Edgar Filing: IDAHO POWER CO

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, 2009
	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). 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 September 30, 2009:
IDACORP, Inc.:	47,650,036
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 Form with the reduced disclosure format.

COMMONLY USED TERMS

AFUDC	-	Allowance for Funds Used During Construction
APCU	-	Annual Power Cost Update
ASC	-	Accounting Standards Codification
Cal ISO	-	California Independent System Operator
CalPX	-	California Power Exchange
CAMP	-	Comprehensive Aquifer Management Plan
CO₂	-	Carbon Dioxide
EIS	-	Environmental impact statement
EPS	-	Earnings per share
ESA	-	Endangered Species Act
ESPA	-	Eastern Snake Plain Aquifer
FASB	-	Financial Accounting Standards Board
FERC	-	Federal Energy Regulatory Commission
FIN	-	Financial Accounting Standards Board Interpretation
Fitch	-	Fitch Ratings, Inc.
GAAP	-	Generally Accepted Accounting Principles in the United States of America
HCC	-	Hells Canyon Complex
Ida-West	-	Ida-West Energy, a subsidiary of IDACORP, Inc.
IDWR	-	Idaho Department of Water Resources
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.
IPC	-	Idaho Power Company, a subsidiary of IDACORP, Inc.
IPUC	-	Idaho Public Utilities Commission
IRP	-	Integrated Resource Plan
IWRB	-	Idaho Water Resource Board
kW	-	Kilowatt
LGAR	-	Load growth adjustment rate
maf	-	Million acre feet
MD&A	-	Management’s Discussion and Analysis of Financial Condition and Results of Operations
Moody’s	-	Moody’s Investors Service
MW	-	Megawatt
MWh	-	Megawatt-hour
NO_x	-	Nitrogen Oxide
NWRFC	-	National Weather Service Northwest River Forecast Center
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
RH BART	-	Regional Haze – Best Available Retrofit Technology
RFP	-	Request for Proposal
S&P	-	Standard & Poor’s Ratings Services
SFAS	-	Statement of Financial Accounting Standards
SO₂	-	Sulfur Dioxide
SRBA	-	Snake River Basin Adjudication
Valmy	-	North Valmy Steam Electric Generating Plant
VIEs	-	Variable Interest Entities

TABLE OF CONTENTS

Part I. Financial Information:
	Item 1. Financial Statements (unaudited)
		IDACORP, Inc.:
			Condensed Consolidated Statements of Income	1
			Condensed Consolidated Balance Sheets	2-3
			Condensed Consolidated Statements of Cash Flows	4
			Condensed Consolidated Statements of Comprehensive Income	5
		Idaho Power Company:
			Condensed Consolidated Statements of Income	6
			Condensed Consolidated Balance Sheets	7-8
			Condensed Consolidated Statements of Capitalization	9
			Condensed Consolidated Statements of Cash Flows	10
			Condensed Consolidated Statements of Comprehensive Income	11
		Notes to the Condensed Consolidated Financial Statements		12-41
		Reports of Independent Registered Public Accounting Firm		42-43

	Item 2. Management’s Discussion and Analysis of Financial Condition and Results of			44-86
			Operations

	Item 3. Quantitative and Qualitative Disclosures About Market Risk			86-87

	Item 4. Controls and Procedures			87-88

Part II. Other Information:

	Item 1. Legal Proceedings			88

	Item 2. Unregistered Sales of Equity Securities and Use of Proceeds			88-89

	Item 6. Exhibits			89-97

Signatures				98

Exhibit Index				99

SAFE HARBOR STATEMENT

This 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.” 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,” and 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,
			2009		2008		2009		2008
			(thousands of dollars except for per share amounts)
Operating Revenues:
Electric utility:
General business			$	277,676	$	246,639	$	663,818	$	602,700
Off-system sales			23,691		34,637		78,888		93,640
Other revenues			21,761		16,831		50,969		43,508
Total electric utility revenues			323,128		298,107		793,675		739,848
Other			1,381		1,609		3,042		3,534
Total operating revenues			324,509		299,716		796,717		743,382
Operating Expenses:
Electric utility:
Purchased power			73,483		79,513		131,370		174,900
Fuel expense			49,530		46,467		113,138		112,385
Third-party transmission expense			2,791		3,738		5,473		6,138
Power cost adjustment			1,614		(20,105)		44,236		(38,678)
Other operations and maintenance			68,970		71,040		212,392		213,183
Energy efficiency programs			12,202		5,956		24,933		13,249
Gain on sale of emission allowances			-		(158)		(289)		(504)
Depreciation			28,837		25,717		81,631		78,084
Taxes other than income taxes			5,600		4,827		15,749		14,431
Total electric utility expenses			243,027		216,995		628,633		573,188
Other expense			1,879		1,144		3,374		3,331
Total operating expenses			244,906		218,139		632,007		576,519
Operating Income (Loss):
Electric utility			80,101		81,112		165,042		166,660
Other			(498)		465		(332)		203
Total operating income			79,603		81,577		164,710		166,863
Other Income , net			4,569		2,038		15,548		10,081
Income (Losses) of Unconsolidated Equity-Method
	Investments		2,866		2,642		648		(4,672)
Interest Expense:
Interest on long-term debt			18,840		17,226		53,762		49,847
Other interest expense, net of AFUDC			(239)		1,310		481		3,219
Total interest expense			18,601		18,536		54,243		53,066
Income Before Income Taxes			68,437		67,721		126,663		119,206
Income Tax Expense			13,730		15,809		25,700		28,335
Net Income			54,707		51,912		100,963		90,871
	Adjustment for (income) loss attributable to
		noncontrolling interests	(229)		(173)		(126)		98
Net Income Attributable to IDACORP, Inc.			$	54,478	$	51,739	$	100,837	$	90,969
Weighted Average Common Shares Outstanding - Basic (000’s)			47,068		45,126		46,953		45,044
Weighted Average Common Shares Outstanding - Diluted (000’s)			47,141		45,246		46,999		45,149
Earnings Per Share of Common Stock:
Earnings Attributable to IDACORP Inc.-Basic			$	1.16	$	1.15	$	2.15	$	2.02
Earnings Attributable to IDACORP Inc.-Diluted			$	1.16	$	1.14	$	2.15	$	2.02
Dividends Paid 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,
	2009		2008
Assets	(thousands of dollars)

Current Assets:
Cash and cash equivalents	$	28,869	$	8,828
Receivables:
Customer	83,990		64,733
Allowance for uncollectible accounts	(1,534)		(1,724)
Other	12,242		10,439
Taxes receivable	-		18,111
Accrued unbilled revenues	49,779		43,934
Materials and supplies (at average cost)	50,599		50,121
Fuel stock (at average cost)	22,346		16,852
Prepayments	11,659		10,059
Deferred income taxes	14,739		37,550
Other	3,105		7,381
Total current assets	275,794		266,284

Investments	197,861		198,552

Property, Plant and Equipment:
Utility plant in service	4,141,054		4,030,134
Accumulated provision for depreciation	(1,556,226)		(1,505,120)
Utility plant in service - net	2,584,828		2,525,014
Construction work in progress	236,632		207,662
Utility plant held for future use	6,549		6,318
Other property, net of accumulated depreciation	19,134		19,171
Property, plant and equipment - net	2,847,143		2,758,165

Other Assets:
American Falls and Milner water rights	24,487		26,332
Company-owned life insurance	27,029		29,482
Regulatory assets	701,931		696,332
Long-term receivables (net of allowance of $1,684 and $2,478)	5,212		4,012
Other	37,835		43,686
Total other assets	796,494		799,844

Total	$	4,117,292	$	4,022,845

The accompanying notes are an integral part of these statements.

IDACORP, Inc.
Condensed Consolidated Balance Sheets
(unaudited)

	September 30,		December 31,
	2009		2008
Liabilities and Shareholders’ Equity	(thousands of dollars)

Current Liabilities:
Current maturities of long-term debt	$	84,064	$	86,528
Notes payable	36,780		151,250
Accounts payable	88,136		96,785
Taxes accrued	20,531		-
Interest accrued	27,680		16,727
Other	37,761		44,378
Total current liabilities	294,952		395,668

Other Liabilities:
Deferred income taxes	528,953		515,719
Regulatory liabilities	285,695		276,266
Other	340,003		344,870
Total other liabilities	1,154,651		1,136,855

Long-Term Debt	1,282,900		1,183,451

Commitments and Contingencies

Shareholders’ Equity:
IDACORP, Inc. shareholders’ equity:
Common stock, no par value (shares authorized 120,000,000;
47,679,227 and 46,929,203 shares issued, respectively)	747,402		729,576
Retained earnings	640,029		581,605
Accumulated other comprehensive loss	(6,900)		(8,707)
Treasury stock (29,191 and 9,022 shares at cost, respectively)	(53)		(37)
Total IDACORP, Inc. shareholders’ equity	1,380,478		1,302,437
Noncontrolling interest	4,311		4,434
Total shareholders’ equity	1,384,789		1,306,871

Total	$	4,117,292	$	4,022,845

The accompanying notes are an integral part of these statements.

