Taxes

IDACORP’s and Idaho Power’s income tax expense for the three and nine months ended September 30, 2010 decreased substantially relative to the same periods in 2009, primarily as a result of the tax accounting method change for repair-related expenditures on utility assets for the 2009 tax year discussed below. For information relating to IDACORP’s and Idaho Power’s computation of the estimated annual effective tax rate, see Note 2 – “Income Taxes” to the condensed consolidated financial statements included in this report.

An analysis of income tax expense is as follows:

		IDACORP					Idaho Power
		2010		2009			2010		2009
Three months ended September 30,
Income tax provision		$	17,489	$		13,730	$	22,100	$	18,746
Accounting method change			(7,374)			-		(7,374)		-
	Income tax expense	$	10,115	$		13,730	$	14,726	$	18,746
Effective tax rate			13.1%			20.1%		18.6%		26.9%

Nine months ended September 30,
Income tax provision		$	26,448		$	25,700	$	33,874	$	36,194
Accounting method change			(32,561)			-		(32,561)		-
Medicare Part D subsidy			903			-		903		-
	Income tax (benefit) expense	$	(5,210)		$	25,700	$	2,216	$	36,194
Effective tax rate			(4.4%)			20.3%		1.8%		27.2%

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

Tax Accounting Method Change for Repair-Related Expenditures: In June 2010, Idaho Power completed its evaluation of a tax accounting method change for its 2009 tax year that allows a current income tax deduction for repair-related expenditures on its utility assets that are currently capitalized for financial reporting and tax purposes and planned to make this method change following the automatic consent procedures with the filing of IDACORP’s 2009 consolidated federal income tax return in September 2010. Accordingly, in the second quarter of 2010, Idaho Power recorded an estimated net tax benefit of $25.2 million related to the cumulative method change adjustment (tax years 1999 through 2009) and included an annual deduction estimate in its 2010 income tax provision, which resulted in a $3.6 million net tax benefit. In conjunction with recording the estimated tax benefit for the method change adjustment, Idaho Power increased its current liability for uncertain tax positions by $9.7 million.

In September 2010, Idaho Power adopted this method concurrent with the filing of IDACORP’s 2009 consolidated federal income tax return. For the three months ended September 30, 2010, Idaho Power recorded an additional net tax benefit of $7.4 million related to the filed deduction for the cumulative method change adjustment and a $3.1 million net tax benefit for the annual deduction estimate included in its 2010 income tax provision. Idaho Power’s current liability for uncertain tax positions was also increased by $2.2 million related to the method change adjustment. The estimated annual tax deduction related to capitalized repairs produces a net tax benefit of $9 million annually, which is approximately $5 million higher than the annual amount reported in 2009. In addition, the reversal of previously deferred taxes related to the method change will offset a portion of the ongoing annual benefit.

Status of Audit Proceedings and Uniform Capitalization Method Change: In May 2009, IDACORP formally entered the IRS CAP program for its 2009 tax year. The CAP program provides for IRS examination throughout the year. In January 2010, IDACORP was accepted into the CAP program for its 2010 tax year. With the

exception of Idaho Power’s capitalized repairs method (discussed above) and uniform capitalization method (discussed below), IDACORP and Idaho Power believe there are no remaining tax uncertainties for the 2009 tax year and expect that the 2009 examination may conclude in the fourth quarter of 2010 or during fiscal year 2011. IDACORP and Idaho Power are unable to predict the outcome of the 2010 examination.

Specifically within the 2009 CAP examination, the IRS began its audit of Idaho Power’s current method of uniform capitalization. In September 2009, the IRS issued Industry Director Directive #5 (IDD), which discusses the IRS’s compliance priorities and audit techniques related to the allocation of mixed service costs in the uniform capitalization methods of electric utilities. Since that time the IRS and Idaho Power have jointly worked through the impact the IDD guidance had on Idaho Power’s uniform capitalization method and reached agreement during the third quarter of 2010. The agreement provided that Idaho Power change its uniform capitalization method to the agreed upon method under the IDD with the filing of IDACORP’s 2009 consolidated federal income tax return. Due to the method change agreement with IRS, Idaho Power reversed the uncertain tax position liability for its 2009 uniform capitalization deduction resulting in a $1.1 million tax benefit as of September 30, 2010.

The resulting tax deductions available under the agreed upon uniform capitalization method were significantly greater than Idaho Power’s prior method. For the three months ended September 30, 2010, Idaho Power recorded a net tax benefit of $65.3 million related to the cumulative method change adjustment (tax years 1986 through 2009) for this method and the current year impact. The prescribed regulatory accounting treatment for this method is the same as discussed earlier for the capitalized repairs method.

Idaho Power has also provided a current uncertain tax position liability equal to the $65.3 million net tax benefit recorded for the uniform capitalization method change. While Idaho Power has an agreement with the IRS for examination and tax return filing purposes, it is awaiting U.S. Congress Joint Committee on Taxation approval of its method or approval of methods filed by other similarly-situated companies under the IDD before concluding that the new method is effectively settled for financial reporting purposes. IDACORP and Idaho Power cannot predict exactly when such approval will materialize, but believe it is possible in the fourth quarter of 2010 or, more likely, during fiscal year 2011. The estimated annual tax deduction related to the uniform capitalization method, if approved, will produce a tax benefit that approximates the annual net tax benefit reported for the capitalized repairs method. If recognized, $61 million of the unrecognized tax benefits for uniform capitalization would affect the effective tax rate.

Cash Impacts of Tax Method Changes: IDACORP and Idaho Power will realize federal and state cash benefits associated with the 2009 capitalized repairs and uniform capitalization method changes of $33 million and $42 million, respectively. The majority of this cash benefit has been realized through reductions to cash payments that would have otherwise been owed to taxing authorities for the 2009 tax year, except for a federal refund of $24 million that is expected to be received in the fourth quarter of 2010. Additionally, approximately $9 million of state cash benefits are expected to be substantially realized through reduced tax payments for the 2010 tax year.

Tax Method Change’s Impact on Sharing: In accordance with Idaho Power’s January 2010 settlement agreement, if Idaho Power’s return on year-end equity exceeds 10.5 percent in any year from 2009 to 2011, including if one or both of the method changes were to cause return on year-end equity to exceed 10.5 percent, Idaho Power is required to share with Idaho customers 50 percent of any Idaho-jurisdiction earnings in excess of a 10.5 percent return on year-end equity.

Non-utility Operations

IFS’s earnings decreased $0.6 million for the quarter and $0.9 million year-to-date as compared to the same periods of 2009. The reductions are primarily due to lower tax benefits related to its investments in affordable housing and historic rehabilitation developments.

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 revenues (including the recovery of previously deferred costs) from sales of electricity and transmission capacity. General business revenues and the costs to supply power to general business customers are factors that have the greatest impact on Idaho Power’s operating cash flows.

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 recently focused on critical infrastructure needs that relate to system reliability and resource adequacy, and expects that total capital expenditures will be at or slightly above $1 billion from 2010 through 2012. Idaho Power also has significant future cash contribution obligations under its pension plan.

Idaho Power’s operating cash flows usually do not fully support the amount required for utility capital expenditures, particularly during periods of heavy infrastructure development as is presently occurring. Idaho Power from time to time needs to access capital markets in order to fund these needs as well as to fund maturing debt. See “Capital Requirements” below for a further discussion of Idaho Power’s current and anticipated infrastructure development requirements and associated capital expenditure estimates.

Idaho Power uses operating and capital budgets to control operating costs and optimize capital expenditures, and funds liquidity needs for capital expenditures through cash flows from continuing operations, public debt offerings, commercial paper markets, and credit facilities. General business revenues, 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 weather and water conditions and Idaho Power’s ability to obtain rate relief to cover its operating costs and provide a return on investment. Idaho Power seeks to recover its operating costs and earn a return on its capital expenditures through rates, periodically filing for rate adjustments for recovery of operating costs and capital investments to provide the opportunity to align Idaho Power’s earned returns with those allowed by regulators. IDACORP and Idaho Power expect to continue financing capital requirements with a combination of internally generated funds and externally financed debt and equity capital.

IDACORP’s and Idaho Power’s access to long-term and short-term debt markets, including their respective $100 million and $300 million credit facilities, helps provide necessary liquidity to support operating activities. In addition to access to its credit facility, IDACORP currently has approximately $547 million remaining on its shelf registration statement that can be used for the issuance of debt securities and common stock. IDACORP has a sales agency agreement with BNY Mellon Capital Markets, LLC where 1.4 million shares of common stock remain available to be sold from time to time in at-the-market offerings, which expires in December 2010. Idaho Power currently has $300 million remaining on its shelf registration statement that can be used for the issuance of first mortgage bonds and debt securities. On June 17, 2010, Idaho Power entered into a selling agency agreement with ten banks for the issuance and sale of up to $500 million aggregate principal amount of first mortgage bonds, $200 million in principal amount of which were issued in August 2010. IDACORP and Idaho Power also meet short-term liquidity requirements through the issuance of commercial paper, which under recent commercial paper market conditions has been a relatively low-cost, flexible, borrowing option. While short-term borrowing costs have not been significant to date, any future uncertainty in the credit markets may result in increased costs for commercial paper borrowings or limit the ability to issue commercial paper, which may increase IDACORP’s and Idaho Power’s reliance on their respective credit facilities for short-term liquidity purposes.

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

Operating Cash Flows

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

IDACORP’s and Idaho Power’s operating cash inflows for the nine months ended September 30, 2010, were $223 million and $196 million, respectively. Idaho Power’s operating cash flows decreased by $12 million compared to the nine months ended September 30, 2009 and IDACORP’s operating cash flows were the same for the nine months ended September 30, 2010 and 2009. 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 Idaho Power’s operating cash flows in the first nine months of 2010 and 2009 are discussed below:

• A $60 million contribution was made to the defined benefit pension plan in 2010. No contribution to this plan was made in 2009.

