Edgar Filing: IDAHO POWER CO

UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-K

(Mark One)

X	ANNUAL REPORT PURSUANT TO SECTION 13 OR 15 (d) OF
	THE SECURITIES EXCHANGE ACT OF 1934

	For the fiscal year ended December 31, 2009

	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 in
Commission	their charters, address of principal executive	IRS Employer
File Number	offices, zip code and telephone number	Identification 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 and www.idahopower.com

		Name of exchange on
SECURITIES REGISTERED PURSUANT TO SECTION 12(b) OF THE ACT:		which registered
IDACORP, Inc.: Common Stock, without par value		New York

SECURITIES REGISTERED PURSUANT TO SECTION 12(g) OF THE ACT:
Idaho Power Company: Preferred Stock

Indicate by check mark whether the registrants are well-known seasoned issuers, as defined in Rule 405 of the Securities Act.

IDACORP, Inc.

Yes

( X )

( )

Idaho Power Company

Yes

( )

( X )

Indicate by check mark if the registrants are not required to file reports pursuant to Section 13 or Section 15(d) of the Act.

IDACORP, Inc.

Yes

( )

( X )

Idaho Power Company

Yes

( )

( X )

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 registrant has submitted electronically and posted on its corporate Web site, 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 registrant was required to submit and post such files). Yes ___No ___

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrants’ knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. ( X )

Indicate by check mark whether the registrants are large accelerated filers, accelerated filers, non-accelerated filers, or smaller reporting companies.

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 Act).

IDACORP, Inc.

Yes

( )

( X )

Idaho Power Company

Yes

( )

( X )

Aggregate market value of voting and non-voting common stock held by nonaffiliates (June 30, 2009):

IDACORP, Inc.:

$1,224,885,216

Idaho Power Company:

None

Number of shares of common stock outstanding at January 31, 2010:

IDACORP, Inc.:	47,951,829
Idaho Power Company:	39,150,812 all held by IDACORP, Inc.

Documents Incorporated by Reference:

Part III, Items 10 - 14	Portions of IDACORP, Inc.’s definitive proxy statement to be filed pursuant to Regulation 14A for the Annual Meeting of Shareholders to be held on May 20, 2010.

This combined Form 10-K 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 representation as to the information relating to IDACORP, Inc.’s other operations.

Idaho Power Company meets the conditions set forth in General Instruction (I)(1)(a) and (b) of Form 10-K 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
Cal ISO	-	California Independent System Operator
CalPX	-	California Power Exchange
CAMP	-	Comprehensive Aquifer Management Plan
CO₂	-	Carbon Dioxide
cfs	-	Cubic feet per second
EIS	-	Environmental impact statement
EPS	-	Earnings per share
ESA	-	Endangered Species Act
ESPA	-	Eastern Snake Plain Aquifer
FASB	-	Financial Accounting Standards Board
FCA		Fixed Cost Adjustment mechanism
FERC	-	Federal Energy Regulatory Commission
FIN	-	Financial Accounting Standards Board Interpretation
Fitch	-	Fitch, Inc.
FPA	-	Federal Power Act
GAAP	-	Generally Accepted Accounting Principles
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.
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
NOx	-	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
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
WECC	-	Western Electricity Coordinating Council

TABLE OF CONTENTS
					Page
Part I

	Item 1.		Business		5-14
	Item 1A.		Risk Factors		15-19
	Item 1B.		Unresolved Staff Comments		19
	Item 2.		Properties		20-21
	Item 3.		Legal Proceedings		21
	Item 4.		Submission of Matters to a Vote of Security Holders		21

	Executive Officers of the Registrants				21-22

Part II

	Item 5.		Market for Registrant’s Common Equity, Related Stockholder
				Matters and Issuer Purchases of Equity Securities	23-24
	Item 6.		Selected Financial Data		25
	Item 7.		Management’s Discussion and Analysis of Financial Condition and
				Results of Operations	25-61
	Item 7A.		Quantitative and Qualitative Disclosures about Market Risk		61-62
	Item 8.		Financial Statements and Supplementary Data		63
	Item 9.		Changes in and Disagreements with Accountants on Accounting and
				Financial Disclosure	121
	Item 9A.		Controls and Procedures		121-126
	Item 9B.		Other Information		126

Part III

	Item 10.		Directors, Executive Officers and Corporate Governance*		126
	Item 11.		Executive Compensation*		126
	Item 12.		Security Ownership of Certain Beneficial Owners and Management and Related
				Stockholder Matters*	127
	Item 13.		Certain Relationships and Related Transactions, and Director Independence*		127
	Item 14.		Principal Accountant Fees and Services*		127-129

Part IV

	Item 15.		Exhibits and Financial Statement Schedules		129-141

	Signatures				142-143



	*Except as indicated in Item 12, IDACORP, Inc. information is incorporated by reference to IDACORP,
		Inc.’s definitive proxy statement for the 2010 Annual Meeting of Shareholders.

SAFE HARBOR STATEMENT

This Form 10-K 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-K at Part II, Item 7- “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,” or similar expressions.

PART I - IDACORP, INC. AND IDAHO POWER COMPANY

ITEM 1. BUSINESS

OVERVIEW

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

Idaho Power was incorporated under the laws of the state of Idaho in 1989 as successor to a Maine corporation organized in 1915. Idaho Power is an electric utility engaged in the generation, transmission, distribution, sale and purchase of electric energy and is regulated by the FERC and the state regulatory commissions of Idaho and Oregon. Idaho Power is the parent of Idaho Energy Resources Co. (IERCo), a joint venturer in Bridger Coal Company (Bridger Coal), which supplies coal to the Jim Bridger generating plant owned in part by Idaho Power.