IDACORP, Inc.
Condensed Consolidated Statements of Cash Flows
(unaudited)

	Nine months ended
	September 30,
	2009		2008
Operating Activities:	(thousands of dollars)
Net income	$	100,963	$	90,871
Adjustments to reconcile net income to net cash provided by
operating activities:
Depreciation and amortization	86,485		83,898
Deferred income taxes and investment tax credits	14,797		16,075
Changes in regulatory assets and liabilities	37,721		(50,081)
Non-cash pension expense	3,076		3,009
(Earnings) losses of equity method investments	(648)		4,672
Distributions from equity method investments	9,415		850
Gain on sale of assets	(417)		(3,369)
Other non-cash adjustments to net income, net	(764)		1,770
Change in:
Accounts receivable and prepayments	(22,065)		(11,819)
Accounts payable and other accrued liabilities	(24,636)		(16,782)
Taxes accrued	38,812		6,244
Other current assets	(11,817)		(17,940)
Other current liabilities	5,850		8,971
Other assets	678		1,126
Other liabilities	(14,924)		(2,090)
Net cash provided by operating activities	222,526		115,405
Investing Activities:
Additions to property, plant and equipment	(155,591)		(176,475)
Proceeds from the sale of non-utility assets	2,250		5,753
Investments in affordable housing	(6,176)		(8,486)
Proceeds from the sale of emission allowances	2,382		2,959
Investments in unconsolidated affiliates	-		(3,065)
Proceeds from the sale of investments	8,956		-
Purchase of held-to-maturity securities	-		(2,885)
Maturity of held-to-maturity securities	-		4,610
Withdrawal of refundable deposit for tax related liabilities	-		20,000
Other	683		(7,932)
Net cash used in investing activities	(147,496)		(165,521)
Financing Activities:
Increase (decrease) in term loans	(170,000)		170,000
Issuance of long-term debt	100,000		120,000
Remarketing (purchase) of pollution control revenue bonds	166,100		(166,100)
Retirement of long-term debt	(9,174)		(7,630)
Dividends on common stock	(42,414)		(40,516)
Net change in short-term borrowings	(110,570)		13,570
Issuance of common stock	16,738		12,550
Acquisition of treasury stock	(1,441)		(304)
Other	(4,228)		(1,694)
Net cash (used in) provided by financing activities	(54,989)		99,876
Net increase in cash and cash equivalents	20,041		49,760
Cash and cash equivalents at beginning of the period	8,828		7,966
Cash and cash equivalents at end of the period	$	28,869	$	57,726
Supplemental Disclosure of Cash Flow Information:
Cash paid during the period for:
Income taxes (refunded) paid	$	(21,356)	$	8,762
Interest (net of amount capitalized)	$	41,227	$	40,933
Non-cash investing activities:
Additions to property, plant and equipment in accounts payable	$	19,990	$	10,527
Investments in affordable housing	$	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,
	2009		2008
	(thousands of dollars)

Net Income	$	54,707	$	51,912

Other Comprehensive Income (Loss):
Unrealized gains (losses) on securities:
Net unrealized holding gains (losses) arising during the period,
net of tax of $734 and ($791)	1,143		(1,232)
Unfunded pension liability adjustment, net of tax
of $87 and $67	136		104
Total Comprehensive Income	55,986		50,784
Comprehensive income attributable to noncontrolling interests	(229)		(173)
Comprehensive Income attributable to IDACORP, Inc. common shareholders	$	55,757	$	50,611

The accompanying notes are an integral part of these statements.

IDACORP, Inc.
Condensed Consolidated Statements of Comprehensive Income
(unaudited)

	Nine months ended
	September 30,
	2009		2008
	(thousands of dollars)

Net Income	$	100,963	$	90,871

Other Comprehensive Income (Loss):
Unrealized gains (losses) on securities:
Net unrealized holding gains (losses) arising during the period,
net of tax of $898 and ($1,679)	1,399		(2,616)
Unfunded pension liability adjustment, net of tax
of $261 and $200	408		311
Total Comprehensive Income	102,770		88,566
Comprehensive (income) loss attributable to noncontrolling interests	(126)		98
Comprehensive Income attributable to IDACORP, Inc. common shareholders	$	102,644	$	88,664

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,
	2009		2008		2009		2008
	(thousands of dollars)
Operating Revenues:
General business	$	277,676	$	246,639	$	663,818	$	602,700
Off-system sales	23,691		34,637		78,888		93,640
Other revenues	21,761		16,831		50,969		43,508
Total operating revenues	323,128		298,107		793,675		739,848

Operating Expenses:
Operation:
Purchased power	73,483		79,513		131,370		174,900
Fuel expense	49,530		46,467		113,138		112,385
Third-party transmission expense	2,791		3,738		5,473		6,138
Power cost adjustment	1,614		(20,105)		44,236		(38,678)
Other	52,495		54,806		159,420		162,537
Energy efficiency programs	12,202		5,956		24,933		13,249
Gain on sale of emission allowances	-		(158)		(289)		(504)
Maintenance	16,475		16,234		52,972		50,646
Depreciation	28,837		25,717		81,631		78,084
Taxes other than income taxes	5,600		4,827		15,749		14,431
Total operating expenses	243,027		216,995		628,633		573,188

Income from Operations	80,101		81,112		165,042		166,660

Other Income:
Allowance for equity funds used during construction	2,131		1,265		4,629		2,394
Earnings of unconsolidated equity-method investments	4,328		4,487		6,980		2,621
Other income, net	1,717		825		9,662		7,425
Total other income	8,176		6,577		21,271		12,440

Interest Charges:
Interest on long-term debt	18,826		16,916		53,661		48,868
Other interest	1,302		2,290		4,230		6,437
Allowance for borrowed funds used during construction	(1,654)		(1,549)		(4,439)		(4,966)
Total interest charges	18,474		17,657		53,452		50,339

Income Before Income Taxes	69,803		70,032		132,861		128,761

Income Tax Expense	18,746		22,627		36,194		42,357

Net Income	$	51,057	$	47,405	$	96,667	$	86,404

The accompanying notes are an integral part of these statements.

Idaho Power Company
Condensed Consolidated Balance Sheets
(unaudited)

	September 30,		December 31,
	2009		2008
Assets	(thousands of dollars)

Electric Plant:
In service (at original cost)	$	4,141,054	$	4,030,134
Accumulated provision for depreciation	(1,556,226)		(1,505,120)
In service - net	2,584,828		2,525,014
Construction work in progress	236,632		207,662
Held for future use	6,549		6,318
Electric plant - net	2,828,009		2,738,994

Investments and Other Property	108,747		106,057

Current Assets:
Cash and cash equivalents	20,334		3,141
Receivables:
Customer	83,990		64,433
Allowance for uncollectible accounts	(1,499)		(1,724)
Other	10,278		7,947
Taxes receivable	-		41,363
Accrued unbilled revenues	49,779		43,934
Materials and supplies (at average cost)	50,599		50,121
Fuel stock (at average cost)	22,346		16,852
Prepayments	11,489		9,865
Deferred income taxes	3,922		3,852
Other	2,269		4,968
Total current assets	253,507		244,752

Deferred Debits:
American Falls and Milner water rights	24,487		26,332
Company-owned life insurance	27,029		29,482
Regulatory assets	701,931		696,332
Other	37,047		42,907
Total deferred debits	790,494		795,053

Total	$	3,980,757	$	3,884,856

The accompanying notes are an integral part of these statements.

Idaho Power Company
Condensed Consolidated Balance Sheets
(unaudited)

	September 30,		December 31,
	2009		2008
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	638,758		618,758
Capital stock expense	(2,097)		(2,097)
Retained earnings	536,155		482,047
Accumulated other comprehensive loss	(6,900)		(8,707)
Total common stock equity	1,263,793		1,187,878

Long-term debt	1,279,900		1,180,691
Total capitalization	2,543,693		2,368,569

Current Liabilities:
Long-term debt due within one year	81,064		81,064
Notes payable	-		112,850
Accounts payable	85,971		96,268
Notes and accounts payable to related parties	1,265		768
Taxes accrued	478		-
Interest accrued	27,680		16,675
Other	36,928		43,274
Total current liabilities	233,386		350,899

Deferred Credits:
Deferred income taxes	580,896		547,159
Regulatory liabilities	285,695		276,266
Other	337,087		341,963
Total deferred credits	1,203,678		1,165,388

Commitments and Contingencies

Total	$	3,980,757	$	3,884,856

The accompanying notes are an integral part of these statements.

Idaho Power Company
Condensed Consolidated Statements of Capitalization
(unaudited)

	September 30,			December 31,
	2009		%	2008		%
	(thousands of dollars)
Common Stock Equity:
Common stock	$	97,877		$	97,877
Premium on capital stock	638,758			618,758
Capital stock expense	(2,097)			(2,097)
Retained earnings	536,155			482,047
Accumulated other comprehensive loss	(6,900)			(8,707)
Total common stock equity	1,263,793		50	1,187,878		50

Long-Term Debt:
First mortgage bonds:
7.20% Series due 2009	80,000			80,000
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			-
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
Total first mortgage bonds	1,165,000			1,065,000
Amount due within one year	(80,000)			(80,000)
Net first mortgage bonds	1,085,000			985,000

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	8,509			9,573
Note guarantee due within one year	(1,064)			(1,064)
Unamortized premium/discount - net	(2,890)			(3,163)
Term Loan Credit Facility	-			166,100
Purchase of pollution control revenue bonds	-			(166,100)

Total long-term debt	1,279,900		50	1,180,691		50

Total Capitalization	$	2,543,693	100	$	2,368,569	100
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,
	2009		2008
	(thousands of dollars)
Operating Activities:
Net income	$	96,667	$	86,404
Adjustments to reconcile net income to net cash provided by
operating activities:
Depreciation and amortization	85,922		83,285
Deferred income taxes and investment tax credits	12,419		15,173
Changes in regulatory assets and liabilities	37,721		(50,081)
Non-cash pension expense	3,076		3,009
Earnings of equity method investments	(6,980)		(2,621)
Distributions from equity method investments	8,340		-
Gain on sale of assets	(442)		(3,383)
Other non-cash adjustments to net income	(2,516)		(1,346)
Change in:
Accounts receivables and prepayments	(21,940)		(12,162)
Accounts payable	(26,283)		(16,175)
Taxes accrued	41,996		21,636
Other current assets	(11,817)		(17,939)
Other current liabilities	6,029		8,945
Other assets	678		1,121
Other liabilities	(14,983)		(1,888)
Net cash provided by operating activities	207,887		113,978
Investing Activities:
Additions to utility plant	(155,591)		(176,475)
Proceeds from the sale of non-utility assets	2,250		5,690
Proceeds from sale of emission allowances	2,382		2,959
Investments in unconsolidated affiliates	-		(3,065)
Withdrawal of refundable deposit for tax related liabilities	-		20,000
Other	648		(7,550)
Net cash used in investing activities	(150,311)		(158,441)
Financing Activities:
Increase (decrease) in term loans	(170,000)		170,000
Issuance of long-term debt	100,000		120,000
Remarketing (purchase) of pollution control revenue bonds	166,100		(166,100)
Retirement of long-term debt	(1,064)		(1,064)
Dividends on common stock	(42,560)		(40,678)
Net change in short term borrowings	(108,950)		(5,222)
Capital contribution from parent	20,000		-
Other	(3,909)		(1,631)
Net cash (used in) provided by financing activities	(40,383)		75,305
Net increase in cash and cash equivalents	17,193		30,842
Cash and cash equivalents at beginning of the period	3,141		5,347
Cash and cash equivalents at end of the period	$	20,334	$	36,189