• Idaho Power’s net payments made to IDACORP for income tax were $22 million for the nine months ended September 30, 2010, as compared with net payments received from IDACORP of $12 million for the nine months ended September 30, 2009.

• Changes in retail customer accounts receivable and unbilled revenue balances increased cash flows by $30 million. Higher balances caused by a colder December 2009 increased collections in 2010 of prior year sales by $19 million as compared with 2008 sales collected in 2009. A decrease in period-ending accounts receivable and unbilled revenue balances as compared with September 30, 2009 resulted in a lower amount of current period sales carried over to be collected in a later period, improving cash flows by $11 million.

• Changes in accounts payable increased operating cash flows by $21 million as accounts payable relating to 2008 operating expenses were higher than 2009 expenses paid in 2010.

• In the first quarter of 2009, $13 million of refunds were made to Idaho Power’s transmission customers upon a final order from the FERC on Idaho Power’s OATT.

• Changes in regulatory assets associated with the PCA and the PCAM improved cash flows by $11 million, as Idaho Power deferred $38 million less of excess net power supply costs but also collected $27 million less of previously deferred costs as compared with the first nine months of 2009.

IDACORP’s net income tax payments made were $1 million for the nine months ended September 30, 2010, as compared with net income tax payments received from taxing authorities of $21 million for the nine months ended September 30, 2009. These amounts include net refunds totaling $1 million and $21 million for 2010 and 2009, respectively, from the settlement of audits for tax years prior to 2009. The cash tax benefits for the 2009 income tax returns, including the two tax method changes, are expected to be substantially realized by the end of 2010 either in the form of refunds or through the reduction of current tax payment requirements. As discussed in “Results of Operations – Income Taxes,” IDACORP expects to receive a $24 million federal tax refund for 2009 during the fourth quarter of 2010.

Pension Funding: During the third quarter of 2010, Idaho Power made a $60 million contribution to its pension plan. The contribution was $54 million in excess of the $6 million minimum contribution required to be made in 2010 for the 2009 plan year. The higher contribution amount was made to increase the funded position of the plan, to reduce required Pension Benefit Guaranty Corporation premiums, and to reduce future minimum required contributions. For at least the period 2011 to 2014, Idaho Power expects to make additional significant cash contributions to its pension plan and has significant obligations under other postretirement benefit plans.

The funded status of the pension and other postretirement benefit obligations refers to the difference between plan assets and estimated obligation of the plan. The calculation of funding requirements for pension plans requires election of a methodology to determine the actuarial value of assets and the interest rate used to measure the

pension liabilities. The funded status may change over time due to several factors, including contribution levels, assumed discount rates and actual and assumed rates of return on plan assets. IDACORP and Idaho Power continuously monitor available and proposed pension funding guidance and financial market conditions and their impact on the pension plan, and evaluate the potential impact on funding requirements and strategies.

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

Investing Cash Flows

Cash flows from investing activities consist primarily of capital expenditures related to new construction and improvements to Idaho Power’s distribution, transmission, and generation facilities. IDACORP’s and Idaho Power’s investing cash outflows were $231 million and $222 million, respectively, for the nine months ended September 30, 2010. These amounts were an increase in outflows of $83 million and $71 million, respectively, compared to the nine months ended September 30, 2009. Investing cash outflows for 2010 were primarily for construction of utility infrastructure needed to address Idaho Power’s peak demand growth, aging plant and equipment, and forecasted customer growth. Construction expenditures were partially offset by proceeds from the sale of $19 million of transmission-related assets to PacifiCorp.

Financing Cash Flows

Financing activities provide supplemental cash for both day-to-day operations and capital requirements as needed. Idaho Power funds liquidity needs for capital investment, working capital, energy and price hedging, and other financial commitments through cash flows from continuing operations, public debt offerings, commercial paper markets, and credit facilities. IDACORP 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 inflows for the nine months ended September 30, 2010, were $140 million and $183 million, respectively. These amounts were an increase in inflows of $195 million and $223 million, respectively, compared to the nine months ended September 30, 2009.

The following are significant items that affected financing cash flows in 2010:

• On August 30, 2010, Idaho Power issued $100 million of 3.40% First Mortgage Bonds, Secured Medium-Term Notes, Series I due 2020 and $100 million of 4.85% First Mortgage Bonds, Secured Medium-Term Notes, Series I due 2040 under an existing shelf registration statement.

• IDACORP sold 768,612 shares of common stock in September 2010 at an average price of $35.21 for aggregate net proceeds of $27 million, under an existing shelf registration statement.

• IDACORP and Idaho Power paid cash dividends of $43 million.

• IDACORP made a net repayment of $50 million of commercial paper.

• Idaho Power received two capital contributions totaling $30 million from IDACORP.

Idaho Power has $120 million of first mortgage bonds that mature in the first quarter of 2011. Idaho Power expects to use a portion of the proceeds from the August 2010 first mortgage bond issuance to repay those first mortgage bonds at maturity.

Shelf Registrations and Debt and Equity Issuances: IDACORP has approximately $547 million remaining on its shelf registration statement that can be used for the issuance of debt securities and common stock. IDACORP also has a sales agency agreement with BNY Mellon Capital Markets, LLC pursuant to which it may sell common stock from time to time in at-the-market offerings. Under the current agreement, IDACORP sold 768,612 shares in September 2010 at an average price of $35.21 for aggregate net proceeds of $27 million. As of September 30, 2010, there were 1.4 million shares remaining available to be sold under the sales agency agreement. The sales agency agreement terminates on December 5, 2010.

On June 17, 2010, Idaho Power entered into a Selling Agency Agreement with Banc of America Securities LLC; BNY Mellon Capital Markets, LLC; J.P. Morgan Securities Inc.; KeyBanc Capital Markets Inc.; Merrill Lynch, Pierce, Fenner & Smith Incorporated; Mitsubishi UFJ Securities (USA), Inc.; RBC Capital Markets Corporation; SunTrust Robinson Humphrey, Inc.; U.S. Bancorp Investments, Inc.; and Wells Fargo Securities, LLC in connection with the potential issuance and sale from time to time of up to $500 million aggregate principal amount of first mortgage bonds under a shelf registration statement. On August 30, 2010, Idaho Power issued $100 million of 3.40% First Mortgage Bonds, Secured Medium-Term Notes, Series I due 2020, and $100 million of 4.85% First Mortgage Bonds, Secured Medium-Term Notes, Series I due 2040 under the selling agency agreement. Idaho Power expects to use the net proceeds from the sale of the first mortgage bonds to pay at maturity its $120 million 6.60% first mortgage bonds due March 2, 2011 and to fund a portion of the company’s capital requirements. As of September 30, 2010, $300 million remained on Idaho Power’s shelf registration for the issuance of first mortgage bonds and debt securities.

The issuance of first mortgage bonds requires that Idaho Power meet interest coverage and security provisions set forth in the Indenture of Mortgage and Deed of Trust securing the bonds. Future issuance of first mortgage bonds are subject to satisfaction of covenants and security provisions set forth in the Indenture of Mortgage and Deed of Trust securing the bonds, market conditions, regulatory authorizations, or by covenants and tests contained in other financing agreements. As a result of restrictions in the Indenture of Mortgage and Deed of Trust, as of September 30, 2010, Idaho Power could issue approximately $355 million of additional first mortgage bonds based on total unfunded property additions of approximately $592 million. Idaho Power could issue an additional $612 million of first mortgage bonds based on retired first mortgage bonds. 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, 2010 was limited to approximately $415 million.

Credit Facilities: IDACORP and Idaho Power each have a five-year credit agreement that terminates on April 25, 2012, subject to one year extensions, to be used for general corporate purposes and commercial paper back-up, and that provide for the issuance of loans and standby letters of credit. Each facility contains a covenant requiring a leverage ratio of consolidated indebtedness to consolidated total capitalization of no more than 65 percent as of the end of each fiscal quarter. In determining the leverage ratio, “consolidated indebtedness” broadly includes all indebtedness of the respective borrower and its subsidiaries, excluding indebtedness evidenced by certain hybrid securities (as defined in the credit agreement). “Consolidated total capitalization” is calculated as the sum of all consolidated indebtedness, consolidated stockholders’ equity of the borrower and its subsidiaries, and the aggregate value of outstanding hybrid securities. At September 30, 2010, the leverage ratios for IDACORP and Idaho Power were 52 percent and 54 percent, respectively. IDACORP’s and Idaho Power’s ability to utilize the credit facilities is subject to continued compliance with the leverage ratio covenants included in the credit facilities, which could limit the ability of the companies to issue first mortgage bonds and debt securities pursuant to current and future shelf registration statements. At September 30, 2010, IDACORP and Idaho Power were in compliance with all facility covenants.

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

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

Revolving credit facility		$	100,000	$	300,000	$	100,000	$	300,000
Commercial paper outstanding			(4,000)		-		(53,750)		-
Identified for other use ⁽¹⁾			-		(24,245)		-		(24,245)
	Net balance available	$	96,000	$	275,755	$	46,250	$	275,755
⁽¹⁾ Port of Morrow and American Falls bonds that holders may put to Idaho Power.
⁽²⁾ Holding company only.

At October 22, 2010, IDACORP had no loans under its credit facility and $2 million of commercial paper outstanding, and Idaho Power had no loans under its credit facility and no commercial paper outstanding.