IDACORP’s other subsidiaries include:

• IDACORP Financial Services, Inc. (IFS), an investor in affordable housing and other real estate investments;

• Ida-West Energy Company (Ida-West), an operator of small hydroelectric generation projects that satisfy the requirements of the Public Utility Regulatory Policies Act of 1978 (PURPA); and

• IDACORP Energy (IE), a marketer of energy commodities, which wound down operations in 2003.

IDACORP’s business strategy emphasizes Idaho Power as IDACORP’s core business. Idaho Power is IDACORP’s only reportable business segment, contributing 98.6 percent of IDACORP’s income from continuing operations in 2009. Segment data is presented in Note 17 to the consolidated financial statements. At December 31, 2009, IDACORP had 1,994 full-time employees, 1,979 of which were employed by Idaho Power.

Idaho Power detailed a three-part strategy of responsible planning, responsible development and protection of resources, and responsible energy use to ensure adequate energy supplies. Idaho Power continues to evaluate and refine its business strategy to ensure coordination among and integration of all functional areas of the company. Idaho Power’s business strategy balances the interests of owners, customers and employees while maintaining the company’s financial stability and flexibility. The strategy includes:

RESPONSIBLE PLANNING: Idaho Power’s planning process is intended to ensure adequate generation and transmission resources to meet population growth and increasing electricity demand. This planning process now integrates Idaho Power’s regulatory strategy and financial planning, including the consideration of regional economic development in the growing communities we serve.

RESPONSIBLE DEVELOPMENT AND PROTECTION OF RESOURCES: Idaho Power’s business strategy has included the development and protection of generation, transmission, distribution and associated infrastructure, and the natural resources Idaho Power depends upon. The strategy now includes specific consideration of workforce planning, development and retention related to these strategic elements.

RESPONSIBLE ENERGY USE: Idaho Power’s business strategy has included energy efficiency and demand response programs and preparation for potential carbon and renewable portfolio standard legislation. The strategy now includes targeted reductions relating to carbon emission intensity and public disclosure of these reductions.

IDACORP and Idaho Power make available free of charge their Annual Report on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K and all amendments to these reports filed or furnished pursuant to Section 13(a) or 15(d) of the Securities Exchange Act of 1934 as soon as reasonably practicable after the reports are electronically filed with or furnished to the Securities and Exchange Commission. IDACORP’s website is www.idacorpinc.com and can also be accessed through a link to the IDACORP website on the Idaho Power website at www.idahopower.com.

UTILITY OPERATIONS

Idaho Power’s service territory covers approximately 24,000 square miles in southern Idaho and eastern Oregon, with an estimated population of one million. Idaho Power holds franchises in 71 cities in Idaho and nine cities in Oregon and holds certificates from the respective public utility regulatory authorities to serve all or a portion of 25 counties in Idaho and three counties in Oregon. As of December 31, 2009, Idaho Power supplied electric energy to approximately 490,000 general business customers. Idaho Power’s principal commercial and industrial customers are involved in food processing, electronics and general manufacturing, forest products, beet sugar refining and winter recreation.

Weather, customer demand and economic conditions impact electricity sales. Extreme temperatures increase sales to customers who use electricity for cooling and heating, and moderate temperatures decrease sales. Increased precipitation levels during the agricultural growing season reduce electricity sales to customers who use electricity to operate irrigation pumps.

Rates and Revenues

Retail

Electric utilities have historically been recognized as natural monopolies and have operated in a highly regulated environment in which they have an obligation to provide electric service to their customers in return for an exclusive franchise within their service territory with an opportunity to earn a regulated rate of return. Idaho Power is under the retail jurisdiction (as to rates, service, accounting and other general matters of utility operation) of the Idaho Public Utilities Commission (IPUC) and the Oregon Public Utility Commission (OPUC) and as a regulated electric utility, Idaho Power is generally not subject to retail competition. The IPUC and the OPUC determine the rates that Idaho Power charges to its general business customers. Idaho Power is also under the retail regulatory jurisdiction of the IPUC, the OPUC and the Public Service Commission of Wyoming as to the issuance of debt and equity securities.

Approximately 95 percent of Idaho Power’s general business revenue comes from customers located in Idaho. Idaho Power uses general rate cases, power cost adjustment mechanisms, a fixed cost adjustment (FCA) mechanism, and subject-specific filings to recover its costs of providing service and to earn a return on investment. Significant rate cases and proceedings are discussed in more detail in Note 3 to the consolidated financial statements.

Special Customer Electric Service Agreements

Micron: The IPUC authorized Idaho Power to amend temporarily an electric service agreement with one of its largest customers, Micron Technology, Inc. (Micron) for the period January 2009 through June 2009, to provide Micron flexibility in restructuring its operations. Subsequently, the IPUC approved an extension of the temporary amendment through December 31, 2009. The amendments did not have a significant impact on Idaho Power’s 2009 earnings and are not expected to have a significant impact on 2010 earnings. The IPUC approved a replacement agreement between Idaho Power and Micron on February 12, 2010, providing operating and planning benefits to Idaho Power while allowing Micron to reduce its contract demand from 85 MW to 60 MW.

Hoku: In September 2008, Idaho Power entered into an electric service agreement with a new customer, Hoku Materials, Inc. (Hoku), to provide electric service to Hoku’s polysilicon production facility under construction in Pocatello, Idaho. The IPUC approved the electric service agreement in March 2009. The initial term of the agreement was four years beginning June 1, 2009, (this date was subsequently changed to December 1, 2009) with a maximum demand obligation during the initial term of 82 MW.

Hoku was still not taking service on December 1, 2009, and Idaho Power agreed to temporarily waive the minimum billed energy charge in the Hoku special contract, effective December 1, 2009. The temporary waiver would remain in effect until the month the contract load factor first exceeds 70 percent of the total contract demand, or March 31, 2011, whichever comes first. The IPUC has approved this waiver. While the multi-month delay in the starting date for Hoku’s required energy purchases reduces Idaho Power’s revenues, the revenue reductions are largely offset by corresponding reductions in Idaho Power’s costs of providing service to Hoku.