Supplemental Disclosure of Cash Flow Information:
Cash paid during the period for:
Income taxes (received from) paid to parent	$	(11,668)	$	8,331
Interest (net of amount capitalized)	$	40,505	$	38,300
Non-cash investing activities:
Additions to property, plant and equipment in accounts payable	$	19,990	$	10,527

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,
	2009		2008
	(thousands of dollars)

Net Income	$	51,057	$	47,405

Other Comprehensive Income (Loss):
Unrealized gains (losses) on securities:
Net unrealized holding gains (losses) arising during the period,
net of tax of $734 and ($791)	1,143		(1,232)
Unfunded pension liability adjustment, net of tax
of $87 and $67	136		104
Total Comprehensive Income	$	52,336	$	46,277

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,
	2009		2008
	(thousands of dollars)

Net Income	$	96,667	$	86,404

Other Comprehensive Income (Loss):
Unrealized gains (losses) on securities:
Net unrealized holding gains (losses) arising during the period,
net of tax of $898 and ($1,679)	1,399		(2,616)
Unfunded pension liability adjustment, net of tax
of $261 and $200	408		311
Total Comprehensive Income	$	98,474	$	84,099

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 (IPC). These Notes to the Condensed Consolidated Financial Statements apply to both IDACORP and IPC. However, IPC 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 IPC. 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.

IPC is an electric utility with a service territory covering approximately 24,000 square miles in southern Idaho and eastern Oregon. IPC is regulated by the FERC and the state regulatory commissions of Idaho and Oregon. IPC is the parent of Idaho Energy Resources Co. (IERCo), a joint venturer in Bridger Coal Company, which supplies coal to the Jim Bridger generating plant owned in part by IPC.

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

The entities that IDACORP and IPC 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 $26 million of assets, primarily a small hydroelectric plant, and approximately $17 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 results in it absorbing a majority of the expected losses of 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 IFS and Ida-West, IDACORP also holds variable interests in VIEs for which it is not the primary beneficiary. These interests are presented as Investments on IDACORP’s condensed consolidated balance sheets. IFS investments in VIEs are affordable housing and historic rehabilitation developments in which IFS holds limited partnership interests ranging from five to 99 percent. These investments were acquired between 1996 and 2009, and are not consolidated because IFS does not absorb a majority of the expected losses of these entities, either because of specific provisions in the partnership agreements or due to not owning a majority interest. IFS’s maximum exposure to loss in these developments is limited to its net carrying value, which was $79 million at September 30, 2009. Ida-West has 50 percent ownership of three other joint ventures that are not consolidated because Ida-West does not absorb a majority of the expected losses. Ida-West’s maximum exposure to loss in these joint ventures is limited to its net carrying value, which was $11 million at September 30, 2009.

Financial Statements

In the opinion of IDACORP and IPC, the accompanying unaudited condensed consolidated financial statements contain all adjustments necessary to present fairly their consolidated financial positions as of September 30, 2009, and consolidated results of operations for the three and nine months ended September 30, 2009, and 2008, and consolidated cash flows for the nine months ended September 30, 2009, and 2008. 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 IPC’s Annual Report on Form 10-K for the year ended December 31, 2008. The results of operations for the interim periods are not necessarily indicative of the results to be expected for the full year.

Subsequent Events

In the preparation of these financial statements, IDACORP and IPC evaluate all subsequent events that provide additional evidence about conditions that existed at the date of the balance sheet. Subsequent events were evaluated through October 29, 2009, up to the time the financial statements were issued.

Reclassifications

Certain prior year amounts have been reclassified to conform to the current year presentation. The reclassifications made to prior year amounts include the following:

• Other expense was combined with the other income line in IDACORP’s and IPC’s condensed consolidated statements of income to present information in a more condensed manner;

• Third-party transmission expense was broken out from electric utility other operations and maintenance in IDACORP’s condensed consolidated statements of income and from other operation in IPC’s condensed consolidated statements of income because third-party transmission costs are now treated as a power supply cost in the power cost adjustment (PCA);

• Employee notes – current was combined with other current receivables and employee notes – long-term was combined with other non-current assets in IDACORP’s and IPC’s condensed consolidated balance sheets due to the employee notes becoming an immaterial balance; and

• Uncertain tax positions was combined with other current liabilities in IDACORP’s and IPC’s condensed consolidated balance sheets due to the uncertain tax positions becoming an immaterial balance.

Revenues

Operating revenues for IPC related to the sale of energy are generally recorded when service is rendered or energy is delivered to customers. IPC accrues unbilled revenues for electric services delivered to customers but not yet billed at period-end. IPC collects franchise fees and similar taxes related to energy consumption. These amounts are recorded as liabilities until paid to the taxing authority. None of these collections are reported on the income statement as revenue or expense. Beginning in February 2009, IPC is collecting AFUDC in base rates for a specific capital project, as discussed in Note 6, “Regulatory Matters.” Cash collected under this ratemaking mechanism is recorded as a regulatory liability.

Allowance for Funds Used during Construction (AFUDC)

AFUDC represents the cost of financing construction projects with borrowed funds and equity funds. With one exception, cash is not realized currently from such allowance, it is realized under the rate-making process over the service life of the related property through increased revenues resulting from a higher rate base and higher depreciation expense. The component of AFUDC attributable to borrowed funds is included as a reduction to interest expense, while the equity component is included in other income.

Earnings Per Share (EPS)

In January 2009, IDACORP adopted accounting guidance that clarified that unvested share-based payment awards that contain non-forfeitable rights to dividends or dividend equivalents (whether paid or unpaid) are participating securities and shall be included in the computation of EPS pursuant to the two-class method. Prior-period EPS data has been adjusted retrospectively. Adoption of this guidance did not have a material impact on IDACORP’s EPS and had no impact on IPC’s condensed consolidated financial statements. The following table presents the computation of IDACORP’s basic and diluted earnings per share for the three and nine months ended September 30, 2009 and 2008 (in thousands, except for per share amounts):

				Three months ended				Nine months ended
				September 30,				September 30,
				2009		2008		2009		2008
Numerator:
	Net income attributable to IDACORP, Inc.			$	54,478	$	51,739	$	100,837	$	90,969

Denominator:
	Weighted-average common shares outstanding - basic				47,068		45,126		46,953		45,044
	Effect of dilutive securities:
		Options			15		32		12		43
		Restricted Stock			58		88		34		62
		Weighted-average common shares
			outstanding diluted		47,141		45,246		46,999		45,149
	Basic earnings per share			$	1.16	$	1.15	$	2.15	$	2.02
	Diluted earnings per share			$	1.16	$	1.14	$	2.15	$	2.02

The diluted EPS computation excluded 548,957 and 640,674 options for the three and nine months ended September 30, 2009, respectively, because the options’ exercise prices were greater than the average market price of the common stock during those periods. For the same periods last year, 577,585 and 513,862 options were excluded from the diluted EPS computation for the same reason. In total, 636,753 options were outstanding at September 30, 2009, with expiration dates between 2010 and 2015.

Adoption of Guidance on Noncontrolling Interests

On January 1, 2009, IDACORP and IPC adopted guidance related to presentation of noncontrolling interests in consolidated subsidiaries (previously referred to as minority interests). This guidance clarified that noncontrolling interests should be reported as equity on the consolidated financial statements. IDACORP has disclosed in its financial statements the portion of equity and net income attributable to the noncontrolling interests in consolidated subsidiaries and has reclassified $4 million of noncontrolling interests from other liabilities to shareholders’ equity on the December 31, 2008, balance sheet. IPC does not have any noncontrolling interests. The adoption of this guidance modifies financial statement presentation, but does not impact financial statement results.

The following table presents a reconciliation of the carrying amount of shareholders’ equity (in thousands):

				Attributable to
		Attributable to		noncontrolling
		IDACORP, Inc.		interests		Total
Shareholders’ equity at January 1, 2009		$	1,302,437	$	4,434	$	1,306,871
	Net income		100,837		126		100,963
	Common stock dividends		(42,413)		-		(42,413)
	Common stock issuances		17,061		-		17,061
	Common stock acquired		(1,441)		-		(1,441)
	Unrealized holding gains on securities		1,399		-		1,399
	Unfunded pension liability adjustment		408		-		408
	Other		2,190		(249)		1,941
Shareholders’ equity at September 30, 2009		$	1,380,478	$	4,311	$	1,384,789

Shareholders’ equity at January 1, 2008		$	1,207,315	$	4,478	$	1,211,793
	Net income (loss)		90,969		(98)		90,871
	Common stock dividends		(40,671)		-		(40,671)
	Common stock issuances		12,647		-		12,647
	Common stock acquired		(304)		-		(304)
	Unrealized holding losses on securities		(2,616)		-		(2,616)
	Unfunded pension liability adjustment		311		-		311
	Other		3,009		(7)		3,002
Shareholders’ equity at September 30, 2008		$	1,270,660	$	4,373	$	1,275,033

New and Adopted Accounting Pronouncements

The Financial Accounting Standards Board (FASB) has issued several new accounting pronouncements. IDACORP and IPC have adopted these pronouncements in 2009:

• On January 1, 2009, IDACORP and IPC adopted guidance related to business combinations. This guidance establishes principles and requirements for how an acquirer in a business combination: (1) recognizes and measures in its financial statements the identifiable assets acquired, the liabilities assumed, and any noncontrolling interest in the acquiree; (2) recognizes and measures the goodwill acquired in the business combination or a gain from a bargain purchase; and (3) determines what information to disclose to enable users of the financial statements to evaluate the nature and financial effects of the business combination. In April 2009, the FASB issued guidance further clarifying the application of the standard. The guidance primarily relates to business combinations entered into after December 31, 2009, and has not impacted IDACORP’s or IPC’s consolidated financial statements.