The following table presents additional information about short term borrowing during the periods:

		Three months ended			Nine months ended
		September 30,			September 30,
		2010			2010
		Idaho Power		IDACORP		Idaho Power		IDACORP
Commercial paper:
Period end:
	Amount outstanding	-	$	4,000		-	$	4,000
	Weighted average interest rate	-		0.46%		-		0.46%
Daily average amount outstanding for the reporting period		-	$	12,680	$	465	$	18,219
Weighted average interest rate		-		0.45%		0.43%		0.40%
Maximum month-end balance		-	$	15,200	$	5,500	$	28,780

Impact of Credit Ratings on Liquidity

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

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

Effective October 12, 2010, the letter agreement between IDACORP, Idaho Power, and Fitch Ratings (Fitch), pursuant to which Fitch agreed to provide IDACORP and Idaho Power with credit rating services for certain of

IDACORP’s and Idaho Power’s securities, expired, and IDACORP and Idaho Power elected to not renew the letter agreement for a subsequent term. IDACORP’s and Idaho Power’s non-renewal of the letter agreement was not the result of any disagreement with Fitch, but was the result of cost-cutting measures initiated by IDACORP and Idaho Power.

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

Idaho Power maintains margin agreements relating to its wholesale commodity contracts that allow performance assurance collateral to be requested of and/or posted with certain counterparties. As of September 30, 2010, Idaho Power had posted approximately $4 million of assurance collateral. Should Idaho Power experience a reduction in its credit rating on Idaho Power’s unsecured debt to below investment grade Idaho Power could be subject to additional requests by its wholesale counterparties to post additional performance assurance collateral. Counterparties to derivative instruments and other forward contracts could request immediate payment or demand immediate ongoing full daily collateralization on derivative instruments and contracts in net liability positions. Based upon Idaho Power’s current energy and fuel portfolio and market conditions as of September 30, 2010, the approximate amount of additional collateral that could be requested upon a downgrade to below investment grade is approximately $18 million. Idaho Power actively monitors the portfolio exposure and the potential exposure to additional requests for performance assurance collateral calls, through sensitivity analysis, to minimize capital requirements.

Capital Requirements

Idaho Power expects that total capital expenditures will be at or slightly above $1 billion from 2010 through 2012. Internal cash generation after dividends is expected to provide less than the full amount of total capital requirements during that period. To fund in part Idaho Power’s capital requirements, Idaho Power issued $200 million of first mortgage bonds in August 2010, a portion of the net proceeds of which Idaho Power intends to use to repay $120 million of debt maturing in the first quarter of 2011. In September 2010, IDACORP sold 768,612 shares of its common stock for aggregate net proceeds of approximately $27 million. In June and September 2010, IDACORP made capital contributions to Idaho Power in an aggregate amount of $30 million. Beyond 2010, IDACORP and Idaho Power expect to continue financing capital requirements with a combination of internally generated funds and externally financed capital.

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

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

Langley Gulch Power Plant: The Langley Gulch Power Plant is a natural gas-fired CCCT generating plant with a summer nameplate capacity of approximately 300 MWs and a winter capacity of approximately 330 MWs. Construction of the plant is underway. The plant is being constructed near New Plymouth, Idaho and is contracted to achieve commercial operation by November 1, 2012. Incentives are anticipated to advance the commercial operation date to July 1, 2012. The total cost estimate for the project including AFUDC is $427 million, $146 million of which Idaho Power has incurred from inception in 2009 through September 30, 2010. The plant will connect to Idaho Power's existing grid. During 2010, Idaho Power received an air quality permit to construct and

commenced construction. Construction activities have included mobilization, earthwork, and underground electrical ductbank and piping. Idaho Power completed work on permitting in the third quarter of 2010, with the U.S. Bureau of Land Management (BLM) granting rights of way for water pipelines and transmission lines on October 4, 2010.

Other Major Projects:

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

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

Hemingway-Bowmont Transmission Line: The Hemingway-Bowmont transmission line consists of 13 miles of new 230-kV transmission line that will provide power to the Treasure Valley in southwest Idaho. The project was placed in service in 2010 at a total cost of approximately $16 million. The 2010 cost estimate for the project was $6.5 million and is included in the above table.

Boardman-Hemingway Line: The Boardman-Hemingway Line is a proposed 299-mile, 500-kV transmission project between a station near Boardman, Oregon and the Hemingway station. This line will provide transmission service to meet needs identified in the 2009 Integrated Resources Plan (IRP) and other requests pursuant to Idaho Power’s OATT. The Oregon Energy Facility Siting Council process and the National Environmental Policy Act process have been restarted. Public scoping meetings were held in August and the comment period ended on September 27, 2010. The Oregon Department of Fish and Wildlife (ODF&W) is working with Idaho Power to minimize the impact of the conservation plan for the greater sage grouse on the proposed route. The cost of the initial phase of the project is estimated at $50 million and the 2010 to 2012 cost estimate is included in the table above. Total cost estimates for the project are approximately $600 million. Idaho Power expects its share of the project to be between 30 and 50 percent. Construction costs beyond the initial phase are not included in the table above. This project is expected to be completed in 2015, subject to siting, permitting, and regulatory approvals. Idaho Power expects to receive a draft environmental impact statement (EIS) from the BLM relating to the project in early 2012. Idaho Power will continue to work with ODF&W and other agencies to address environmental issues, including proposed lawmaking relating to sage grouse in Oregon, which could delay the project, alter the proposed siting, and result in significantly higher costs.

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

AMI / Smart Grid (American Recovery and Reinvestment Act of 2009 (ARRA)): The AMI project provides the means to automatically retrieve energy consumption information, eliminating manual meter reading expense. Idaho Power intends to install this technology for approximately 99 percent of its customers and is on pace to complete the installations by the end of 2011. As of September 30, 2010, Idaho Power had installed approximately 315,000 AMI meters. On May 28, 2010, the IPUC approved Idaho Power’s request to include the 2010 AMI investment in its rate base. The requested increase to rates of approximately $2.4 million was effective June 1, 2010. The total cost estimates for the project are approximately $74 million. The 2010 and 2011 costs are included in the table above.

Under the ARRA, Idaho Power was awarded a grant of $47 million from the Department of Energy (DOE). This grant matches a $47 million investment by Idaho Power in Smart Grid technology, including AMI. The grant was signed by the DOE on April 2, 2010. Idaho Power has received approximately $15 million from the DOE as of September 30, 2010 and expects to bill and collect monthly over the term of the three-year contract. The grant amount is not included in the table above.

Memorandum of Understanding and Related Transactions with PacifiCorp:

Memorandum of Understanding: On March 5, 2010, Idaho Power and PacifiCorp entered into a Memorandum of Understanding (MOU) under which Idaho Power and PacifiCorp agreed to negotiate in good faith to reach arrangements pertaining to the sale by the parties to one another of an undivided ownership interest in certain transmission facilities, and joint development and construction of three transmission projects. The parties also agreed to negotiate in good faith to reach arrangements pertaining to interconnection of their respective systems; joint ownership, operation, and maintenance of the systems; cost-sharing; capital improvements; and each party’s rights to a specified transmission capacity on applicable transmission lines. The MOU further provides that Idaho Power and PacifiCorp will negotiate in good faith to attempt to reach an agreement to terminate existing transmission capacity rights agreements over portions of Idaho Power’s existing transmission system and replace them with new agreements, if required. On July 29, 2010, Idaho Power and PacifiCorp mutually agreed to extend the final date to execute and deliver definitive agreements under the MOU from September 1, 2010 to November 5, 2010. Idaho Power anticipates that the parties will extend the timeframe to complete the negotiations into 2011. The MOU may be terminated by either party at any time.

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

The Hemingway and Populus stations are owned and operated in accordance with separate Joint Ownership and Operating Agreements (Operating Agreements), each dated May 3, 2010. The Operating Agreements include terms relating to the obligations of Idaho Power and PacifiCorp as the operators of the Hemingway and Populus stations, respectively, including, among other items, construction of additional transmission and interconnection equipment at the stations, cost sharing, operation and maintenance, and interconnection and energizing of the transmission systems. On May 10, 2010, Idaho Power and PacifiCorp filed the Operating Agreements with the FERC, requesting that the FERC determine that the rates that Idaho Power and PacifiCorp were imposing on one another pursuant to the Operating Agreements were just and reasonable. On July 9, 2010, following the filing of an intervention and protest by the Bonneville Power Administration, the FERC issued an order finding that the terms, conditions, and rates in the Operating Agreements were just and reasonable, and accepted the Operating Agreements for filing effective July 10, 2010.

Environmental Regulation Costs

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

Other Capital Requirements

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

Contractual Obligations

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

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

• In 2010, Idaho Power entered into several power purchase agreements with wind and other alternate energy developers. Payments pursuant to these agreements are expected to total approximately $493 million from 2011 to 2031.

• On August 30, 2010, Idaho Power issued $100 million of its 3.40% First Mortgage Bonds, Secured Medium-Term Notes, Series I due November 1, 2020 and $100 million of its 4.85% First Mortgage Bonds, Secured Medium-Term Notes, Series I due August 15, 2040, pursuant to an existing shelf registration statement.

• On September 15, 2010, Idaho Power made a $60 million contribution to its pension plan. The contribution was $54 million in excess of the $6 million minimum contribution required to be made in 2010 for the 2009 plan year. The excess contribution affected the company’s future obligations by reducing the pension funding requirements by an aggregate of $45 million for 2011-2012 and $6 million for 2013-2014.

• As of September 30, 2010, Idaho Power had increased its current liability for uncertain tax positions for two tax accounting method changes it completed with the filing of IDACORP’s 2009 consolidated federal income tax return in September 2010. If the liability is realized, estimated federal and state income tax payments of $50.7 million could be due as early as 2011.

Dividends

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

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

REGULATORY MATTERS:

Overview

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

Idaho Power has continued to focus on timely recovery of its costs through filings with the IPUC and OPUC. Discussed below are filings and important regulatory determinations that have been recently made. Regulatory matters and the financial impact of rate decisions are also discussed in “Results of Operations” of this MD&A and in Note 3 - “Regulatory Matters” to the condensed consolidated financial statements included in this report.

Oregon and Idaho Deferred Net Power Supply Costs

A summary of the changes in deferred power supply costs during the nine months ended September 30, 2010 is set forth in Note 3 - “Regulatory Matters” to the condensed consolidated financial statements. The net decrease of $58 million in Idaho Power’s balance of deferred power supply costs from December 31, 2009 to September 30, 2010 is predominantly a result of the recovery of $60 million through rates.