Wholesale

As a public utility under Part II of the Federal Power Act (FPA), Idaho Power has authority to charge market-based rates for wholesale energy sales under its FERC tariff and to provide transmission services under its Open Access Transmission Tariff (OATT). Idaho Power’s OATT is revised each year based on financial and operational data Idaho Power files annually with the FERC in its Form 1. The Energy Policy Act of 2005 (Energy Act) granted the FERC increased statutory authority to implement mandatory transmission and reliability standards, as well as enhanced oversight of power and transmission markets, including protection against market manipulation. Significant rate cases and proceedings are discussed in more detail in Note 3 to the consolidated financial statements.

Idaho Power has one firm wholesale power sales contract with Raft River Electric Cooperative for up to 15 MW. This contract expires in September 2010. However, Raft River Electric Cooperative has provided notice that is intends to renew the contract, as allowed in the original agreement, through September 2011.

Idaho Power has one wholesale reserve sales contract, with United Materials of Great Falls, Inc. The agreement requires Idaho Power to carry reserves in association with an energy sales agreement between Idaho Power and United Materials from the Horseshoe Bend Wind Farm located in Montana. The term of the agreement runs seasonally through May 2013.

Energy sales

The following table presents Idaho Power’s revenues and energy use by customer type for the last three years. Idaho Power’s operations are discussed further in Part II, Item 7 - “MD&A - RESULTS OF OPERATIONS - Utility Operations:”

				Years Ended December 31,
				2009		2008		2007
Revenues (thousands of dollars)
	Residential			$	409,479	$	353,262	$	308,208
	Commercial				232,816		203,035		170,001
	Industrial				141,530		122,302		101,409
	Irrigation				109,655		105,712		88,685
	Deferred revenue related to Hells Canyon
		relicensing AFUDC			(9,715)		-		-
		Total general business			883,765		784,311		668,303
	Off-system sales				94,373		121,429		154,948
	Other				67,858		50,336		52,150
			Total	$	1,045,996	$	956,076	$	875,401

Energy use (thousands of MWh)
	Residential				5,300		5,297		5,227
	Commercial				3,858		3,970		3,937
	Industrial				3,140		3,355		3,454
	Irrigation				1,650		1,922		1,924
			Total general business		13,948		14,544		14,542
	Off-system sales				2,836		2,048		2,744
			Total		16,784		16,592		17,286

Power Supply

Idaho Power primarily relies on company-owned hydroelectric, coal and gas-fired generation facilities and long-term power purchase agreements (PPAs) to supply the energy needed to serve customers. Idaho Power’s annual hydroelectric generation varies depending on water conditions in the Snake River and market purchases and sales are used to balance supply and demand throughout the year. Idaho Power’s low-cost hydroelectric plants are typically the company’s largest source of electricity. Idaho Power’s generating plants and their capacities are listed in Item 2 - “Properties.”

Weather, customer growth and economic conditions impact power supply costs. Drought conditions and customer growth cause a greater reliance on more expensive purchased power to meet load requirements. Conversely, favorable hydroelectric generation conditions increase production at Idaho Power’s hydroelectric generating facilities and reduce the need for purchased power. Economic conditions can affect market price of natural gas and coal, which may impact fuel expense and market prices for purchased power.

Idaho Power’s system is dual peaking, with the larger peak demand occurring in the summer. The all-time system peak demand is 3,214 MW, set on June 30, 2008, and the all-time winter peak demand is 2,527 MW set on December 10, 2009. During these and other similar heavy load periods Idaho Power’s system is fully committed to serve loads and meet required operating reserves.

The following table presents Idaho Power’s total power supply for the last three years:

				MWh			Percent of total generation
				2009	2008	2007	2009	2008	2007
				(thousands of MWhs)
Hydroelectric plants				8,096	6,908	6,181	53%	48%	46%
Coal-fired plants				6,941	7,279	7,144	45%	50%	52%
Natural gas fired plants				242	217	223	2%	2%	2%
		Total system generation		15,279	14,404	13,548	100%	100%	100%
Purchased power - cogeneration and
	small power production (CSPP)			970	757	777
Purchased power - Other				1,942	2,960	4,419
		Total purchased power		2,912	3,717	5,196
			Total power supply	18,191	18,121	18,744

Hydroelectric Generation

Idaho Power operates 17 hydroelectric projects located on the Snake River and its tributaries. Together, these hydroelectric facilities provide a total nameplate capacity of 1,709 MW and annual generation equal to approximately 8.6 million MWh under median water conditions.

Because of its reliance on hydroelectric generation, Idaho Power’s generation operations can be significantly affected by water conditions. The availability of hydroelectric power depends on the amount of snow pack in the mountains upstream of Idaho Power’s hydroelectric facilities, reservoir storage, springtime snow pack run-off, river base flows, spring flows, rainfall, amount and timing of water leases, and other weather and stream flow management considerations. During low water years, when stream flows into Idaho Power’s hydroelectric projects are reduced, Idaho Power’s hydroelectric generation is reduced. This results in less generation from Idaho Power’s resource portfolio (hydroelectric, coal-fired and gas-fired) available for off-system sales and, generally, an increased use of purchased power to meet load requirements. Both of these situations - a reduction in off-system sales and an increased use of more expensive purchased power - result in increased power supply costs.

Stream flow conditions improved in 2009 resulting in an increase of 1.2 million MWh generated from Idaho Power’s hydroelectric facilities as compared to 2008. The observed stream flow data released in August 2009 by the U.S. Army Corps of Engineers, indicated that Brownlee reservoir inflow for April through July 2009 was 5.6 million acre-feet (maf), or 89 percent of the National Weather Service Northwest River Forecast Center (NWRFC) average, compared to 4.4 maf, or 70 percent of the NWRFC average, in 2008.