• On January 1, 2009, IDACORP and IPC adopted guidance that changes the disclosure requirements for derivative instruments and hedging activities. Entities are required to provide enhanced disclosures about (1) how and why it uses derivative instruments, (2) how derivative instruments and related hedged items are accounted for under prior guidance, and (3) how derivative instruments and related hedged items affect its financial position, financial performance, and cash flows. The adoption of this guidance is reflected in Note 10, and did not otherwise impact IDACORP’s or IPC’s consolidated financial statements.

• On January 1, 2009, IDACORP and IPC adopted guidance related to goodwill and other intangible assets. This guidance removes the requirement that an entity must consider, when determining the useful life of an acquired intangible asset, whether the intangible asset can be renewed without substantial cost or material modifications to the existing terms and conditions associated with the intangible asset. The guidance now requires that an entity consider its own experience in renewing similar arrangements. If the entity has no relevant experience, it would consider market participant assumptions regarding renewal. The adoption of this guidance did not impact IDACORP’s or IPC’s consolidated financial statements.

• In June 2009, IDACORP and IPC adopted guidance on accounting for and disclosures of subsequent events, events that occur after the balance sheet date but before financial statements are issued or are available to be issued. The required new disclosures are made earlier in this note, and this guidance has not otherwise impacted IDACORP’s or IPC’s consolidated financial statements.

• Fair Value Measurements: In the first quarter of 2009, IDACORP and IPC adopted the following fair value guidance:

a. Guidelines for making fair value measurements more consistent by providing guidance related to determining fair values when there is no active market or where the price inputs being used represent distressed sales;

b. Guidance that enhances consistency in financial reporting by increasing the frequency of fair value disclosures by requiring quarterly fair value disclosures for any financial instruments that are not currently reflected on the balance sheet of companies at fair value and requires qualitative and quantitative information about fair value estimates for all such financial instruments; and

c. Guidance on other-than-temporary impairments that brings greater consistency to the timing of impairment recognition, and provides greater clarity to investors about the credit and noncredit components of impaired debt securities that are not expected to be sold. The guidance also requires increased and timelier disclosures sought by investors regarding expected cash flows, credit losses, and the aging of securities with unrealized losses.

The adoption of this guidance did not have a material effect on IDACORP’s or IPC’s consolidated financial statements.

• Effective for financial statements issued for interim and annual periods ending after September 15, 2009, The FASB Accounting Standards Codification ^TM became the source of authoritative U.S. generally accepted accounting principles recognized by the FASB to be applied to nongovernmental entities. Rules and interpretive releases of the SEC under authority of federal securities laws are also sources of authoritative GAAP to SEC registrants. On the effective date, the Codification superseded, but did not change, all then-existing non-SEC accounting and reporting standards, and all other nongrandfathered, non-SEC accounting literature not included in the codification became nonauthoritative. Transition to the Codification did not affect IDACORP’s or IPC’s results of operations, cash flows or financial positions. This Form 10-Q reflects the implementation of the Codification.

The FASB has also issued the following accounting guidance that becomes effective in future periods:

• In December 2008, the FASB issued guidance on enhanced disclosures about retirement plan assets. This guidance will require companies to provide users of financial statements with an understanding of: (1) how investment allocation decisions are made, including the factors that are pertinent to an understanding of investment policies and strategies; (2) the major categories of plan assets; (3) the inputs and valuation techniques used to measure the fair value of plan assets; (4) the effect of fair value measurements using significant unobservable inputs (Level 3) on changes in plan assets for the period; and (5) significant concentrations of risk within plan assets. This guidance is effective for fiscal years ending after December 15, 2009. IDACORP and IPC do not expect the adoption of this guidance to have a material effect on their consolidated financial statements.

• In June 2009, the FASB issued guidance on how the transferor and transferee should separately account for a transfer of a financial asset and a related repurchase financing if certain criteria are met. For IDACORP and IPC, this guidance is effective for financial asset transfers occurring on or after January 1, 2010, and early adoption is prohibited. IDACORP and IPC do not expect the adoption of this guidance to have a material effect on their consolidated financial statements.

• In June 2009, the FASB issued amendments to prior consolidation guidance. The amendments will significantly affect the overall consolidation analysis of VIEs. The amendments will require IDACORP and IPC to reconsider their previous conclusions relating to the consolidation of VIEs, including (1) whether an entity is a VIE, (2) whether the enterprise is the VIE’s primary beneficiary, and (3) what type of financial statement disclosures are required. For IDACORP and IPC, the amendments are effective as of January 1, 2010, and early adoption is prohibited. IDACORP and IPC are currently assessing the impact of the amendments on their consolidated financial statements.

• Accounting Standards Updates (ASUs) – The FASB has issued several amendments to the Codification in the form of ASUs No. 2009-01 through 2009-15. IDACORP and IPC are evaluating the provisions of these amendments. Several of these ASUs are not applicable to IDACORP and IPC and are not included in the following discussion. IDACORP and IPC expect the following ASU to be relevant, but does not expect it to have a material impact on IDACORP’s or IPC’s consolidated financial statements:

o ASU 2009-05 provides clarification of measurement techniques to be used in circumstances in which a quoted price in an active market for the identical liability is not available and provides other fair value guidance. This guidance is effective for the first reporting period beginning after issuance. IDACORP and IPC will adopt the guidance in their December 31, 2009, financial statements.

2. INCOME TAXES:

In accordance with interim reporting requirements, IDACORP and IPC use an estimated annual effective tax rate for computing their provisions for income taxes. IDACORP’s effective tax rate for the nine months ended September 30, 2009, was 20.3 percent, compared to 23.8 percent for the nine months ended September 30, 2008. IPC’s effective tax rate for the nine months ended September 30, 2009, was 27.2 percent, compared to 32.9 percent for the nine months ended September 30, 2008. The decrease in the 2009 estimated annual effective tax rates from 2008 was primarily due to an examination settlement, state bonus depreciation, and timing and amount of other regulatory flow-through tax adjustments at IPC. The decreases were partially offset by additional income tax expense from greater pre-tax earnings at IDACORP and IPC, and lower tax credits from IFS.

In April 2009, the State of Idaho adopted the federal bonus depreciation provisions enacted as part of the American Recovery and Reinvestment Act of 2009. IPC’s regulatory tax accounting method allows for the flow-through of certain state tax adjustments, including accelerated depreciation. Due to the application of the bonus depreciation provision, IPC was able to reduce its income tax expense by $2.2 million for the nine months ended September 30, 2009.

The Internal Revenue Service (IRS) completed its examination of IDACORP’s 2006 tax year in May 2009. The 2006 examination report was submitted for U.S. Congress Joint Committee on Taxation (JCT) review in June. In July, the JCT completed its review and accepted the report without change. IDACORP considered all uncertain tax positions related to its 2006 tax year effectively settled as of the second quarter, and decreased IPC’s liability for unrecognized tax benefits by $1.3 million.

In March 2009, the JCT completed its review of IDACORP’s 2001-2004 uniform capitalization appeals settlement and 2005 IRS examination report. The JCT accepted both items without change. IDACORP considered these matters effectively settled in 2008 and recorded the related financial effects in its December 31, 2008, financial statements.

The IRS began its examination of IDACORP’s 2007-2008 tax years in July 2009. In May 2009, IDACORP formally entered the IRS Compliance Assurance Process (CAP) program for its 2009 tax year. The CAP program provides for IRS examination throughout the year. The 2007-2009 examinations are expected to be completed in 2010. IDACORP and IPC are unable to predict the outcome of these examinations.

3. COMMON STOCK AND STOCK-BASED COMPENSATION:

During the nine months ended September 30, 2009, IDACORP entered into the following transactions involving its common stock:

• In September 2009, 326,307 original issue shares were issued in at-the-market offerings at an average price of $28.63 per share through the continuous equity program (CEP). An additional 163,053 shares sold in September 2009 settled in October 2009 at an average price of $29.10 per share.

• 112,128 original issue shares and 24,948 treasury shares were used for awards granted under the 2000 Long-Term Incentive and Compensation Plan.

• 28,518 original issue shares and 22,550 treasury shares were used for awards granted under the Restricted Stock Plan.

• 12,936 treasury shares were used for the annual stock grant to directors under the Non-Employee Directors Stock Compensation Plan.

• 283,071 original issue shares were issued under the Dividend Reinvestment and Stock Purchase Plan and the Employee Savings Plan.

IDACORP has a Sales Agency Agreement with BNY Mellon Capital Markets, LLC, as IDACORP’s agent, for the offer and sale of up to 3,000,000 shares of its common stock from time to time in at-the-market offerings. At September 30, 2009, there were 2,301,871 shares remaining available for sale under the CEP. At October 29, 2009 there were 2,138,818 shares remaining available.

IDACORP contributed $20 million in cash as additional equity to IPC in September 2009. No additional shares of IPC common stock were issued.

IDACORP has three share-based compensation plans. IDACORP’s employee plans are the 2000 Long-Term Incentive and Compensation Plan (LTICP) and the Restricted Stock Plan (RSP). These plans are intended to align employee and shareholder objectives related to IDACORP’s long-term growth. IDACORP also has one non-employee plan, the Non-Employee Directors Stock Compensation Plan (DSP). The purpose of the DSP is to increase directors’ stock ownership through stock-based compensation.

The LTICP for officers, key employees and directors permits the grant of nonqualified stock options, incentive stock options, stock appreciation rights, restricted stock, restricted stock units, performance units, performance shares and other awards. The RSP permits only the grant of restricted stock or performance-based restricted stock. At September 30, 2009, the maximum number of shares available under the LTICP and RSP were 1,597,309 and 25,515, respectively.