Idaho Regulatory Matters in 2010

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

• A general rate moratorium in effect until January 1, 2012. The moratorium does not apply to other specified revenue requirement proceedings, such as the PCA, the FCA, pension funding, AMI, energy efficiency rider, and government imposed fees.

• A provision to share with Idaho customers 50 percent of any Idaho-jurisdiction earnings in excess of a 10.5 percent return on equity in any calendar year from 2009 to 2011.

• A provision to allow additional amortization of ADITC if Idaho Power’s actual return on year-end equity in its Idaho jurisdiction is below 9.5 percent in any calendar year from 2009 to 2011. Idaho Power is permitted to amortize additional ADITC in an amount up to $45 million over the three-year period, but could use no more that $15 million in any one year unless there is a carryover. Carryover amounts are added to the $15 million annual allowance up to a maximum amortization of $25 million in any one year.

Because Idaho Power’s 2009 Idaho-jurisdiction return on year-end equity was between 9.5 and 10.5 percent, the sharing and additional amortization provisions were not triggered in 2009, and the ADITC available for accelerated additional amortization in 2010 is $25 million. Idaho Power recorded additional ADITC amortization of $4.5 million in the first quarter of 2010, but reversed the entire $4.5 million in the second quarter based on updated estimates of annual 2010 return on equity. Idaho Power does not currently anticipate recording additional ADITC amortization in the remainder of 2010, and thus expects to have available $25 million of additional ADITC amortization for use in 2011, in accordance with the settlement.

On January 19, 2010, Idaho Power filed with the IPUC a request to reestablish base net power supply costs with an increase of $74.8 million in the Idaho jurisdiction. On April 13, 2010, the IPUC found that adjustments for

PURPA contracts ($7.1 million) and the Hoku contract ($4.0 million) as proposed by the IPUC Staff were reasonable reductions to Idaho Power’s proposed base net power supply expenses. The remaining amount of $63.7 million was approved as a working number for Idaho Power’s 2010 PCA filing, but the IPUC deferred final calculation of authorized base net power supply expenses to the 2010 PCA case. Remaining at issue in the settlement was a $24.9 million increase in coal costs at the Bridger plant, which was first raised as an area for review by the OPUC Staff, which review has concluded. In May 2010, the IPUC issued an order approving the $63.7 million increase in base net power supply expenses and cost recovery in full in the Idaho jurisdiction in connection with Idaho Power’s 2010 PCA filing and order, discussed below.

2010 PCA Filing and Order: On April 15, 2010, Idaho Power filed its annual application with the IPUC to implement new PCA rates to be effective June 1, 2010 through May 31, 2011, and to change base rates, pursuant to the terms of the Idaho settlement agreement. Idaho Power’s application stated that the proposed PCA computations result from the stipulation approved by the IPUC in its order issued in January 2010, which provides for a sharing between customers and Idaho Power shareholders of any PCA rate reduction that results from the 2010 PCA. The January 2010 stipulation provides that PCA rates will be reduced by the full calculated amount and that base rates will be increased in an amount that partially offsets the PCA decrease. On May 28, 2010, the IPUC issued its order approving a $146.9 million decrease in the PCA, along with a base rate increase of $88.7 million. The net effect of these two rate adjustments is an overall decrease in customer rates of $58.2 million, or 6.49 percent, effective June 1, 2010. The $88.7 million base rate increase reflects a $63.7 million increase in base power supply costs and a $25 million increase in base rates. Idaho Power’s PCA application was approved as filed with the IPUC, with the exception of a $0.2 million interest expense adjustment relating to base power supply costs.

The IPUC’s order identified the following two specific items of contention raised by certain industrial customers of Idaho Power: (1) the prudency of Idaho Power’s determination of coal costs for the Jim Bridger plant, and (2) the use of the LGAR in times of load decline. The LGAR is an element of the PCA formula that is intended to eliminate recovery of power supply expenses associated with load growth resulting from changing weather conditions, a growing customer base, or changing customer use patterns. The IPUC approved the full Jim Bridger coal costs included in the base level power supply costs and the amount included in Idaho Power’s PCA forecast, finding that Idaho Power had met its burden of proof to establish the reasonableness of the coal costs to be included in the base level power supply costs. With regard to the LGAR, Idaho Power’s true-up calculation for the PCA included an increase of $21.3 million for the decline in load growth for the Idaho jurisdiction. The intervening parties asserted that use of the LGAR in times of load decline is inappropriate in that it results in potential double recovery. However, the IPUC Staff recommended no change to the load growth adjustment amounts or methodology, and the IPUC did not remove the LGAR adjustment to the PCA component. The IPUC’s order stated, however, that it expects the IPUC Staff, Idaho Power, and interested parties to meet to address an appropriate change to the LGAR mechanism to eliminate a potential double recovery when loads decline. On September 28, 2010, representatives of Idaho Power and two other utilities, and a representative of Idaho Power’s industrial customers, attended an IPUC workshop to discuss the LGAR mechanism. Idaho Power expects that the IPUC Staff will circulate a proposal relating to the LGAR in the near term; however, Idaho Power is unable to predict whether the proposal will result in any changes to the LGAR mechanism.

Other 2010 IPUC Filings and Orders:

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

• Fixed Cost Adjustment: In March 2007, the IPUC approved the implementation of a FCA pilot program for Idaho Power’s residential and small general service customers. The FCA is a rate mechanism designed to remove Idaho Power’s disincentive to invest in energy efficiency programs by separating (or decoupling) the recovery of fixed costs from the variable kilowatt-hour charge and linking it instead to a set amount per customer. The FCA allows Idaho Power to recover the difference between certain fixed costs recovered in rates and the fixed costs authorized for recovery in Idaho Power’s most recent rate case. The pilot program began on January 1, 2007 and ended on December 31, 2009. On April 29, 2010, the IPUC approved a two-year extension of the FCA pilot program, effective retroactively to January 1, 2010. For the three and nine months ended September 30, 2010, Idaho Power accrued revenues of $3.1 million and $6.5 million, respectively, under the FCA.

On March 15, 2010, Idaho Power filed an application with the IPUC requesting authorization to implement FCA rates for electric service from June 1, 2010 through May 31, 2011. On May 28, 2010, the IPUC issued an order approving Idaho Power’s request. The rate adjustments are expected to result in collection of an additional $3.6 million over currently billed amounts during the period from June 1, 2010 to May 31, 2011. In its order, the IPUC reiterated a statement in its prior order that making the FCA permanent is premature, and that during the two year extension of the FCA program it expects additional data to develop, giving interested parties and customers time to evaluate the FCA and address issues of concern.

On June 4, 2010, Idaho Power filed with the IPUC a revised tariff sheet for its FCA rates, containing updated values for fixed cost per customer and fixed cost per energy to recognized IPUC-approved changes in base rates that went into effect June 1, 2010. The application requested a net increase for recovery of fixed costs of $8.8 million over 2008 figures, the year of Idaho Power’s most recent general rate case, applicable to deferral balances beginning on June 1, 2011 for residential and small general service customers. In August 2010, the IPUC Staff filed comments with the IPUC citing concerns with the methodology used by Idaho Power and outlining an alternative proposal. Idaho Power is unable to predict the outcome of this matter.

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

The IPUC’s order provided that the allowance of recovery of the 2009 pension plan contribution does not guarantee that the IPUC will similarly approve recovery of future pension contributions without evidence that Idaho Power has evaluated alternatives to reduce the burden placed on customers. The IPUC stated in its order that “Idaho Power is advised that, previous orders notwithstanding, approval of Idaho Power’s pension contributions in this case does not guarantee IPUC approval of future pension plan contributions. Authority for the balancing account and regulatory account remain in place. However, further justification is required before additional rate recovery for future contributions will be authorized.”

Idaho Power considers its retirement-related benefits to be a competitive package that supports employees’ financial needs in retirement while appropriately sharing the market risk between Idaho Power and its employees, and believes that the benefits package allows Idaho Power to recruit and retain a highly skilled workforce. Since the issuance of the IPUC’s order, Idaho Power undertook its annual review of its current retirement benefits packages, which included a thorough review of costs, benefits, and risks associated with the retirement benefits package, and considered alternatives to its pension plan and the weighting of plans between defined benefit and defined contribution. Following that analysis, in September 2010 Idaho Power’s board of directors voted to make changes to the defined benefit plan for persons hired on or after January 2, 2011 that would reduce the estimated annual cost of the plan for those employees by 13 percent. Costs savings from the change will begin in 2011 and are expected to increase over time as a larger proportion of Idaho Power’s workforce becomes subject to the new benefits calculation. On October 1, 2010, Idaho Power filed an application with the IPUC requesting an order accepting Idaho Power’s 2011 retirement benefits package on or before February 28, 2011. Idaho Power’s application did not request recovery through rates of additional pension plan contributions. If the IPUC approves the application, Idaho Power will prepare a further application requesting recovery of pension plan contributions through rates.

Idaho Power records its deferred pension expense as a regulatory asset. As of September 30, 2010, Idaho Power has a regulatory asset of $3.6 million remaining from the initial $5.4 million of Idaho jurisdiction amount approved for recovery as discussed above. In addition, Idaho Power has Idaho jurisdiction regulatory assets associated with deferred pension expenses of $52.6 million that the IPUC has not approved or denied for recovery. If the IPUC were to determine that future pension contributions were not reasonable and prudently incurred, Idaho Power would be required to write off some or all of the balance of its deferred pension expense for its Idaho jurisdiction. Idaho Power has determined, based on its evaluation, that these Idaho jurisdiction regulatory assets are probable of recovery.