Storage in selected federal reservoirs upstream of Brownlee as of February 21, 2010, was 118 percent of average. The stream flow forecast released on February 19, 2010, by the NWRFC predicts that Brownlee reservoir inflow for April through July 2010 will be 2.9 maf, or 46 percent of the NWRFC average.

Power generation at the Idaho Power hydroelectric power plants on the Snake River also depends on the state water rights held by Idaho Power and the long-term sustainability of the Snake River, tributary spring flows and the Eastern Snake Plain Aquifer that is connected to the Snake River. Idaho Power continues to participate in water management issues in Idaho that may affect those water rights and resources with the goal to preserve, to the fullest extent possible, the long-term availability of water for use at Idaho Power’s hydroelectric projects on the Snake River. For further information see Part II, Item 7 – “MD&A – LEGAL MATTERS – Snake River Basin Water Rights.”

Idaho Power is subject to the provisions of the Federal Power Act (FPA) as a “public utility” and as a “licensee” as therein defined and is subject to regulation by the FERC. As a licensee under Part I of the FPA, Idaho Power and its licensed hydroelectric projects are subject to conditions set forth in the FPA and related FERC regulations. These conditions and regulations include provisions relating to condemnation of a project upon payment of just compensation, amortization of project investment from excess project earnings, possible takeover of a project after expiration of its license upon payment of net investment, severance damages and other matters.

Idaho Power obtains licenses for its hydroelectric projects from the FERC, similar to other utilities that operate nonfederal hydroelectric projects on qualified waterways. These licenses last for 30 to 50 years depending on the size, complexity, and cost of the project. Idaho Power is actively pursuing the relicensing of the Hells Canyon Complex and Swan Falls projects. For further information on relicensing activities see Part II, Item 7 – “MD&A – RELICENSING OF HYDROELECTRIC PROJECTS.”

The state of Oregon has a Hydroelectric Act providing for licensing of hydroelectric projects in that state. With respect to project property located in Oregon, Idaho Power’s Brownlee, Oxbow and Hells Canyon facilities are subject to the Oregon Hydroelectric Act. Idaho Power has obtained Oregon licenses for these facilities and these licenses are not in conflict with the FPA or Idaho Power’s FERC licenses.

Coal and Natural-Gas Combustion Generation
Idaho Power co-owns three coal-fired power plants and owns two natural gas combustion turbine power plants. The coal-fired plants are: Jim Bridger located in Wyoming; Boardman located in Oregon; and Valmy located in Nevada. The natural gas-fired plants, Danskin and Bennett Mountain, are located in Idaho.

Fuel supply-coal

Idaho Power, through its subsidiary IERCo, owns a one-third interest in Bridger Coal, which owns the Jim Bridger mine that supplies coal to the Jim Bridger generating plant (one-third owned by Idaho Power). The mine, located near the Jim Bridger plant, operates under a long-term sales agreement that provides for delivery of coal over a 51-year period ending in 2024 from surface, high-wall, and underground sources. The Jim Bridger mine has sufficient reserves to provide coal deliveries for the term of the sales agreement. Idaho Power also has a coal supply contract providing for annual deliveries of coal through 2014 from the Black Butte Coal Company’s Black Butte and Leucite Hills mines located near the Jim Bridger plant. This contract supplements the Bridger Coal deliveries and provides another coal supply to operate the Jim Bridger plant. The Jim Bridger plant’s rail load-in facility and unit coal train allow the plant to take advantage of potentially lower-cost coal from other mines for tonnage requirements above established contract minimums.

NV Energy, as operator of the Valmy generating plant, has an agreement with Arch Coal Sales Company, Inc. to supply coal to the plant through 2011. As a 50 percent owner of the plant, Idaho Power is obligated to purchase one-half of the coal, Idaho Power’s portion ranging from 515,000 tons to 762,500 tons annually. NV Energy also has a coal supply contract with Black Butte Coal Company’s Black Butte Mine for deliveries through 2015. Idaho Power is obligated to purchase one-half of the coal purchased under this agreement ranging from as low as 44,000 to as many as 500,000 tons annually.

The Boardman generating plant receives coal from the Powder River Basin through annual contracts. Portland General Electric, as operator of the Boardman plant, has two agreements with Foundation Coal West, Inc. to supply all of Boardman’s coal requirements in 2010 and additional deliveries through 2011. As a ten percent owner of the plant, Idaho Power is obligated to purchase ten percent of the coal purchased under these agreements, which cumulatively ranges from 175,000 to 225,000 tons annually.

Fuel supply-natural gas

Idaho Power owns and operates the Danskin and Bennett Mountain combustion turbines, which are supplied gas through Northwest Pipeline GP’s (Northwest) pipeline. Gas is purchased as needs are identified for summer peaks or to meet system requirements. Natural gas is transported under two long-term agreements with Northwest. The first agreement, which runs into 2022, with annual extensions at Idaho Power’s sole discretion, is for 24,523 million British thermal units (MMBtu) per day. Idaho Power also has the ability to flow a total of 78,092 MMBtu on an alternate firm basis without incurring a reservation charge on the additional amount. The second agreement, beginning in 2012 and running through 2027, provides Idaho Power with transportation capacity for 22,000 MMBtu per day. In addition to the two long-term gas transportation agreements, Idaho Power has entered into a long-term storage agreement with Northwest for 131,453 MMBtu of total storage capacity at the Jackson Prairie Storage Project located in Lewis County, Washington. As the project is developed, storage capacity will be phased into service and allocated to Idaho Power on a monthly basis. Idaho Power’s current storage allotment is approximately 53 percent of its total, and its full allotment is expected to be reached by January 2011. The firm storage contract expires in 2043, with bilateral termination rights at the end of the contract. Storage gas will be purchased and stored with the intent of fulfilling needs as identified for summer peaks or to meet system requirements.