The following table shows the compensation cost recognized in income and the tax benefits resulting from these plans, as well as the amounts allocated to IPC for those costs associated with IPC’s employees (in thousands of dollars). No equity compensation costs have been capitalized:

	IDACORP				IPC
	Nine months ended				Nine months ended
	September 30,				September 30,
	2009		2008		2009		2008
Compensation cost	$	2,711	$	3,106	$	2,570	$	2,933
Income tax benefit	$	1,060	$	1,214	$	1,005	$	1,147

Stock awards: Restricted stock awards have vesting periods of up to three years. Restricted stock awards entitle the recipients to dividends and voting rights, and unvested shares are restricted as to disposition and subject to forfeiture under certain circumstances. The fair value of restricted stock awards is measured based on the market price of the underlying common stock on the date of grant and is charged to compensation expense over the vesting period based on the number of shares expected to vest. The weighted average fair value at date of grant for restricted stock awards granted during 2009 was $25.48.

Performance-based restricted stock awards have vesting periods of three years. Performance awards entitle the recipients to voting rights, and unvested shares are restricted as to disposition, subject to forfeiture under certain circumstances, and subject to meeting specific performance conditions. Based on the attainment of the performance conditions, the ultimate award can range from zero to 150 percent of the target award. Dividends are accrued during the vesting period and will be paid out only on shares that eventually vest.

The performance goals for these awards are independent of each other and equally weighted, and are based on two metrics, cumulative earnings per share (CEPS) and total shareholder return (TSR) relative to a peer group. The fair value of the CEPS portion is based on the market value at the date of grant, reduced by the loss in time-value of the estimated future dividend payments, using an expected quarterly dividend of $0.30. The fair value of the TSR portion is estimated using a statistical model that incorporates the probability of meeting performance targets based on historical returns relative to the peer group. Both performance goals are measured over the three-year vesting period and are charged to compensation expense over the vesting period based on the number of shares expected to vest. The weighted average fair value at date of grant for CEPS and TSR awards granted during the first nine months of 2009 was $19.50.

Stock option awards are granted with exercise prices equal to the market value of the stock on the date of grant. The options have a term of 10 years from the grant date and vest over a five-year period. The fair value of each option is amortized into compensation expense using graded-vesting. Stock options are not a significant component of share-based compensation awards under the LTICP.

4. LONG-TERM DEBT:

Long-Term Financing

As of September 30, 2009, IDACORP had approximately $579 million remaining on a shelf registration statement that can be used for the issuance of debt securities or common stock. As of October 29, 2009, IDACORP had approximately $574 remaining available on the shelf registration statement.

On March 30, 2009, IPC issued $100 million of 6.15 percent first mortgage bonds, due April 1, 2019. IPC used the net proceeds to repay a portion of its short-term debt in anticipation of utilizing short-term debt to repay $80 million of 7.20 percent first mortgage bonds that mature December 1, 2009. IPC has $130 million remaining on a shelf registration statement that can be used for the issuance of first mortgage bonds and unsecured debt.

In February 2009, IFS repaid $7.2 million of debt related to investments in affordable housing. The debt was scheduled to mature in 2009 and 2010. On May 15, 2009, IFS issued a $6 million equity funding obligation to finance a portion of its $12 million investment in affordable housing. The obligation is scheduled to mature in 2010.

Pollution Control Revenue Refunding Bonds and Term Loan Credit Agreement: On April 3, 2008, IPC made a mandatory purchase of two series of Pollution Control Revenue Refunding Bonds issued for the benefit of IPC, the $116.3 million aggregate principal amount of Pollution Control Revenue Refunding Bonds Series 2006 issued by Sweetwater County, Wyoming due 2026 and the $49.8 million aggregate principal amount of Pollution Control Revenue Refunding Bonds Series 2003 issued by Humboldt County, Nevada due 2024 (together the Pollution Control Bonds). IPC initiated this transaction in order to adjust the interest rate period of the Pollution Control Bonds from an auction interest rate period to a weekly interest rate period, effective April 3, 2008. This change was made to mitigate the higher-than-anticipated interest costs in the auction mode, which was a result of the financial guarantor’s credit ratings deterioration.

On August 20, 2009, J.P. Morgan Securities Inc. as the Remarketing Agent, purchased the Pollution Control Bonds from IPC for remarketing to the public. The Humboldt County Bonds carry a 5.15 percent term interest rate and mature on December 1, 2024. The Sweetwater County Bonds carry a 5.25 percent term interest rate and mature on July 15, 2026. The Pollution Control Bonds are not subject to redemption for 10 years, except for extraordinary optional and mandatory redemption prior to maturity, in each case at 100 percent of the principal amount, plus accrued interest if any to the date of redemption. In connection with the remarketing of the Pollution Control Bonds, the financial guaranty insurance policies securing the Pollution Control Bonds were terminated.

On August 25, 2009, IPC used proceeds from the reoffering of the Pollution Control Bonds and additional corporate funds to prepay its $170 million loan under a Term Loan Credit Agreement dated as of February 4, 2009, among JPMorgan Chase Bank, N.A., as administrative agent and lender, Bank of America, N.A. and Wachovia Bank, National Association, as lenders.

5. NOTES PAYABLE:

Credit Facilities

IDACORP has a $100 million credit facility and IPC 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 bank 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 and S&P.

At September 30, 2009, no loans were outstanding on either IDACORP’s facility or IPC’s facility. At September 30, 2009, IPC had regulatory authority to incur up to $450 million of short-term indebtedness.

Balances and interest rates of short-term borrowings were as follows at September 30, 2009, and December 31, 2008 (in thousands of dollars):

			September 30, 2009						December 31, 2008
			IPC		IDACORP		Total		IPC		IDACORP		Total
Commercial paper
	outstanding		$	-	$	36,780	$	36,780	$	108,950	$	13,400	$	122,350
Other short-term
	borrowings			-		-		-		3,900		25,000		28,900
		Total	$	-	$	36,780	$	36,780	$	112,850	$	38,400	$	151,250

Weighted-average.
	interest rate			0.00%		0.44%		0.44%		4.89%		4.29%		4.74%

6. REGULATORY MATTERS:

Idaho 2008 General Rate Case

On January 30, 2009, the IPUC issued an order approving an average annual increase in Idaho base rates, effective February 1, 2009, of 3.1 percent (approximately $20.9 million annually), a return on equity of 10.5 percent and an overall rate of return of 8.18 percent. On February 19, 2009, IPC filed a request for reconsideration with the IPUC and on March 19, 2009, the IPUC issued an order that increased IPC’s Idaho revenue requirement by an additional $6.1 million to approximately $27 million for this rate case, raising the average rate increase from 3.1 percent to 4.0 percent.

The IPUC denied reconsideration with respect to a refund of $3.3 million of fees recovered by IPC from the FERC. On April 2, 2009, IPC filed an application with the IPUC for an accounting order approving amortization of the fees over a five year period beginning October 2006 when IPC received the FERC credit. The IPUC approved IPC’s requested amortization period in an order issued on April 28, 2009. In the first quarter of 2009, IPC recorded a charge of approximately $1.7 million to electric utility other operations expense and a corresponding regulatory liability for the amount to be refunded from February 1, 2009, through the end of the amortization period, September 2011. As the regulatory liability is amortized it will reduce electric utility other operations expense ratably over the remaining amortization period.

The January 30, 2009 order authorized approximately $15 million related to increases in base net power supply costs. It also allowed IPC to include in rates approximately $6.8 million ($10.6 million including income tax gross-up) of 2009 AFUDC relating to the Hells Canyon Complex relicensing project. Typically, AFUDC is not included in rates until a project is in use and benefitting customers, but the IPUC determined that including this amount in current rates is in the public interest. Because AFUDC is already recorded on an accrual basis, this portion of the rate increase will improve cash flows but will not have a current impact on IPC’s net income. The amounts collected are being deferred as a regulatory liability and will be recognized in revenues over the life of the new license once it has been issued.

Deferred Net Power Supply Costs

IPC’s deferred net power supply costs consisted of the following balances, including applicable carrying charges (in thousands of dollars):

			September 30,		December 31,
			2009		2008
Idaho PCA current year:
	Deferral for the 2009-2010 rate year		$	-	$	93,657
	Deferral for the 2010-2011 rate year			26,121		-
Idaho PCA true-up awaiting recovery:
	Authorized in May 2008			-		47,164
	Authorized in May 2009			66,716		-
Oregon deferral:
	2001 Costs			-		1,663
	2006 Costs			2,285		1,215
	2007 Costs			6,105		-
	2008 Power cost adjustment mechanism			5,725		5,400
		Total deferral	$	106,952	$	149,099

Idaho: IPC has a PCA mechanism that provides for annual adjustments to the rates charged to its Idaho retail customers. The PCA tracks IPC’s actual net power supply costs (fuel, purchased power and third-party transmission expenses less off-system sales) and compares these amounts to net power supply costs currently being recovered in retail rates.

The annual adjustments are based on two components:

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

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

Prior to February 1, 2009, the PCA mechanism provided that 90 percent of deviations in power supply costs were to be reflected in IPC’s rates for both the forecast and the true-up components. Effective February 1, 2009, this sharing percentage was changed to 95 percent.

2009-2010 PCA: On May 29, 2009, the IPUC approved the 2009-2010 PCA of $84.3 million or 10.2 percent, effective June 1, 2009. The 2009-2010 PCA reflects a new methodology discussed in “PCA Workshops” below that utilizes IPC’s most recent operating plan to forecast power supply expenses rather than the previous method based on a forecast of Brownlee Reservoir inflow and a regression formula.

2008-2009 PCA: On May 30, 2008, the IPUC approved IPC’s 2008-2009 PCA and an increase to then-existing revenues of $73.3 million, effective June 1, 2008, which resulted in an average rate increase to IPC’s customers of 10.7 percent. The IPUC’s order adopted an IPUC Staff proposal to use a forecast for power supply costs that equaled the amounts in current base rates. The revenue increase was net of $16.5 million of gains from the 2007 sale of excess SO₂emission allowances, including interest, which the IPUC ordered be applied against the PCA.

PCA Workshops: In its May 30, 2008 order approving IPC’s 2008-2009 PCA, the IPUC directed IPC to set up workshops with the IPUC Staff and several of IPC’s largest customers (together, the Parties) to address PCA-related issues not resolved in the PCA filing. Workshops were conducted in the fall and a settlement stipulation was filed with the IPUC and approved on January 9, 2009.