On September 15, 2010, Idaho Power made a $60 million pension contribution - its required $5.8 million minimum contribution for the 2009 plan year, plus $54.2 million to pre-fund future pension funding obligations. This pre-funding contribution creates a pre-funding balance that can be used to offset future minimum required contributions, and results in an increased funding balance, which avoids unfavorable implication under covenants and ERISA plan limitations that are triggered when the funding target balance falls below specified levels. The additional contributions also increase the “expected return on assets” component of net periodic pension expense and decrease variable premiums payable to the Pension Benefit Guaranty Corporation by an estimated $0.5 million for the 2010 plan year, and may favorably impact premiums in subsequent years based on the funded status of the plan in subsequent years.

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

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

Idaho Energy Efficiency Programs:

Idaho Power’s energy efficiency rider is the funding mechanism for Idaho Power’s investment in energy efficiency, conservation, and demand response programs. In two separate orders issued in February 2009 and April 2010, the IPUC approved for ratemaking purposes the energy efficiency rider expenditures, totaling $29 million, Idaho Power made from 2002 through 2007.

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

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

Demand-Side Resources Filing: 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:

• move demand response incentive payments out of the energy efficiency rider and into the PCA on a prospective basis beginning on June 1, 2011, and thus subject to a true-up under the PCA mechanism;

• 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

• change the carrying charge on the existing energy efficiency rider balancing account (from the current interest rate of 1.0 percent to Idaho Power’s authorized rate of return).

Absent IPUC approval of Idaho Power’s proposed modifications, Idaho Power predicts that, based on forecasted revenues and demand-side resource expenditures, the estimated balance of the energy efficiency rider would move from a negative $17 million balance at the end of 2010 to a negative $30 million balance in 2012, and with acceptance of the proposed modifications would approach $0 in mid-2012. Idaho Power’s application did not request a change in customer rates.

Eligibility Limits for Larger Customers. On August 26, 2010, Idaho Power filed an application with the IPUC requesting an order authorizing a reduction in the upper eligibility limit for large power service, agricultural irrigation service, and point of delivery service requirements from 25 MW to 20 MW. The reduction in the eligibility limit would permit these customers to make special contract arrangements with Idaho Power. By lowering the size limit, Idaho Power can better address service to growing or new load within a special contract, allowing for specific cost-of-service information as well as the unique operating characteristics of customers of this size to be considered and captured within the terms of the agreement. In its application, Idaho Power stated that it has approximately 75 potential new customers system wide with loads greater than 1 MW that have expressed interest in obtaining service from Idaho Power. Some of those potential new customers have indicated that their expected load may exceed 20 MW.

Transmission Cost Deferral Filing: In July 2009, Idaho Power filed an application with the IPUC requesting that the IPUC authorize the deferral of costs associated with transmission service based on transmission costs that could not be recovered in a transmission rate case before the FERC. 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 estimate of the revenue shortfall, and thus the deferral amount, from $8.1 million to $2.1 million. Idaho Power also requested to begin amortization of the $2.1 million deferred amount on January 1, 2012, rather than January 1, 2011, as originally ordered, because Idaho Power’s settlement agreement would not permit potential inclusion of the deferral amount in rates until after January 1, 2012. Because Idaho Power’s regulatory asset recorded for the deferred amount as of September 30, 2010 was $2 million, if the IPUC were to grant the request Idaho Power does not anticipate that the reduction in the deferral amount would have a material impact on its financial condition or results of operations.

Oregon Regulatory Matters in 2010

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

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

• PCAM: The PCAM consists of an annual power supply expense true-up, which uses an asymmetrical dead band (the range of deviations within which Idaho Power absorbs cost increases or decreases) to calculate the net power supply deviations used in the true-up calculations. On February 26, 2010, Idaho Power filed its PCAM application for the 2009 year with the OPUC. The filing stated that actual net power supply costs were within the deadband, resulting in no request for a deferral. In an April 15, 2010 stipulation, which was approved in an order issued by the OPUC on May 24, 2010, Idaho Power agreed to a one-time modification to the deadband used to calculate the net power supply deviations in the 2010 PCAM. The deadband was increased by $0.2 million, to $2.4 million, before any excess power costs are subject to collection pursuant to the terms of the PCAM, and the deadband was reduced by $0.2 million, to $(1.0) million, before any power costs are subject to return pursuant to the terms of the PCAM.

• APCU: Idaho Power annually updates its net power supply expense included in its Oregon rates through the APCU. The APCU is comprised of two primary components: an October power cost update

and a March power cost forecast. The October update contains Idaho Power’s forecasted net power supply expense reflected on a normalized and unit basis for an April through March test period. The March forecast contains Idaho Power’s net power supply expense based upon updated actual forecasted conditions. The rates from the October update and March forecast are combined, and that combined rate is then included in rates effective on June 1 of each year. On March 23, 2010, Idaho Power filed its March forecast for the 2010 APCU rate adjustment with the OPUC. A stipulation among various parties combining the March forecast and 2009 October update was filed with the OPUC on April 15, 2010. The stipulation was approved on May 24, 2010, and the rate adjustments are expected to result in collection of an additional $2.2 million over currently billed amounts over the 12-month APCU adjustment period beginning June 1, 2010. On October 15, 2010, Idaho Power filed its October update with the OPUC, requesting an increase in base rates of $1.6 million.

Oregon Solar Photovoltaic Energy Pilot Program: During and subsequent to the second quarter of 2010, the OPUC adopted rules implementing a solar photovoltaic capacity standard (SPCS) and solar photovoltaic pilot program (SPPP) applicable to companies providing electric service to Oregon customers. The OPUC orders and related Idaho Power compliance filings established the rules, processes, and procedures to implement the Oregon Legislature’s mandate for all Oregon electric companies to implement and make solar photovoltaic energy programs available to their respective Oregon customers. Pursuant to the SPCS and SPPP, Idaho Power is required to (1) either build or purchase an aggregate of 500kW of energy from one or more solar facilities by the year 2020; and (2) purchase energy from qualified solar photovoltaic systems at a financial incentive rate of 55 cents per kWh to promote the development of 10-kW and smaller solar projects over the next two years. The program is to be rolled out over a two year period for a total nameplate capacity of 400 kW. The first year’s program allotment of 200 kW was made available to Oregon customers on July 1, 2010, and is fully subscribed. The legislative mandate and the OPUC orders specify that the cost of these programs be paid by Oregon customers. Idaho Power’s costs of participation in the program, currently estimated to be $0.6 million per year, are being deferred and collected from Oregon customers through a rider mechanism.

Federal Regulatory Matters in 2010

FERC ITSA: In June 2009, Idaho Power filed with the FERC a request for authority to increase rates to PacifiCorp under the existing Agreement for Interconnection and Transmission Services (ITSA) between Idaho Power and PacifiCorp to the OATT level. In August 2009, the FERC accepted the rates subject to refund. On May 24, 2010, Idaho Power and PacifiCorp entered into and filed an offer of settlement with the FERC, which settlement affirms those rates. On July 23, 2010, the FERC issued an order approving the ITSA settlement. Under the settlement, PacifiCorp will take and pay for 250 MW of long-term firm point-to-point transmission service, pursuant to the ITSA, the rates, terms, and conditions of which will be equivalent to Idaho Power’s OATT. For the three months ended September 30, 2010, Idaho Power collected $1 million related to the ITSA with PacifiCorp.

Annual OATT Update: On August 26, 2010, Idaho Power submitted its annual Final Information Filing (FIF) for its OATT to FERC and posted the filing on its OASIS Internet platform. The FIF is the computation of Idaho Power’s transmission rate for service under its OATT, which is updated annually. The new rate submitted by Idaho Power is $19.60 per kW/year, an increase from the prior $15.83 per kW/year OATT rate, and was effective as of October 1, 2010 for a period of one year. For the nine months ended September 30, 2010, revenues from the transmission rate for service under the OATT were $11 million. In September 2010, Idaho Power made corrections to its OATT rates for the period beginning October 1, 2007 through September 30, 2010, which resulted in the issuance of refunds, including interest, to transmission customers of $0.5 million.

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

During 2010, Idaho Power self-reported to both the FERC and the WECC, and received notices of alleged violations from the WECC relating to reliability and CIP matters. Idaho Power received notification that the FERC

intends to take no further action regarding several issues previously reported by Idaho Power. Certain matters reported to the FERC and the WECC remain unresolved, and Idaho Power is unable to predict what action, if any, the WECC or the FERC will take on those unresolved matters, but Idaho Power does not expect any material adverse effect on its financial position, results of operations, or cash flows. Idaho Power plans to continue its policy of reducing potential violations through its compliance program and self-reporting compliance issues to the FERC and the WECC.

Bonneville Power Administration Residential Exchange Program – Agreement in Principle: The Pacific Northwest Electric Power Planning and Conservation Act of 1980, through the Residential Exchange Program, 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 BPA. Pursuant to agreements between the BPA and Idaho Power, benefits from the BPA 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 Residential Exchange Program payments that the utilities pass through to their residential and small farm customers in the form of electricity bill credits. Idaho Power took action with both the IPUC and the OPUC to reduce the level of credit on its customers’ bills to zero, effective June 1, 2007.

Since that time, Idaho Power has been working with the other northwest IOUs and consumer-owned utilities, northwest state public utility commissions, and the BPA to craft an agreement so that residential and small farm customers of Idaho Power can resume sharing in the benefits of the federal Columbia River power system. The BPA initiated several public processes. Subsequent BPA filings and decisions have provided no Residential Exchange Program benefits to Idaho Power’s customers, and Idaho Power and other IOUs filed petitions for review of the BPA’s decisions with the U.S. Court of Appeals for the Ninth Circuit.