Idaho Power plans to construct and operate the Langley Gulch combined-cycle natural gas power plant. Construction is scheduled to begin during the summer of 2010 with an on-line date targeted for the summer of 2012. Gas for Langley Gulch will be supplied through Northwest’s pipeline. Procurement of gas will be managed to meet system requirements and fueling strategies.

Purchased Power Agreements

Idaho Power has four firm wholesale purchased power contracts. The first contract is with PPL Energy Plus, LLC, for 83 MW per hour during heavy load hours, to address increased demand during June, July and August. The contract term is through August 2011. The second contract is with Raft River Energy I, LLC for 13 MW (nameplate generation) from its Raft River Geothermal Power Plant Unit #1 located in southern Idaho. The contract term is through April 2033. The third contract is with Telocaset Wind Power Partners, LLC, for 101 MW (nameplate generation) from its Elkhorn Valley wind project located in eastern Oregon. The contract term is through 2027. A fourth contract is currently before the IPUC for authorization. This contract is with USG Oregon LLC for 22 MW (estimated average annual output) from its to-be-constructed Neal Hot Springs #1 geothermal power plant located near Vale, Oregon. The contract term is 25 years with an option to extend. Commercial operation is expected in late 2012.

Idaho Power has an exchange agreement with Clatskanie People’s Utility. The agreement is for the exchange of up to 18 MWs of energy from the Arrowrock Project in southern Idaho for energy from Idaho Power’s system or power purchased at the Mid-Columbia trading hub. The initial term of the agreement is January 1, 2010, through December 31, 2015. Idaho Power has the right to renew the agreement for two additional five-year terms. Idaho Power also has an exchange agreement with NV Energy that is pending approval from the Public Utilities Commission of Nevada. The term of the agreement is one business day following the Public Utilities Commission of Nevada’s approval, and continuing for two consecutive years, and provides for the exchange of up to 45 MW of energy hourly.

CSPP Purchases

Pursuant to the requirements of Section 210 of PURPA, the state regulatory commissions have each issued orders and rules regulating Idaho Power’s purchase of power from cogeneration and small power production (CSPP) facilities. A key component of the PURPA contracts is the energy price contained within the agreements. The PURPA regulations specify that a utility must pay energy prices based on the utility’s avoided costs. The Published Avoided Cost is a price established by the IPUC and OPUC to estimate Idaho Power’s cost of developing additional generation resources. The IPUC and OPUC have established specific rules and regulations to calculate the published avoided cost that Idaho Power is required to include in the PURPA contracts.

Idaho Power has contracts for the purchase of energy from a number of private developers. Under these contracts:

• Idaho Power is required to purchase all of the output from the facilities located inside its service territory.

• Idaho Power is required to purchase the output of projects located outside its service territory if it has the ability to receive at the facility’s requested point of delivery on the Idaho Power system.

• The IPUC jurisdictional portion of the costs associated with CSPP contracts is fully recovered through base rates and the PCA; the OPUC jurisdictional portion is recovered through general rate case filings and the Oregon power cost mechanism.

• For IPUC jurisdictional contracts, projects that generate up to ten average MW of energy monthly are eligible for IPUC Published Avoided Costs for up to a 20-year contract term.

• For OPUC jurisdictional contracts, projects with a nameplate rating of up to ten MW of capacity are eligible for OPUC Published Avoided Costs for up to a 20-year contract term.

• If a PURPA project does not qualify for Published Avoided Costs, Idaho Power is required to negotiate the terms, prices and conditions with the developer. These negotiations reflect the characteristics of the individual projects (i.e., operational flexibility, location and size) and the benefits to the Idaho Power system and must be consistent with other similar energy alternatives.

On March 12, 2009, the IPUC increased the Published Avoided Cost rates. For example, the rate for a 20-year levelized 2009 contract increased from $69.54/MWh to $88.92/MWh. This increase continues a favorable climate for PURPA project development and may lead to additional PURPA agreements. Those agreements may result in Idaho Power acquiring energy at above wholesale market prices and at times when a surplus already exists as well as requiring additional operational integration costs, thus increasing costs to its customers. As noted above, substantially all CSPP costs are recovered through base rates and Idaho Power’s power supply cost mechanisms.

As of December 31, 2009, Idaho Power had signed agreements to purchase energy from 96 CSPP facilities with contracts originally ranging from one to 35 years. Eighty of these facilities, with a combined nameplate capacity of 298 MW, were on-line at the end of 2009; the other 16 facilities under contract, with a combined nameplate capacity of 266 MW, are projected to come on-line during 2010 and 2011. The majority of the new facilities will be wind resources which will generate on an intermittent basis. During 2009, Idaho Power purchased 970,419 megawatt-hours (MWh) from CSPP facilities at a cost of $59 million, resulting in a blended price of 6.1 cents per kilowatt hour.

Wholesale Competition

The 1992 National Energy Policy Act and the FERC’s rulemaking activities have established the regulatory framework to open the wholesale energy market to competition. Open-access transmission for wholesale customers provides energy suppliers with opportunities to sell and deliver electricity at market-based prices. Idaho Power actively monitors and participates, as appropriate, in energy industry developments, to maintain and enhance its ability to effectively participate in wholesale energy markets in a manner consistent with its business goals.

Wholesale Energy Market Activities

Idaho Power participates in the wholesale energy market by buying power to help meet load demands and selling power that is in excess of load demands. Idaho Power’s market activities are guided by a risk management policy and frequently updated operating plans and influenced by customer loads, market prices, and cost and availability of generating resources. Some of Idaho Power’s hydroelectric generation facilities are operated to optimize the water that is available by choosing when to run generation units and when to store water in reservoirs. These decisions affect the timing and volumes of market purchases and market sales. Even in below normal water years, there are opportunities to vary water usage to maximize generation unit efficiency, capture marketplace economic benefits and meet load demand. Wholesale energy market prices and compliance factors, such as allowable river stage elevation changes and flood control requirements, influence these dispatch decisions.