The following changes were effective as of February 1, 2009:

• PCA sharing ratio – the PCA allocates the deviations in net power supply expenses between customers (95 percent) and shareholders (5 percent). The previous sharing ratio was 90/10.

• LGAR – 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 2007 general rate case reset the LGAR from $29.41 to $62.79 per MWh, but applied that rate to only 50 percent of the load growth beginning in March 2008. In the stipulation, the Parties agreed on the formula for calculating the LGAR. Based on the final rates approved by the IPUC in the 2008 general rate case and the supporting data, the current LGAR is $26.63 per MWh, effective February 1, 2009.

• Use of IPC’s operation plan power supply cost forecast – the operation plan forecast may better match current collections with actual net power supply costs in the year they are incurred and result in smaller amounts being included in the following year’s “true-up” rate, beginning with the 2009-2010 PCA filing.

• Inclusion of third-party transmission expense – transmission expenses paid to third parties to facilitate wholesale purchases and sales of energy, including losses, are a necessary component of net power supply costs. Deviation in these costs from levels included in base rates is now reflected in PCA computations.

• Adjusted distribution of base net power supply costs – base net power supply costs are distributed throughout the year based upon the monthly shape of normalized revenues for purposes of the PCA deferral calculation.

Oregon: IPC has a power cost recovery mechanism in Oregon with two components: the annual power cost update (APCU) and the power cost adjustment mechanism (PCAM). The combination of the APCU and the PCAM allows IPC to recover excess net power supply costs in a more timely fashion than through the previously existing deferral process.

The APCU allows IPC to reestablish its Oregon base net power supply costs annually, separate from a general rate case, and to forecast net power supply costs for the upcoming water year. The APCU has two components: the “October Update,” where each October IPC calculates its estimated normalized net power supply expenses for the following April through March test period, and the “March Forecast,” where each March IPC files a forecast of its expected net power supply expenses for the same test period, updated for a number of variables including the most recent stream flow data and future wholesale electric prices. On June 1 of each year, rates are adjusted to reflect costs calculated in the APCU.

The PCAM is a true-up filed annually in February. The filing calculates the deviation between actual net power supply expenses incurred for the preceding calendar year and the net power supply expenses recovered through the APCU for the same period. Under the PCAM, IPC is subject to a portion of the business risk or benefit associated with this deviation through application of an asymmetrical deadband (or range of deviations) within which IPC absorbs cost increases or decreases. For deviations in actual power supply costs outside of the deadband, the PCAM provides for 90/10 sharing of costs and benefits between customers and IPC. However, a collection will occur only to the extent that it results in IPC’s actual return on equity (ROE) for the year being no greater than 100 basis points below IPC’s last authorized ROE. A refund will occur only to the extent that it results in IPC’s actual ROE for that year being no less than 100 basis points above IPC’s last authorized ROE. The PCAM rate is then added to or subtracted from the APCU rate, subject to certain statutory limitations discussed below, with new combined rates effective each June 1.

2010 APCU: On October 19, 2009, IPC filed the October Update portion of its 2010 APCU with the OPUC. The filing reflects that revenues associated with IPC’s base net power supply costs would be increased by $2.6 million over the current APCU, an average 8.2 percent increase. The actual impact of the 2010 APCU will be determined once the March Forecast portion is filed in March 2010 and combined with the October Update. Final rates are expected to become effective on June 1, 2010.

2009 APCU: On October 23, 2008, IPC filed the October Update portion of its 2009 APCU with the OPUC. The filing, combined with supplemental testimony filed on December 1, 2008, reflects that revenues associated with IPC’s base net power supply costs would be increased by $1.6 million over the previous October Update, an average 4.6 percent increase.

On March 20, 2009, IPC filed the March Forecast portion of its 2009 APCU. When combined with the October Update, the March Forecast resulted in a requested increase to Oregon revenues of 11.5 percent, or $3.9 million annually. On May 26, 2009, the OPUC approved the requested rate increase effective June 1, 2009.

2008 APCU: On May 20, 2008, the OPUC approved IPC’s 2008 APCU (comprising both the October Update and the March Forecast) with the new rates effective June 1, 2008. The approved APCU resulted in a $4.8 million, or 15.7 percent, increase in Oregon revenues.

2008 PCAM: On February 27, 2009, IPC filed the true-up of its net power supply costs for the period January 1 through December 31, 2008, with the OPUC. The 2008 PCAM filing reflects a deviation of actual net power supply costs above the forecast for that period of $7.4 million. After the application of the deadband, the filing requests that $5.0 million be added to IPC’s true-up balancing account and amortized sequentially after the amounts discussed below under “Oregon Excess Power Cost Deferrals.” A pre-hearing conference was held on April 27, 2009, to discuss the status of the case. A joint workshop and settlement conference was held July 7, 2009. As a result of the conference, IPC filed supplemental testimony on October 14, 2009, that reflects agreed upon changes to the calculation of the deferral. The revised 2008 PCAM filing now reflects a deviation of actual net power supply costs above the forecast for that period of $7.7 million and requests that $5.1 million be added to IPC’s true-up balancing account and amortized sequentially.

Oregon Excess Power Cost Deferrals: The timing of future recovery of Oregon power supply cost deferrals is subject to an Oregon statute that specifically limits rate amortizations of deferred costs to six percent of gross Oregon revenue per year ($1.9 million for 2009 based on 2008 revenues). On October 6, 2008, the OPUC issued an order clarifying that the PCAM is also a deferral under the Oregon statute. The following deferrals were authorized under processes existing prior to the establishment of the PCAM.

May-December 2007 Excess Power Costs: On April 30, 2007, IPC filed for an accounting order with the OPUC to defer net power supply costs for the period from May 1, 2007, through April 30, 2008, in anticipation of higher than “normal” (higher than base) power supply expenses. In the filing, IPC included a forecast of Oregon’s jurisdictional share of excess power supply costs of $5.7 million. Settlement discussions were held in February 2009. As a result of those discussions, the parties to the proceeding reached a settlement and a stipulation was filed with the OPUC on April 8, 2009. In the stipulation, the parties agreed to limit the calculation of excess net power supply costs in this docket to the eight-month period from May 1 through December 31, 2007. Based on the methodology adopted by the parties to the stipulation, it was determined that IPC should be allowed to defer excess net power supply costs of $6.4 million (including interest through the date of the order) for that period. The amount to be recovered was reduced by $0.9 million of emission allowance sales (including interest) during the same period allocated to Oregon, resulting in an approved deferral balance of $5.5 million. IPC recorded the $6.4 million deferral in the second quarter 2009 as a reduction to power cost adjustment expense. The emission allowances sales were previously deferred. The parties also agreed that the excess power supply costs from the period beginning in 2008 would be deferred pursuant to the PCAM agreement established as part of the power cost variance filing for 2008 and calculated according to the PCAM. On May 28, 2009, the OPUC issued its order adopting the stipulation.

2006-2007 Excess Power Costs: On June 30, 2009, IPC filed an application with the OPUC to begin amortizing through rates the 2006-2007 deferral of $2.0 million plus $0.4 million of accrued interest, effective September 1, 2009. The OPUC issued an order approving IPC’s application on September 1, 2009. IPC expects amortization of this deferral to take approximately 16 months. The May 1 - December 31, 2007 deferral of $6.1 million (net of the emission allowance adjustment and including accrued interest) and the $5.7 million 2008 PCAM balance (including accrued interest) will be recovered sequentially following the full recovery of the 2006-2007 deferral.

Fixed Cost Adjustment Mechanism (FCA)

On March 12, 2007, the IPUC approved the implementation of a FCA mechanism pilot program for IPC’s residential and small general service customers. The pilot program began on January 1, 2007, and runs through 2009. The FCA is a rate mechanism designed to remove IPC’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. In the FCA, for each customer class, the number of customers is multiplied by a fixed cost per customer. The cost per customer is based on IPC’s revenue requirement as established in a general rate case. This authorized fixed cost recovery amount is compared to the amount of fixed costs actually recovered by IPC. The amount of over- or under-recovery is then returned to or collected from customers in a subsequent rate adjustment. On October 1, 2009, IPC filed an application with the IPUC to make the FCA mechanism permanent beginning with the June 1, 2010 rate change.

On May 29, 2009, the IPUC approved a rate increase, effective June 1, 2009 through May 31, 2010, to recover $2.7 million of fixed costs under-recovered during 2008. On May 30, 2008, the IPUC approved a rate reduction, effective June 1, 2008 through May 31, 2009, to return $2.4 million of fixed costs over-recovered in 2007.

IPC deferred fixed costs of $5.0 million related to the FCA during the first nine months of 2009.

Energy Efficiency Matters

Idaho Energy Efficiency Rider (Rider): IPC’s Rider is the chief funding mechanism for IPC’s investment in energy efficiency and demand response programs. On May 29, 2009, the IPUC approved IPC’s application to increase the Rider to 4.75 percent of base revenues, effective June 1, 2009. Based on 2008 test year revenue, IPC expects Rider revenues of $27.3 million in 2009 and $33.2 million in each of 2010 and 2011. Effective June 1, 2008, IPC began collecting 2.5 percent of base revenues, or approximately $17 million annually, under the Rider. Prior to that date, IPC collected 1.5 percent of base revenues, with funding caps for residential and irrigation customers.

Energy Efficiency Prudency Review: In the 2008 general rate case, IPC requested that the IPUC explicitly find that IPC’s expenditures between 2002 and 2007 of $29 million of funds obtained from the Rider were prudently incurred and would, therefore, no longer be subject to potential disallowance. The IPUC Staff recommended that the IPUC defer a prudency determination for these expenditures until IPC was able to provide a comprehensive evaluation package of its programs and efforts. IPC contended that sufficient information had already been provided to the IPUC Staff for review.

On February 18, 2009, IPC filed a stipulation with the IPUC reflecting an agreement with the IPUC Staff on $14.3 million of the Rider funds. The IPUC Staff agreed that this portion of the Rider expenditures were prudently incurred. On March 6, 2009, the IPUC approved the stipulation, identifying $18.3 million as prudent, which included $14.3 million of Rider funding and $4.0 million of other funds.