Concurrent with the litigation, Idaho Power and other parties engaged in extensive settlement negotiations. As a result of these negotiations, five regional IOUs, including Idaho Power, most consumer-owned utilities, the IPUC, the OPUC, the Washington Utilities and Transportation Commission, and the Citizens’ Utility Board of Oregon signed a non-binding Agreement in Principle, effective as of September 1, 2010, outlining how the Residential Exchange Program will be administered by the BPA. The Agreement in Principle creates a path forward for a final settlement agreement to be executed if ultimately agreed upon by the parties. Any final settlement is expected to be submitted for Congressional ratification. Since any benefits would pass directly through to Idaho Power’s eligible residential and small farm customers, the outcome of this matter is not expected to have an effect on Idaho Power’s financial condition or results of operations.

Integrated Resource Plan

Idaho Power filed its 2009 IRP with the IPUC and OPUC in December 2009. The IRP addresses available supply-side and demand-side resource options, planning period load forecasts, potential resource portfolios, a risk analysis, and near-term and long-term action plans. On August 3, 2010, the IPUC issued an order accepting the IRP for filing. On October 11, 2010, the OPUC issued an order acknowledging the IRP and directing Idaho Power to provide the results of additional analysis and expand the contents of its 2011 IRP. The OPUC requested that Idaho Power analyze, among other things, the impact of coal curtailment and coal plant retirement, the effects of environmental regulations, and treatment of the Boardman to Hemingway transmission project as an uncommitted resource, and requested that Idaho Power provide an updated project analysis on the Boardman to Hemingway transmission project in the 2011 IRP.

These actions by the IPUC and the OPUC conclude the regulatory process associated with the 2009 IRP. Idaho Power is currently working on the 2011 IRP to be filed with regulators in June 2011.

Relicensing of Hydroelectric Projects:

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

HCC: Idaho Power’s most significant relicensing effort is the HCC, which provides approximately 68 percent of Idaho Power’s hydroelectric generating nameplate capacity and 36 percent of its total generating nameplate capacity. In 2007, the FERC Staff issued a final EIS for the HCC, which the FERC will use to determine whether, and under what conditions, to issue a new license for the project. Idaho Power has reviewed the final EIS and is developing comments for filing with the FERC. However, certain portions of the final EIS involve issues that may be influenced by water quality certifications for the project under section 401 of the Clean Water Act and formal consultations under the Endangered Species Act (ESA), which remain unresolved. Idaho Power anticipates filing comments to the final EIS as the section 401 and ESA processes progress and the manner in which they may affect pending issues becomes more certain. In that regard, Idaho Power continues to cooperate with the U.S. Fish and Wildlife Service, the National Marine Fisheries Service, and the FERC in an effort to address ESA concerns and to work with Idaho and Oregon to take measures to ensure that any discharges from the HCC will comply with the temperature and other applicable necessary state water quality standards so that appropriate water quality certifications can be issued for the project. The FERC is expected to issue a license order for the HCC once the ESA consultation and the state water quality certification processes are completed. Idaho Power is currently operating under an annual license issued by the FERC and expects to continue operating under annual licenses until a new multi-year license is issued.

Swan Falls: Idaho Power is currently operating the Swan Falls hydroelectric project under an annual license while its application for a multi-year license is pending before the FERC. The FERC issued a final EIS for the Swan Falls project in August 2010 and Idaho Power is currently reviewing the final EIS. The final EIS identifies the Snake River Physa snail, which was previously believed to be extinct, as existing in the area. A biological assessment will be conducted and a biological opinion will be issued relating to the Snake River Physa snail prior to FERC issuing a new license.

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

Treatment of Relicensing Costs: Relicensing costs are recorded in construction work in progress until new multi-year licenses are issued by the FERC, at which time the charges will be transferred to electric plant in service. Relicensing costs and costs related to new licenses will be submitted to regulators for recovery through the ratemaking process. Relicensing costs of $127 million and $5 million for HCC and Swan Falls, respectively, were included in construction work in progress at September 30, 2010. The IPUC authorizes Idaho Power to include in rates approximately $6.8 million annually ($10.6 million grossed up for income taxes) of AFUDC relating to the HCC relicensing project, and collecting these amounts will reduce the relicensing amount submitted to regulators for recovery through the ratemaking process.

LEGAL MATTERS:

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

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

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

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

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

fired plant as a result of modifications made to the plant in 1998 and 2004. The Notice of Violation states the maximum civil penalties the EPA is authorized to impose under the CAA for violations of the NSPS (which range from $25,000 to $37,500 per day), but does not impose any penalties, or specify the amount of any proposed penalties with respect to the alleged violations. In the Notice of Violation, the EPA has offered PGE an opportunity to confer with the EPA about the violations cited and to present information on the specific findings of the EPA. Idaho Power intends to participate in those discussions.

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

Snake River Basin Water Rights: Idaho Power is engaged in the Snake River Basin Adjudication (SRBA), which commenced in 1987, to define the nature and extent of water rights in the Snake River Basin in Idaho, including the water rights of Idaho Power. On March 25, 2009, Idaho Power and the State of Idaho entered into a settlement agreement with respect to the 1984 Swan Falls Agreement and Idaho Power’s water rights under the Swan Falls Agreement, which settlement agreement is subject to certain conditions discussed below. The settlement agreement will also resolve litigation between Idaho Power and the State of Idaho relating to the Swan Falls Agreement.

The settlement agreement provides that Idaho Power’s water rights in excess of minimum flows at its hydroelectric facilities between Milner Dam and Swan Falls Dam are subordinate to future upstream beneficial uses, including aquifer recharge. The agreement commits the State of Idaho and Idaho Power to further discussions on important water management issues concerning the Swan Falls Agreement and the management of water in the Snake River Basin. It also recognizes that water management measures that enhance aquifer levels, springs and river flows, such as aquifer recharge projects, benefit both agricultural development and hydropower generation and deserve study to determine their economic potential, their impact on the environment, and their impact on hydropower generation.

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

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

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

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

ENVIRONMENTAL ISSUES:

Idaho Power is subject to regulations by federal, state, and local authorities governing the protection of the environment, including at the federal level the Clean Air Act; the Clean Water Act; the Comprehensive Environmental Response, Compensation and Liability Act; the Emergency Planning and Community Right-to-Know Act; the Endangered Species Act; the Federal Land Policy and Management Act; the National Environmental Policy Act; and the Resource Conservation and Recovery Act. These laws and regulations are continually changing and are generally becoming more restrictive. Idaho Power monitors legislative and regulatory developments at all levels of government for environmental issues, particularly those with the potential to alter the operation and productivity of power generating plants and other assets. Environmental laws and regulations may, among other things, increase the cost of operating power generation plants and constructing new facilities; require that Idaho Power install additional pollution control devices at existing generating plants; or require that Idaho Power discontinue operating certain power generation plants. While there can be no assurance of recovery, Idaho Power intends to seek recovery of any such costs through the ratemaking process. Like many other utilities, Idaho Power continues to actively monitor pollution control standards as they are promulgated and their associated costs to Idaho Power as they relate to the economic and operational feasibility of operation of generation plants. In its order acknowledging Idaho Power’s 2009 IRP, the OPUC has required that Idaho Power analyze (a) any potential EPA, state, and other federal agency regulations associated with air quality, fly ash, and water that may affect Idaho Power’s generation facilities, and (b) coal curtailment and the costs associated with coal plant retirement, and include the results of this analysis in its 2011 IRP.

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

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

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

In May 2010, Idaho Power submitted information to the Carbon Disclosure Project, an independent, not-for-profit organization that claims the largest database of corporate climate change information in the world. Idaho Power’s estimated CO₂ emission intensity (lbs/MWh) from its generation facilities as submitted to the Carbon Disclosure Project was 1,150, 1,097, and 1,004 lbs/MWh for 2007, 2008, and 2009, respectively. Idaho Power estimates that its CO₂ emission intensity from Idaho Power-owned generation facilities for the nine months ended September 30, 2010 was 996 lbs CO₂/MWh.

Regulation of Greenhouse Gas Emissions: The American Clean Energy and Security Act of 2009, H.R. 2454, regarding GHG emissions, renewable energy, energy efficiency, carbon capture and sequestration, and other matters, passed the U.S. House of Representatives on June 26, 2009. Debate on GHG legislation continues in Congress; however, given the complexity of the legislation, other competing legislative priorities, and upcoming elections, the timing and elements of any future legislation addressing GHG emission reduction requirements are uncertain. There are also state and regional initiatives (including the Western Regional Climate Action Initiative) considering market-based mechanisms to reduce GHG emissions.

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

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

In June 2010, the EPA issued a final rule regulating GHG emissions through its preconstruction and operating permit programs under the CAA. This rule is referred to as the “Tailoring Rule.” The first phase of the rule will take effect on January 2, 2011, and will require imposition of Best Available Control Technology (BACT) for GHG emissions if a new major source or modification of an existing major source is projected to result in GHG emissions of at least 75,000 tons per year (CO₂equivalent). In addition, existing major sources will need to amend their operating permits to include applicable requirements relating to GHGs. The EPA has stated it will issue guidance later in 2010 on BACT for power plants, which may focus initially on energy efficiency requirements. The EPA submitted the GHG BACT guidance to the White House Office of Management and Budget on September 17, 2010 for final review. These regulatory provisions may ultimately be nullified if Congress enacts GHG legislation that preempts regulations promulgated by the EPA. The EPAs effort to regulate GHG emissions through the CAA’s permitting programs has been appealed to the U.S. Court of Appeals for the District of Columbia Circuit.

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

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

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

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

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

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

Renewable Standards: The American Clean Energy and Security Act of 2009, in the form passed in the U.S. House of Representatives on June 26, 2009, would require utilities to obtain 20 percent of their electricity from renewable sources by 2020, and reduce demand an additional five percent through conservation and increased energy efficiency. In September 2010, the Renewable Electricity Promotion Act was introduced in the Senate as a stand-alone renewable energy standard (RES) bill. The bill would require utilities to acquire 3 percent of their power from renewable resources beginning in 2012, increasing to 15 percent by 2021, and as proposed would not count existing hydroelectric power generation towards meeting the new RES standard. Idaho Power will be required to comply with a ten percent renewable portfolio standard (RPS) in Oregon beginning in 2025. Idaho Power expects to meet these requirements with the renewable energy certificates (RECs) from the Elkhorn Valley wind project. No RPS requirement currently exists in Idaho. Idaho Power continues to monitor proposed federal RES legislation, which if passed could increase Idaho Power’s capital expenditures and operating costs and reduce earnings and cash flows.