Transmission Services

Idaho Power’s generating facilities are interconnected through its integrated transmission system and are operated on a coordinated basis to achieve maximum load-carrying capability and reliability. Idaho Power’s transmission system is directly interconnected with the transmission systems of the Bonneville Power Administration (BPA), Avista Corporation, PacifiCorp, NorthWestern Energy and NV Energy. Such interconnections, coupled with transmission line capacity made available under agreements with some of the above entities, permit the interchange, purchase, and sale of power among all major electric systems in the west interconnecting with the winter-peaking northern and summer-peaking southern regions of the western power system. Idaho Power provides wholesale transmission service and provides firm and non-firm wheeling services for eligible transmission customers. Idaho Power is a member of the Western Electricity Coordinating Council, the Western Systems Power Pool, the Northwest Power Pool, the Northern Tier Transmission Group, and the North American Energy Standards Board. These groups have been formed to more efficiently coordinate transmission reliability and planning throughout the western grid.

Resource Planning

Idaho Power filed its 2009 Integrated Resource Plan (IRP) with the IPUC and OPUC in December 2009. Idaho Power updates the IRP every two years. The IRP forecasts Idaho Power’s load and resource situation for the next 20 years, analyzes potential supply-side and demand-side options and identifies near-term and long-term actions.

The four primary goals of the IRP are to:

(1) identify sufficient resources to reliably serve the growing demand for energy within Idaho Power’s service area throughout the 20-year planning period;

(2) ensure the selected resource portfolio balances cost, risk and environmental concerns;

(3) give equal and balanced treatment to both supply-side resources and demand-side measures; and

(4) involve the public in the planning process in a meaningful way.

The 2009 IRP analyzed supply-side resources, demand-side management programs, and transmission options taking into account many factors including the estimated costs of complying with potential carbon legislation as part of determining the preferred resource portfolio. The preferred portfolio positions Idaho Power for compliance with anticipated carbon regulations and a federal Renewable Electricity Standard (RES). Due to the uncertainty regarding future carbon regulations, no new conventional coal resources were selected in the preferred portfolio.

During the development of the 2009 IRP, Idaho Power conducted regular public meetings with the IRP Advisory Council (IRPAC). The IRPAC members include the IPUC, the OPUC, political, environmental, and customer representatives and representatives of other public interest groups. IRPAC meetings also serve as the primary forum for involving the public in the planning process.

During the time between resource plan filings, the public and regulatory oversight of the activities identified in the IRP allows for discussion and adjustment of the IRP as warranted. Idaho Power makes periodic adjustments and corrections to the resource plan to reflect changes in technology, economic conditions, anticipated resource development and regulatory requirements.

Supply-side Resources

The foundation of Idaho Power’s energy resources is its company-owned generation facilities including 17 hydroelectric plants, two gas-fired plants and co-ownership in three coal-fired plants (discussed in “ITEM 2 PROPERTIES”). To balance out its resource needs, Idaho Power also utilizes long-term PPA’s to supply the energy needed to serve customers.

Idaho Power also has projects identified for construction that including the 300-MW Langley Gulch combined-cycle power plant, and a 49 MW expansion of the Shoshone Falls hydroelectric facility. Idaho Power is also planning the Boardman to Hemingway and the Gateway West transmission lines and constructing the Hemingway substation to improve reliability, relieve congestion and provide system flexibility (for more information see “ITEM 7 MD&A – LIQUIDITY AND CAPITAL RESOURCES – Capital Requirements – Major Projects”). The IRP also included discussion related to the following resources:

Geothermal RFPs

Although the results of previously conducted geothermal request for proposal (RFP) processes have been disappointing, Idaho Power continues to work with project developers capable of delivering energy to the company’s service area. Idaho Power has included two 20-MW increments of geothermal energy in the 2009 IRP preferred portfolio, one in 2012 and one in 2016.

Wind RFP

The 2009 IRP preferred portfolio includes 150 MW of wind generation coming on-line in 2012. In May 2009, Idaho Power issued an RFP for up to 150 MW of wind generation to come on-line no later than the end of 2012. Idaho Power accelerated the release of the wind RFP to take advantage of the benefits offered in the American Recovery and Reinvestment Act of 2009 (ARRA or the economic stimulus package). Proposals were received in June 2009 and Idaho Power expects to submit a contract to the IPUC for approval in the first half of 2010.

Combined Heat and Power (CHP) RFP

CHP resources were not included in the 2009 IRP preferred portfolio because of the level of uncertainty in being able to successfully develop a CHP project. However, Idaho Power continues to work with large customers and other parties to explore CHP development opportunities.

In November 2009, Idaho Power signed an agreement to jointly investigate a CHP project with the Idaho Office of Energy Resources (IOER) and Amalgamated Sugar, one of Idaho Power’s large industrial customers. The agreement establishes the framework for a CHP feasibility study to be performed at Amalgamated Sugar’s Nampa, Idaho facility that could be as large as 100 MW. IOER and Idaho Power will jointly fund the study.

Demand-Side Management Programs

In 2009, Idaho Power spent approximately $35 million on energy efficiency and targeted demand reduction programs. Approximately $33 million of funding for these programs came from Idaho and Oregon energy efficiency tariff riders. The balance of the funding comes from Idaho Power base rates and from the remaining funds from the BPA’s Conservation and Renewables Discount, which was discontinued in 2007.