On April 1, 2009, IPC filed an application with the IPUC seeking a prudency determination on the $14.7 million balance of Rider funds spent during 2002 through 2007. IPC has requested that this application be processed under modified procedure.

On October 5, 2009, IPC and other investor-owned electric utilities serving in Idaho engaged in an informal public workshop with the IPUC Staff to discuss how energy efficiency evaluation and prudency will be determined on a prospective basis. The IPUC Staff is expected to propose a process for energy efficiency expenditure approval as a result of the workshop.

Advanced Metering Infrastructure (AMI)

The AMI project provides the means to automatically retrieve energy consumption information, eliminating manual meter reading expense. In the future, the system will support enhancements to allow for time-variant rates, perform remote connects and disconnects, and collect system operations data enhancing outage management, reliability efforts and demand-side management options.

IPC filed AMI evaluation and deployment reports with the IPUC on May 1 and August 31, 2007, in compliance with an IPUC order. Consistent with the implementation plan contained in those reports, IPC entered into a number of contracts for materials and resources that allowed for the AMI implementation to commence in late 2008. IPC 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 scheduled.

Idaho: On August 5, 2008, IPC filed an application with the IPUC requesting a CPCN for the deployment of AMI technology and approval of accelerated depreciation for the existing metering equipment. The IPUC approved IPC’s application on February 12, 2009. In its application, IPC estimated the three-year investment in AMI to be $70.9 million. In an April 7, 2009, order, the IPUC clarified that IPC can expect in the ordinary course of events, to include in rate base the prudent capital costs of deploying AMI as it is placed in service up to the capital cost commitment estimate of $70.9 million. The IPUC also clarified, as requested by IPC, that it does not anticipate that the immediate savings derived from the implementation of AMI throughout IPC’s service territory will eliminate or wholly offset the increase in IPC’s revenue requirement caused by the authorized depreciation period.

On March 13, 2009, IPC filed an application with the IPUC for authority to increase its rates due to the inclusion of AMI investment in rate base. The filing requested inclusion of the investments already made for the installation of AMI throughout IPC’s service territory, and those investments that would be made during a June 1, 2009, through May 31, 2010 test year. IPC requested a first year revenue requirement of $11.2 million in the Idaho jurisdiction effective June 1, 2009, for service provided on or after that date. In its calculations, IPC reflected the reduction in investment and the accelerated depreciation costs related to the removal of current metering equipment, as well as changes in operating expenses that accompany the changes in plant investment.

On May 29, 2009, the IPUC approved annual recovery of $10.5 million, effective June 1, 2009. The order was based on IPC’s actual investment in AMI to date, annualized through December 31, 2009, rather than IPC’s proposed test year. The IPUC also allowed IPC to begin three-year accelerated depreciation of the existing metering equipment on June 1, 2009. The order reflects annualized depreciation expense relating to AMI of $9.2 million. The actual depreciation expense for fiscal year 2009 will occur over seven months totaling $6.2 million. IPC has recorded $3.5 million of this amount through September 30, 2009.

Oregon: On October 3, 2008, IPC filed an application with the OPUC requesting authority to accelerate the depreciation and recovery of existing meters in the Oregon jurisdiction over an 18-month period beginning January 2009. The OPUC approved IPC’s request on December 30, 2008. IPC’s AMI deployment schedule calls for the replacement of the Oregon service-territory meters around October 2010. The existing meters will be fully depreciated prior to their removal from service. The filing estimated the balance of plant in service at December 31, 2008, attributable to the existing meters to be $1.4 million. The approval of this application results in an increase of $0.8 million for 2009 in both rates and depreciation expense. This increase is partially offset by the reduced depreciation rates discussed below in “Depreciation Filings.” Combined, the two adjustments result in a $0.4 million net increase to annual depreciation during the period of accelerated recovery.

Depreciation Filings

On September 12, 2008, the IPUC approved a revision to IPC’s depreciation rates, retroactive to August 1, 2008. The new rates are based on a settlement reached by IPC and the IPUC Staff, and result in an annual reduction of depreciation expense of $8.5 million ($7.9 million allocated to Idaho) based upon December 31, 2006, depreciable electric plant in service.

On October 3, 2008, IPC filed an application with the OPUC requesting that the new depreciation rates approved in IPC’s Idaho jurisdiction be authorized for IPC’s Oregon jurisdiction as well. The result for the Oregon jurisdiction would be a decrease in annual depreciation expense and rates of $0.4 million (excluding the impacts of accelerated depreciation of existing Oregon meters as discussed above in “Advanced Metering Infrastructure (AMI) - Oregon”). On August 18, 2009, the OPUC approved a stipulation whereby the OPUC Staff agreed not to make adjustments to the depreciation rates adopted by the IPUC. IPC committed to joint involvement of OPUC Staff prior to submitting future depreciation rates for approval in IPC’s Idaho jurisdiction.

On December 3, 2009, the FERC approved IPC’s request to use the IPUC- approved depreciation rates in future FERC rate filings. The new depreciation accrual rates were reflected in IPC’s OATT rates beginning October 1, 2009.

Idaho Open Access Transmission Tariff (OATT) Shortfall Filing
For Idaho jurisdictional revenue requirement determinations, revenues from third parties (non-state jurisdictional) received through the OATT, referred to as revenue credits, are a direct offset to IPC’s overall revenue requirement. In the last two general rate cases, IPC included an estimate of OATT revenues from third parties based on the forecasted OATT rate less a reserve. However, as discussed below in “OATT”, the FERC order issued on January 15, 2009 had a significant impact on actual third-party transmission revenues IPC received from June 2006 to date, resulting in the overstating of the revenue credits in the Idaho jurisdictional revenue requirement authorized by the IPUC. On July 20, 2009, IPC filed a request with the IPUC for authorization to defer $8.1 million in costs associated with the difference between the revenue credits and the amount of OATT revenues IPC has received since March 2008 and expects to receive through May 2010. Included in the filing are $4.3 million for the period March 1, 2008, through January 31, 2009, the effective period of the February 28, 2008, general rate case order and $3.8 million estimated for the period February 1, 2009, through May 31, 2010, the expected effective period of the January 30, 2009, general rate case order. IPC requested to amortize the unrecovered transmission revenues on a straight-line basis over a three-year period beginning June 1, 2010, and to receive a carrying charge on the balance until rate recovery begins. The application is proceeding under modified procedure. IPC has filed a request for rehearing of the FERC order and is taking additional measures to address the revenue shortfall. If the FERC issues are resolved in IPC’s favor, IPC will reduce the deferral. On September 29, 2009, the IPUC Staff filed comments. Both parties have agreed to reduce the calculation of the total deferral from $8.1 million to $4.7 million to reflect transmission rate increases that became effective after IPC filed its application.

OATT

On March 24, 2006, IPC submitted a revised OATT filing with the FERC requesting an increase in transmission rates. In the filing, IPC proposed to move from a fixed rate to a formula rate, which allows for transmission rates to be updated each year based on financial and operational data IPC is required to file annually with the FERC in its Form 1. The formula rate request included a rate of return on equity of 11.25 percent. IPC’s filing was opposed by several affected parties. Effective June 1, 2006, the FERC accepted IPC’s proposed new rates, subject to refund pending the outcome of the hearing and settlement process.

On August 8, 2007, the FERC approved a settlement agreement by the parties on all issues except the treatment of contracts for transmission service that contain their own terms, conditions and rates that were in existence before the implementation of OATT in 1996 (Legacy Agreements). This settlement reduced IPC’s proposed new rates and, as a result, approximately $1.7 million collected in excess of the settlement rates between June 1, 2006, and July 31, 2007, was refunded with interest in August 2007. As part of the settlement agreement, the FERC established an authorized rate of return on equity of 10.7 percent.

On August 31, 2007, the FERC Presiding Administrative Law Judge (ALJ) issued an initial decision (Initial Decision) with respect to the treatment of the Legacy Agreements, which would have further reduced the new transmission rates. IPC, as well as the opposing parties, appealed the Initial Decision to the FERC. If implemented, the Initial Decision would have required IPC to make additional refunds, of approximately $5.4 million (including $0.4 million of interest) for the June 1, 2006, through December 31, 2008, period. IPC previously reserved this entire amount.

On January 15, 2009, the FERC issued an Order on Initial Decision (FERC Order), which upheld the Initial Decision of the ALJ in most respects, but modified the Initial Decision in one respect that is unfavorable to IPC. The decision required IPC to reduce its transmission service rates to FERC jurisdictional customers. Furthermore, IPC was required to make refunds to FERC jurisdictional transmission customers in the total amount of $13.3 million (including $1.1 million in interest) for the period since the new rates went into effect in June 2006. Based on the FERC Order IPC reserved an additional $7.9 million (including $0.7 million in interest) in the fourth quarter of 2008, bringing the total reserve amount to $13.3 million. Prior to the FERC Order, the FERC jurisdictional transmission revenues (net of the $5 million reserve) recorded in the last seven months of 2006, all of 2007 and 2008 were $8.1 million, $13.3 million and $15.8 million, respectively. Under the FERC Order, the transmission revenues would have been $6.4 million in the last seven months of 2006, $11 million in 2007 and $12.6 million in 2008. Refunds were made on February 25, 2009.

IPC filed a request for rehearing with the FERC on February 17, 2009. IPC believes that the treatment of the Legacy Agreements conflicts with precedent. The rehearing request asserts that the FERC order is in error by: (1) requiring IPC to include the contract demands associated with the Legacy Agreements in the OATT formula rate divisor rather than crediting the revenue from the Legacy Agreements against IPC’s transmission revenue requirement; (2) concluding that IPC must include the contract demands associated with the Legacy Agreements rather than the customers’ coincident peak demands; (3) concluding that the transmission rate contained in one or more of the Legacy Agreements was not a discounted rate; (4) failing to consider the non-monetary benefits received by IPC from the Legacy Agreements; (5) concluding that the services provided under the Legacy Agreements are firm services and therefore should be handled for rate purposes in the same manner as firm services under the OATT; and (6) failing to affirm the rate treatment that has been used for the Legacy Agreements for approximately 30 years. On March 18, 2009, the FERC issued a tolling order that effectively relieves it from acting on the request for reconsideration for an indefinite time period. IPC cannot predict when the FERC will rule on the request for rehearing or the outcome of this matter.