Renewable Energy Contracts: Idaho Power has contracts to purchase energy from seven wind projects that have already achieved commercial operations. The combined nameplate rating of these projects is 208 MW. Idaho Power also has signed and the IPUC approved PURPA contracts to purchase energy from 15 wind projects which have not yet achieved commercial operations, with a combined nameplate rating of 264 MW. Most of these projects are expected to be online by mid-2011 and several are currently under construction. Additionally, Idaho Power has a signed PURPA contract to purchase energy from another wind project with a nameplate rating of 80 MW. This project is expected to be online in December 2011, and Idaho Power would be entitled to receive the RECs associated with the project starting in 2021 under the 25 year contract. Idaho Power is currently awaiting IPUC approval of this contract. In May 2009, Idaho Power issued a request for proposals (RFP) seeking to purchase approximately 150 MW of wind-powered generation by 2012. In August 2010, Idaho Power closed its RFP without awarding a contract, determining that the RFP no longer provided a competitive resource as a result of changes in the wind energy market and lower energy prices available under PURPA power purchase agreements. In addition to the above mentioned projects, Idaho Power continues to discuss other potential PURPA wind generation projects.

Idaho Power has entered into an agreement for the purchase of energy from a geothermal electric generation facility under development near Vale, Oregon, with an estimated 22 MW output and expected on-line date of late 2012. Idaho Power has contracted to receive the RECs from the project during the term of the agreement. On June 8, 2010, Idaho Power entered into a 20 year PURPA power purchase agreement with the owner of a proposed solar power generation facility, which is expected to have a 20-MW nameplate capacity, and an expected online date of January 2011. On September 14, 2010 the IPUC approved Idaho Power’s entry into the power purchase agreement. On July 28, 2010, Idaho Power entered into a 15 year PURPA firm energy sales agreement with the owner of a biomass plant with an expected nameplate capacity of 10 MW and online date of December 2011.

Generally, Idaho Power does not receive the RECs associated with PURPA projects, with the exception of the 80 MW PURPA wind project described above that would entitle Idaho Power to receive RECs starting in 2021. Idaho

Power is selling its near-term RECs and returning to customers their share of those proceeds through the PCA. Idaho Power filed a REC Management Plan with the IPUC in December 2009 to address its treatment of future RECs. Under Idaho Power’s REC Management Plan, Idaho Power would sell near-term RECs, while continuing to acquire and hold long-term contractual rights to own RECs for use in meeting future RES requirements. During the nine months ended September 30, 2010, Idaho Power’s REC sales totaled $2.5 million. Idaho Power has sold all of its 2009 and earlier vintage RECs. Idaho Power has sold a portion of its 2010 RECs and intends to continue selling its 2010 RECs as they are generated and become available for sale.

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

Air Quality: Idaho Power co-owns three coal-fired power plants and owns two natural gas combustion turbine power plants that are subject to air quality regulation. The coal-fired plants are: Jim Bridger (one third interest) located in Wyoming; Boardman (10 percent interest) located in Oregon; and Valmy (50 percent interest) located in Nevada. The natural gas-fired plants, Danskin and Bennett Mountain, are located in Idaho. Additionally, Idaho Power is currently in the process of constructing the Langley Gulch Power Plant, a natural gas-fired CCCT generating plant with a summer nameplate capacity of approximately 300 MW and a winter capacity of approximately 330 MW. The CAA establishes controls on the emissions from stationary sources like those owned by Idaho Power. The EPA adopts many of the standards and regulations under the CAA, while states have the primary responsibility for implementation and administration of these air quality programs. Idaho Power continues to actively monitor, evaluate, and work on air quality issues pertaining to federal and state mercury emission rules, possible legislative amendment of the CAA, National Ambient Air Quality Standards (NAAQS), and Regional Haze – Best Available Retrofit Technology (RH BART) and NSR permitting.

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

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

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

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

On January 22, 2010, the EPA adopted a new NAAQS for NO2 at a level of 100 parts per billion averaged over a 1-hour period. In addition, on June 22, 2010, the EPA adopted a new NAAQS for SO2 at a level of 75 parts per billion averaged over a one-hour period. The EPA has not yet designated areas as attaining or not attaining these new NAAQS. Idaho Power is unable to predict what impact the adoption and implementation of these standards may have on its operations.

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

On December 31, 2009, the WDEQ issued a RH BART permit to PacifiCorp for the Jim Bridger plant. The WDEQ determined that low NOx burners with over-fire air is RH BART for NOx for all four Bridger units and that RH BART is not required for SO2 for the Bridger plant. As part of the WDEQ’s long term strategy for regional haze, the permit requires that PacifiCorp install selective catalytic reduction (SCR) for NOx control at Bridger Units 3 and 4 by December 31, 2015 and December 31, 2016, respectively, and submit an application by January 15, 2015 to install add-on NOx controls at Bridger Units 1 and 2 by December 31, 2023. PacifiCorp is already in the process of installing low NOx burners and SO2 scrubber upgrades at the Bridger plant. The SO2 scrubber upgrade project has been completed on Bridger Units 2 and 4 and is expected to be completed on the other two units by the end of 2011. Idaho Power expects to spend approximately $22 million between 2009 and 2012 to complete these projects. Idaho Power’s estimated share of the cost to install SCR on Bridger Units 3 and 4 is $120 million. Installation of SCR also could require extended maintenance outages. Design and cost estimates for add-on NOx controls at Bridger Units 1 and 2 are not yet available. On February 26, 2010, PacifiCorp filed an administrative appeal of the Bridger RH BART permit with the Wyoming Environmental Quality Council (WEQC). PacifiCorp contends that the WDEQ lacked the legal and technical basis to require the SCR and add-on NOx controls required by the permit. On September 9, 2010, the WEQC denied a motion for summary judgment filed by PacifiCorp challenging the WDEQ’s legal authority to require SCR installation at Bridger. Idaho Power will continue to monitor this process. It is not possible for Idaho Power to predict the outcome of the administrative appeals process at this time.

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

On April 2, 2010, PGE submitted a petition requesting that the OEQC amend the RH BART and long term strategy requirements for the Boardman plant to be the installation of low NO_x burners and over-fire air by July 1, 2011, the phased transition to reduced sulfur coal by December 31, 2011 and July 1, 2014, and the closure of Boardman plant coal-fired boiler by December 31, 2020. However, on June 17, 2010, the OEQC denied PGE’s 2020 closure proposal and directed the ODEQ to explore additional options for early closure and initiate a rulemaking procedure. On June 28, 2010, the ODEQ introduced three proposals that contemplate early closure of the plant by 2020, 2018, or 2015-2016. The ODEQ stated that the capital cost of installing pollution control equipment for each of the options would be $321 million, $103 million, and $36 million, respectively. Each of the proposals would still require the Boardman plant to meet the current 2012 deadline for installing controls to meet the ODEQ’s mercury emission rules. The three proposed alternatives would be in addition to the option under the current RH BART rule that allows installation of controls and operation the Boardman plant through 2040. On August 27, 2010, PGE submitted to the ODEQ a new plan that would close the Boardman plant in 2020, but contemplates additional emission reductions relative to PGE’s previous 2020 closure plan and would increase the

aggregate cost of emissions controls to approximately $75 million, nearly $35 million over PGE’s previous 2020 plan, and would require an additional $14.5 million a year in operation and maintenance costs. The ODEQ solicited public comment and held a number of public hearings on the ODEQ’s and PGE’s emission control and closure proposals throughout the month of September 2010. A final ruling is expected to be submitted to the OEQC in December 2010. Idaho Power is a ten percent owner of the Boardman plant, representing 64 MW of nameplate capacity. Idaho Power is evaluating and discussing with PGE the various options for early closure of the Boardman plant, as well as alternatives. At September 30, 2010, Idaho Power’s net book value in the Boardman plant was approximately $20 million with annual depreciation of approximately $1.2 million.

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

New Source Review (NSR): Since 1999, the EPA and the U.S. Department of Justice have been pursuing a national enforcement initiative focused on the compliance status of coal-fired power plants with the NSR permitting requirements and New Source Performance Standards (NSPS) of the CAA. This initiative has resulted in both enforcement litigation and significant settlements with a large number of public utilities and other owners of coal-fired power plants across the country. The current administration has indicated an intention to continue this NSR enforcement initiative. The EPA sent information requests under the CAA, requesting information relevant to NSR and NSPS compliance to the Jim Bridger plant in 2003, the Valmy plant in 2009, and the Boardman plant in 2008 with a follow up request for information in 2009. Idaho Power is a co-owner of, but does not operate, these plants.

On September 28, 2010, the EPA issued a Notice of Violation to PGE, alleging that PGE has violated the NSPS under Section III of the CAA and operating permit requirements under Title V of the CAA at the Boardman coal-fired plant as a result of certain modifications made to the plant in 1998 and 2004. The Notice of Violation states the maximum civil penalties the EPA is authorized to impose under the CAA for violations of the NSPS (which range from $25,000 to $37,500 per day), but does not impose any penalties, or specify the amount of any proposed penalties with respect to the alleged violations. In the Notice of Violation, the EPA has offered PGE an opportunity to confer with the EPA about the violations cited and to present information on the specific findings of the EPA. Idaho Power intends to participate in those discussions.

Idaho Power cannot predict the outcome of these investigatory and enforcement matters at this time.