Idaho Power has several energy efficiency programs in place and in development, targeting savings across the entire year and across a wide range of customer segments. The emphasis of these programs is to reduce energy consumption, especially during periods of high demand and minimize or delay the need to build new supply-side alternatives. Idaho Power’s programs include:

• irrigation demand response and irrigation efficiency programs target irrigation customers with financial incentives for allowing Idaho Power to interrupt service to their irrigation pumps, and for either improving the energy efficiency of an irrigation system or installing a new energy efficiency system;

• residential air conditioning equipment control measures;

• residential energy efficiency programs targeted at new and existing homes, focusing on customer education and the application of energy efficiency remediation, including energy efficient building techniques, insulation augmentation, air duct sealing, and the use of efficient lighting; and

• industrial and commercial facilities application of energy efficient techniques and technologies, operational and management processes to reduce energy consumption, and a new industrial peak reduction program.

Idaho Power’s revised Irrigation Peak Rewards program design was approved by the IPUC in January 2009. Participating customers receive a credit on their bills in exchange for allowing Idaho Power, within specified parameters, to interrupt service to their irrigation pumps during certain peak hours in a six-week period in June and July. The cost of the program was $10 million in 2009 and is expected to increase to $11 million by 2011.

Idaho Power’s voluntary Commercial Demand Response program is for commercial and industrial customers larger than 200 kilowatts and was approved in May 2009 by the IPUC. Idaho Power signed a five-year contract with a third-party aggregator, EnerNOC, to operate the program and arranges with Idaho Power’s customers to achieve peak reductions. This program is dispatchable (meaning Idaho Power will have flexibility to schedule peak reduction benefits during times of greatest need) and is expected to increase to 50 MW of summer peak demand reduction availability by 2012. The anticipated cost of the program is approximately $12 million over its first five years.

Approximately $3 million of energy efficiency spending was related to research, analysis and development, education, technology evaluation, and market transformation. Some of this activity was done in conjunction with the Northwest Energy Efficiency Alliance (NEEA). Idaho Power contributed $1 million to the NEEA in 2009.

In 2009, Idaho Power’s energy efficiency programs reduced energy usage by approximately 160,000 MWh and the targeted demand reduction programs resulted in a summer peak reduction of about 200 MW.

Environmental Regulation

Idaho Power’s activities are subject to a broad range of federal, state, regional and local laws and regulations designed to protect, restore and enhance the quality of the environment including air, water, and solid waste. Environmental regulation continues to impact Idaho Power’s operations due to the cost of installation and operation of equipment and facilities required for compliance with such regulations, and the modification of system operations to accommodate such regulations. In addition to generally applicable regulations, the FERC licenses issued for Idaho Power’s hydroelectric generating plants have environmental requirements such as aeration of turbine water to meet dissolved gas and temperature standards in the tail waters downstream from the plants. Idaho Power monitors these issues and reports the results to the appropriate regulatory agencies.

Idaho Power co-owns three coal-fired power plants and owns two natural gas combustion turbine power plants that are subject to a broad range of environmental requirements, including air quality regulation.

Idaho Power’s environmental compliance costs will continue to be significant for the foreseeable future especially with potential additional regulation under discussion at the state and federal level. For a more detailed discussion of these and other environmental issues, please see Part II, Item 7 – “MD&A – ENVIRONMENTAL ISSUES.”

Idaho Power estimates its environmental expenditures, based upon present environmental laws and regulations, will be as follows, excluding Allowance for Funds Used During Construction (AFUDC) (in millions of dollars):

		2010			2011 – 2012
Studies and measures related to environmental concerns at hydroelectric facilities		$	6	$	21
Investments in environmental equipment and facilities at thermal plants			12		41
	Total capital expenditures	$	18	$	62

Operating costs for environmental facilities - Hydroelectric		$	16	$	41
Operating costs for environmental facilities - Thermal			8		19
	Total operations and maintenance	$	24	$	60

IFS

IFS invests primarily in affordable housing developments, which provide a return principally by reducing federal and state income taxes through tax credits and accelerated tax depreciation benefits. IFS generated tax credits of $8 million, $11 million and $15 million in 2009, 2008 and 2007, respectively. IFS’s portfolio also includes historic rehabilitation projects such as the Empire Building in Boise, Idaho. IFS made $14 million and $8 million of new investments during 2009 and 2008, respectively, and will continue to review future legislation for new opportunities for investment that will be commensurate with the ongoing needs of IDACORP.

IFS has focused on a diversified approach to its investment strategy in order to limit both geographic and operational risk. Over 90 percent of IFS’s investments have been made through syndicated funds. At December 31, 2009, the gross amount of IFS’s portfolio equaled $197 million in tax credit investments. These investments cover 49 states, Puerto Rico and the U.S. Virgin Islands. The underlying investments include over 700 individual properties, of which all but three are administered through syndicated funds.

IDA-WEST

Ida-West operates and has a 50 percent interest in nine hydroelectric plants with a total generating capacity of 45 MW. Four of the projects are located in Idaho and five are in northern California. All nine projects are “qualifying facilities” under PURPA. Idaho Power purchased all of the power generated by Ida-West’s four Idaho hydroelectric projects at a cost of $9 million in 2009 and $8 million in both 2008 and 2007.

ITEM 1A. RISK FACTORS

The following are factors that could have a significant impact on the operations and financial results of IDACORP, Inc. and Idaho Power Company and could cause actual results or outcomes to differ materially from those discussed in any forward-looking statements:

• Reduced hydroelectric generation can reduce revenues and increase costs, and reduce earnings and cash flows. Idaho Power Company has a predominately hydroelectric generating base. Because of Idaho Power Company’s heavy reliance on hydroelectric generation, water can significantly affect its operations. When hydroelectric generation is reduced, Idaho Power Company must increase its use of generally more expensive thermal generating resources and purchased power and opportunities for off-system sales are reduced, which reduces revenues. In addition, while Idaho Power Company can expect to recover the majority of the net power supply costs above the level included in its rates, recovery of the excess amounts does not occur until the subsequent power cost adjustment year.