Amended Legacy Agreements: Subsequent to the January 15, 2009 FERC Order, IPC has sought to mitigate the resulting revenue shortfall by revising certain of the Legacy Agreements as provided for in the agreements.

On April 3, 2009, IPC notified PacifiCorp that it was terminating its provision of a portion of the services that it provides under the Restated Transmission Service Agreement (RTSA), a Legacy Agreement, effective June 12, 2009. IPC made a filing with the FERC on April 13, 2009 submitting revised rate schedule sheets. The FERC accepted the revised rate schedule sheets by letter order on May 14, 2009. On June 12, 2009 IPC submitted a filing for the purpose of replacing the terminated contract services with OATT service, effective June 13, 2009. An amended RTSA between IPC and PacifiCorp and three long term service agreements were filed to provide for the OATT service. As calculated in the filings, the estimated net transmission revenue increase for the period June 13, 2009 through June 12, 2010 is approximately $3.2 million. The FERC accepted IPC’s filing, effective June 13, 2009, by letter order on July 28, 2009.

On June 19, 2009 IPC submitted a filing to increase rates under the Agreement for Interconnection and Transmission Services (ITSA) contract, another Legacy Agreement between IPC and PacifiCorp. The filing requested an increase of rates to the level paid by OATT customers for Point to Point service and an August 19, 2009 effective date. As calculated in the filing, the estimated net transmission revenue increase for the period September 1, 2009 through August 31, 2010 is approximately $3.9 million. PacifiCorp has intervened in the case and on July 10, 2009 filed a motion to suspend the case for five months and pursue settlement or go to hearing. On August 18, 2009, the FERC accepted IPC’s filing and suspended it, setting it for settlement judge procedures and hearing. IPC is collecting the new rates subject to refund and has reserved the entire increase pending settlement. A settlement conference was held on October 7, 2009, and another is scheduled for November 18, 2009. Settlement discussions are ongoing.

2009 OATT: On August 28, 2009, IPC filed its informational filing with the FERC that contains the annual update of the formula rate based on the 2008 test year. The new rate included in the filing was $15.83 per kW-year, an increase of $2.02 per kW-year, or 14.6 percent. New rates were effective October 1, 2009.

2008 OATT: On August 28, 2008, IPC filed its informational filing with the FERC that contained the annual update of the formula rate based on the 2007 test year. The rate included in the filing was $18.88 per kW-year, a decrease of $0.85 per kW-year, or 4.3 percent. New rates were effective October 1, 2008. IPC subsequently adjusted its rates to $13.81 per kW-year in compliance with the January 15, 2009 order.

7. COMMITMENTS AND CONTINGENCIES:

Purchase Obligations

The following items are the material changes to purchase obligations made outside of the ordinary course of business since December 31, 2008:

• IPC entered into a contract to purchase coal from the Black Butte Coal Company for use at the Jim Bridger generating plant, in which IPC holds a one-third ownership. The contract is expected to total $127 million from 2010 to 2014.

• In February, 2009, IPC entered into a contract with EnerNOC to implement and operate a demand response program for its commercial and industrial customers. IPC estimates it will spend approximately $12.2 million on the program during the five year term of the contract.

• IPC entered into two contracts with Siemens Energy, Inc. to purchase gas and steam turbine equipment and services for the Langley Gulch power plant. IPC estimates it will spend approximately $90 million on the contracts from 2009 through 2012.

• On May 7, 2009, IPC entered into an Engineering, Procurement and Construction Services Agreement (EPC Agreement) with Boise Power Partners Joint Venture, a joint venture consisting of Kiewit Power Engineers Co. and TIC-The Industrial Company for design, engineering, procurement, construction management and construction services for the Langley Gulch power plant. The total contract price to be paid by IPC under the EPC Agreement is approximately one-half of the projected $427 million total project cost for Langley Gulch from 2009 to 2012.

• On June 30, 2009, IPC entered into a contract with Cargill Environmental Finance to purchase power from the Bettencourt B6 dairy anaerobic digester located near Jerome, Idaho. IPC expects the contract to total $8 million from 2009 to 2029. This agreement does not have a specified term.

• In the third quarter, IPC entered into several purchased power agreements with wind and other alternate energy developers. These agreements are expected to total approximately $313 million from 2010 to 2030.

• On August 12, 2009, IPC entered into a multi-year Tribal Water Rental Agreement with the Shoshone-Bannock Tribal Water Supply Bank. The agreement is expected to total approximately $10 million from 2009 to 2013.

• On September 1, 2009, IPC entered into a purchased power contract with Idaho Winds, LLC. IPC’s energy purchases under the contract are expected to total $105 million from 2012 to 2032.

Guarantees

IPC has agreed to guarantee the performance of reclamation activities at Bridger Coal Company of which Idaho Energy Resources Co., a subsidiary of IPC, owns a one-third interest. This guarantee, which is renewed each December, was $63 million at September 30, 2009. Bridger Coal Company has a reclamation trust fund set aside specifically for the purpose of paying these reclamation costs. Bridger Coal Company continually assesses the adequacy of the reclamation trust fund and recently revised their estimate of future reclamation costs. In order to ensure that the reclamation trust fund maintains adequate reserves, Bridger Coal Company will adjust coal prices by adding a per ton surcharge. As an additional safeguard, the Bridger Reclamation Trust Investment Committee has authority to compel a per-ton surcharge to ensure adequate funding levels. 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.

Legal Proceedings

From time to time IDACORP and IPC are parties to legal claims, actions and complaints in addition to those discussed below. Although they will vigorously defend against them, IDACORP and IPC are unable to predict with certainty whether or not they will ultimately be successful. However, based on the companies’ evaluation, they believe that the resolution of these matters, taking into account existing reserves, will not have a material adverse effect on IDACORP’s or IPC’s consolidated financial positions, results of operations or cash flows.

Reference is made to IDACORP’s and IPC’s Annual Report on Form 10-K for the year ended December 31, 2008, and Quarterly Reports on Form 10-Q for the quarters ended March 31, 2009, and June 30, 2009, for a discussion of all material pending legal proceedings to which IDACORP and IPC and their subsidiaries are parties. The following discussion provides a summary of material developments that occurred in those proceedings during the period covered by this report and of any new material proceedings instituted during the period covered by this report.

Western Energy Proceedings at the FERC:

Throughout 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. Some of these proceedings (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 pending in the Ninth Circuit approximately 200 petitions for review of numerous FERC orders regarding the western energy situation, including the California refund proceeding and show cause orders with respect to contentions of market manipulation. Decisions in these appeals may have implications with respect to other pending cases, including those to which IDACORP, IPC or IE are parties. IDACORP, IPC and IE intend to vigorously defend their positions in these proceedings, but are unable to predict the outcome of these matters, except as otherwise stated below, or estimate the impact they may have 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. In April 2001, the FERC issued an order stating that it was establishing a price mitigation plan for sales in the California wholesale electricity market. The FERC’s order also included the potential for directing electricity sellers into California from October 2, 2000, through June 20, 2001, to refund portions of their spot market sales prices if the FERC determined that those prices were not just and reasonable. In July 2001, the FERC initiated the California refund proceeding including evidentiary hearings to determine the scope and methodology for determining refunds. After evidentiary hearings, the FERC issued an order on refund liability on March 26, 2003, and later denied the numerous requests for rehearing. The FERC also required the California Independent System Operator (Cal ISO) to make a compliance filing calculating refund amounts. That compliance filing has been delayed on a number of occasions and has not yet been filed with the FERC.

IE and other parties 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 by potential refund payors, including IE, potential refund recipients and governmental agencies. These cases have been consolidated before the Ninth Circuit. Since the initiation of these cases, the Ninth Circuit has convened a number of case management proceedings to organize these complex cases, while identifying and severing discrete cases that can proceed to briefing and decision and staying action on all of the other consolidated cases.

In its October 2005 decision in the first of the severed cases, the Ninth Circuit concluded that the FERC lacked refund authority over wholesale electrical energy sales made by governmental entities and non-public utilities. In its August 2006 decision in the second severed case, the Ninth Circuit ruled that all transactions that occurred within the California Power Exchange (CalPX) and the Cal ISO markets were proper subjects of the refund proceeding, refused to expand the proceedings into the bilateral market, approved the refund effective date as October 2, 2000, 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. These latter aspects of the decision exposed sellers to increased claims for potential refunds. A number of public entities filed petitions for panel rehearing in June 2007 and certain marketers filed petitions for rehearing and rehearing en banc in November 2007. Those requests were denied by the Ninth Circuit on April 6, 2009. The Ninth Circuit issued a mandate on April 15, 2009, thereby officially returning the cases to the FERC for further action consistent with the court’s decision.

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 IPC made such a cost filing but it was rejected by the FERC in March 2006. IE and IPC requested rehearing of that rejection, but, consistent with obligations established in a settlement which is described in the following paragraph, IE and IPC withdrew that request for rehearing to the extent it pertained to the disputes about the cost filing between IE and IPC and parties that had joined the settlement. On June 18, 2009 FERC issued an order with respect to the cost filings of other sellers and in that order also stated that it was not ruling on the IE and IPC request for rehearing because it had been withdrawn. On July 8, 2009 IE and IPC sought further rehearing pointing out to the FERC that the withdrawal pertained only to the parties with whom IE and IPC had settled. On June 18, 2009, in a separate order, the FERC also ruled that net refund recipients in the California refund proceeding were responsible for the costs associated with all cost filings. Most of the parties that joined the IE and IPC settlement described below were net refund recipients, but until the Cal ISO completes its refund calculations it is uncertain whether any parties who opted not to join the settlement are net refund recipients. If there are no such parties, then the requests for rehearing will be moot. On August 7, 2009 the FERC issued an order extending the time for its consideration of the IE and IPC request for rehearing. IE and IPC are unable to predict how or when the FERC might rule on their requests for rehearing, but their effect is confined to obligations of IE and IPC to the minority of market participants that opted not to join the settlement described below. Accordingly, IE and IPC believe this matter will not have a material adverse effect on their consolidated financial positions, results of operations or cash flows.