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

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

Endangered Species:

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

Sage Grouse: On March 5, 2010, the USFWS announced that listing of the greater sage grouse as threatened or endangered under the ESA is warranted, but precluded by higher priority listing actions. The sage grouse is now considered a “candidate species” under the ESA, which allows land management agencies to implement additional conservation measures in an effort to prevent a formal ESA listing. Due to the presence of sage grouse in the vicinity, siting of Idaho Power’s Boardman to Hemingway and Gateway West 500-kV transmission lines has required more extensive, costly, and time consuming evaluation and engineering. Any required additional conservation measures may increase the costs of existing operations and impact the cost and timing of siting and permitting of the Boardman to Hemingway and Gateway West transmission lines and other construction and transmission projects. Listing of the greater sage grouse as threatened or endangered under the ESA would add an additional requirement and species for consideration in ESA section 7 consultations for those projects, and may increase the expense and adversely affect the cost and timing of those projects.

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

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

Swan Falls Project: Idaho Power is currently operating the Swan Falls hydroelectric project under an annual license while its application for a multi-year license is pending before the FERC. In August 2010, the FERC issued a final EIS in connection with the relicensing. The Snake River Physa snail, which was previously believed to be extinct, was discovered during the EIS review. As a result, a biological assessment will be conducted and biological opinion relating to the Physa snail will be issued as a component of Idaho Power’s relicensing efforts.

OTHER MATTERS:

Critical Accounting Policies and Estimates

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

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

Recently Issued Accounting Pronouncements

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

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

IDACORP and Idaho Power are exposed to market risks, including changes in interest rates, changes in commodity prices, credit risk, and equity price risk. The following discussion summarizes these risks and the financial instruments, derivative instruments, and derivative commodity instruments sensitive to changes in interest rates, commodity prices, and equity prices that were held at September 30, 2010.

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, 2010, IDACORP and Idaho Power, after netting with short term investments, had no floating-rate debt.

Fixed Rate Debt: As of September 30, 2010, IDACORP and Idaho Power each had $1.6 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 $179 million for both IDACORP and Idaho Power if interest rates were to decline by one percentage point from their September 30, 2010 levels.

Commodity Price Risk

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

Credit Risk

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

The use of performance assurance collateral in the form of cash, letters of credit, or guarantees is common industry practice. Idaho Power maintains margin agreements that allow performance assurance collateral to be requested of and/or posted with certain counterparties. As of September 30, 2010, Idaho Power had posted approximately $4 million of assurance collateral. Should Idaho Power experience a reduction in its credit rating on Idaho Power's unsecured debt to below investment grade, Idaho Power could be subject to additional requests by its wholesale counterparties to post additional performance assurance collateral. Counterparties to derivative instruments and other forward contracts could request immediate payment or demand immediate ongoing full daily collateralization on derivative instruments and contracts in net liability positions. Based upon Idaho Power's current energy and

fuel portfolio and current market conditions as of September 30, 2010, the approximate amount of additional collateral that could be requested upon a downgrade is approximately $18 million. Idaho Power actively monitors the portfolio exposure and the potential exposure to additional requests for performance assurance collateral calls, through sensitivity analysis, to minimize capital requirements.

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

Equity Price Risk

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

ITEM 4. CONTROLS AND PROCEDURES

Disclosure Controls and Procedures

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

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

Changes in Internal Control Over Financial Reporting

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

PART II – OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS

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

ITEM 1A. RISK FACTORS

The factors discussed in Part I - Item 1A - “Risk Factors” in IDACORP, Inc.’s and Idaho Power Company’s Annual Report on Form 10-K for the year ended December 31, 2009, which were supplemented by additional factors set forth in Part II - Item 1A - “Risk Factors” in IDACORP, Inc.’s and Idaho Power Company’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2010, could materially affect IDACORP, Inc.’s and Idaho Power Company’s business, financial condition, or future results.

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

Restrictions on Dividends

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

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

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

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

ITEM 5. OTHER INFORMATION

Mine Safety and Health Matters

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

As of September 30, 2010, BCC had 22 legal actions pending before the Federal Mine Safety and Health Review Commission, which includes those that were initiated but not resolved prior to the three-month period ended September 30, 2010. These matters are not exclusive to citations, notices, orders, and penalties assessed by MSHA.

The table below summarizes the total number of citations, notices, and orders issued and penalties assessed by MSHA for the Mine under the indicated provisions of the Mine Safety Act, and other information, for the three-month period ended September 30, 2010.

			Bridger Coal Mine and
			Coal Processing Facility
			(surface)		(underground)
	Mine Safety Act
		Section 104(a) Significant & Substantial Citations ⁽¹⁾		2		9
		Section 104(b) Orders ⁽²⁾		0		0
		Section 104(d) Citations & Orders ⁽³⁾		0		0
		Section 110(b)(2) Flagrant Violations ⁽⁴⁾		0		0
		Section 107(a) Imminent Danger Orders ⁽⁵⁾		0		1
		Section 104(e) Notice ⁽⁶⁾		0		0

Total Value of Proposed MSHA Assessments (in thousands)			$	4	$	42
Number of Fatalities				0		0

⁽¹⁾For alleged violations of a mandatory mining safety standard or regulation where such violation contributed to a discrete safety hazard and there exists a reasonable likelihood that the hazard will result in an injury or illness and there is a reasonable likelihood that such injury will be of a reasonably serious nature.
⁽²⁾For alleged failure to totally abate the subject matter of a Mine Safety Act Section 104(a) citation within the period specified in the citation or as subsequently extended.
⁽³⁾For an alleged unwarrantable failure (i.e., aggravated conduct constituting more than ordinary negligence) to comply with a mining safety standard or regulation.
⁽⁴⁾The 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.

ITEM 6. EXHIBITS

Exhibit No.	Description

10.44	Engineering, Procurement and Construction Services Agreement (the “EPC Agreement”), dated May 7, 2009, between Boise Power Partners Joint Venture, a joint venture consisting of Kiewit Power Engineers Co. and TIC-The Industrial Company, and Idaho Power Company, including Exhibits A through R thereto (Portions of this exhibit have been redacted and filed separately with the Securities and Exchange Commission (“Commission”) in accordance with (i) a request for, and related Order by the Commission dated October 21, 2009, File No. 001-14465 – CF#23941, granting, confidential treatment for portions of the EPC Agreement and Exhibit A thereto pursuant to Rule 24b-2 under the Securities Exchange Act of 1934, as amended (the “Exchange Act”), and (ii) a request for confidential treatment, dated October 28, 2010, pursuant to Rule 24b-2 under the Exchange Act for portions of Exhibits B, C, D, F, I, L, M and P to the EPC Agreement)
12.1	IDACORP, Inc. Computation of Ratio of Earnings to Fixed Charges and Supplemental Ratio of Earnings to Fixed Charges
12.2	Idaho Power Company Computation of Ratio of Earnings to Fixed Charges and Supplemental Ratio of Earnings to Fixed Charges
15.1	Letter Re: Unaudited Interim Financial Information
31.1	IDACORP, Inc. Rule 13a-14(a) CEO certification
31.2	IDACORP, Inc. Rule 13a-14(a) CFO certification
31.3	Idaho Power Rule 13a-14(a) CEO certification
31.4	Idaho Power Rule 13a-14(a) CFO certification
32.1	IDACORP, Inc. Section 1350 CEO certification
32.2	IDACORP, Inc. Section 1350 CFO certification
32.3	Idaho Power Section 1350 CEO certification
32.4	Idaho Power Section 1350 CFO certification
101.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

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

SIGNATURES

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

		IDACORP, INC.
		(Registrant)



Date:	October 28, 2010	By:	/s/ J. LaMont Keen
			J. LaMont Keen
			President and Chief Executive Officer

Date:	October 28, 2010	By:	/s/ Darrel T. Anderson
			Darrel T. Anderson
			Executive Vice President - Administrative
			Services and Chief Financial Officer





		IDAHO POWER COMPANY
		(Registrant)



Date:	October 28, 2010	By:	/s/ J. LaMont Keen
			J. LaMont Keen
			President and Chief Executive Officer

Date:	October 28, 2010	By:	/s/ Darrel T. Anderson
			Darrel T. Anderson
			Executive Vice President - Administrative
			Services and Chief Financial Officer

EXHIBIT INDEX

Exhibit No.	Description

10.44	Engineering, Procurement and Construction Services Agreement (the “EPC Agreement”), dated May 7, 2009, between Boise Power Partners Joint Venture, a joint venture consisting of Kiewit Power Engineers Co. and TIC-The Industrial Company, and Idaho Power Company, including Exhibits A through R thereto (Portions of this exhibit have been redacted and filed separately with the Securities and Exchange Commission (“Commission”) in accordance with (i) a request for, and related Order by the Commission dated October 21, 2009, File No. 001-14465 – CF#23941, granting, confidential treatment for portions of the EPC Agreement and Exhibit A thereto pursuant to Rule 24b-2 under the Securities Exchange Act of 1934, as amended (the “Exchange Act”), and (ii) a request for confidential treatment, dated October 28, 2010, pursuant to Rule 24b-2 under the Exchange Act for portions of Exhibits B, C, D, F, I, L, M and P to the EPC Agreement)
12.1	IDACORP, Inc. Computation of Ratio of Earnings to Fixed Charges and Supplemental Ratio of Earnings to Fixed Charges
12.2	Idaho Power Company Computation of Ratio of Earnings to Fixed Charges and Supplemental Ratio of Earnings to Fixed Charges
15.1	Letter Re: Unaudited Interim Financial Information
31.1	IDACORP, Inc. Rule 13a-14(a) CEO certification
31.2	IDACORP, Inc. Rule 13a-14(a) CFO certification
31.3	Idaho Power Rule 13a-14(a) CEO certification
31.4	Idaho Power Rule 13a-14(a) CFO certification
32.1	IDACORP, Inc. Section 1350 CEO certification
32.2	IDACORP, Inc. Section 1350 CFO certification
32.3	Idaho Power Section 1350 CEO certification
32.4	Idaho Power Section 1350 CFO certification
101.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

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