• Continuing declines in stream flows and over-appropriation of water in Idaho may reduce hydroelectric generation and revenues and increase costs. The combination of declining Snake River base flows, over-appropriation of water and drought conditions have led to disputes among surface water and ground water irrigators, and the state of Idaho. Recharging the Eastern Snake Plain Aquifer, which contributes to Snake River flows, by diverting surface water to porous locations and permitting it to sink into the aquifer is one proposed solution to the dispute. Diversions from the Snake River for aquifer recharge may further reduce Snake River flows available for hydroelectric generation and reduce Idaho Power Company’s revenues and increase costs. Idaho Power Company’s recent settlement agreement with the state of Idaho resolves litigation regarding certain Idaho Power Company water rights on the Snake River and provides for ongoing Snake River water issues to be addressed in the comprehensive aquifer management plan process. However, there is no assurance that this process will lead to increased Snake River stream flows for Idaho Power Company’s hydroelectric projects. Idaho Power Company also has initiated legal action against the U.S. Bureau of Reclamation over the interpretation and effect of a 1923 contract with the U.S. Bureau of Reclamation on the operation of the American Falls Reservoir and the release of water from that reservoir to be used at Idaho Power Company’s downstream hydroelectric projects. The comprehensive aquifer management plan process and the resolution of the litigation may affect Snake River flows available for hydroelectric generation and thereby reduce Idaho Power Company revenues and increase costs.

• Idaho Power Company’s reliance on coal and natural gas to fuel its power generation facilities exposes it to risk of increased costs and reduced earnings. In addition to hydroelectric generation, Idaho Power Company relies on coal and natural gas to fuel its generation facilities. Market price increases in coal and natural gas can result in reduced earnings. Increases in demand for natural gas, including increases in demand due to greater industry reliance on natural gas for power generation, may result in market price increases, short-term price volatility and/or supply availability issues. In addition, delivery of coal and natural gas depends upon gas pipelines, rail lines, rail cars and roadways. Any disruption in Idaho Power Company’s fuel supply may require the company to find alternative fuel sources at higher costs, to produce power from higher cost generation facilities or to purchase power from other sources at higher costs.

• Load growth in Idaho Power Company’s service territory exposes it to greater market and operational risk and could increase costs and reduce earnings and cash flows.

o Increases in both the number of customers and the demand for energy have resulted and may continue to result in increased reliance on purchased power to meet customer load requirements. The price volatility of electricity has substantially increased from what it was at the inception of the power cost adjustment. While Idaho Power Company can expect to recover the majority of the net power supply costs above the amounts included in its rates, recovery of the excess amounts does not occur until the subsequent power cost adjustment year, and the remaining amount is absorbed by Idaho Power Company which could increase costs and reduce earnings and cash flows.

o Load growth can result in the need for additional investments in Idaho Power Company’s infrastructure to serve the new load. If Idaho Power Company were unable to secure timely rate relief from the Idaho Public Utilities Commission, the Oregon Public Utility Commission or the Federal Energy Regulatory Commission to recover the costs of these additional investments, the resulting regulatory lag would have a negative effect on earnings and cash flows.

o Load growth can create planning and operating difficulties for Idaho Power Company that can negatively impact its ability to reliably serve customers.

• Weather can reduce power sales and revenues and reduce earnings and cash flows. Warmer than normal winters, cooler than normal summers and increased rainfall during the irrigation seasons will reduce retail revenues from power sales and may impact the amount and timing of hydroelectric generation. Extreme weather events can disrupt transmission and distribution systems and cause service interruptions and extended outages, and potentially interrupt use of generation resources. Disruption in transmission and distribution systems increases operations and maintenance expenses and reduces earnings and cash flows.

• Idaho Power Company’s risk management policy and programs relating to hedging power and gas exposures and counterparty creditworthiness may not always perform as intended, and we may suffer economic losses. Idaho Power Company actively manages the market risk inherent in its energy related activities and counterparty credit positions. Idaho Power Company has procedures that monitor compliance with our risk management policies and programs, including verification of transactions, regular portfolio reporting of various risk management metrics and daily counterparty credit risk analysis. However, actual hydroelectric and thermal generation, transmission availability and market prices may be significantly different than those originally planned for when we enter into our risk management positions. The high volatility of these items creates uncertainty in the appropriate amount of hedging activity to pursue. Forecasts of future loads and available resources to meet those loads are inherently uncertain and may cause Idaho Power Company to over- or under-hedge actual resource needs, exposing the company to market risk on the over- or under-hedged position. Changes in market prices are also unpredictable and can at times result in Idaho Power Company’s hedged positions performing less favorably than unhedged positions. In addition, Idaho Power Company’s counterparty credit policies may not prevent counterparties from failing to perform, forcing the company to replace forward contracts with transactions in the open market. As a result, risk management decisions may have significant impacts if actual events result in greater losses or costs in delivering energy to customers and could negatively affect financial condition, results of operations or cash flows.

• Increased capital expenditures can significantly affect liquidity. Increases in both the number of customers and the demand for energy require expansion and reinforcement of transmission and distribution systems and generating facilities. If Idaho Power Company does not receive timely regulatory recovery, Idaho Power Company will have to rely more on external financing for its future utility construction expenditures. These large planned expenditures may weaken the consolidated financial profile of IDACORP, Inc. and Idaho Power Company. Additionally, a significant portion of Idaho Power Company’s facilities were constructed many years ago. Aging equipment, even if maintained in accordance with industry practices, may require significant capital expenditures. Failure of equipment or facilities used in Idaho Power Company’s system could potentially increase repair and maintenance expenses, purchased power expenses and capital expenditures.

• If the Idaho Public Utilities Commission, the Oregon Public Utility Commission or the Federal Energy Regulatory Commission grant less rate recovery in rate case filings than Idaho Power Company needs to cover increased costs of providing services, earnings and cash flows may be reduced. If the Idaho Public Utilities Commission, the Oregon Public Utility Commission or the Federal Energy Regulatory Commission grant less rate recovery in rate case filings than Idaho Power Company needs to cover increased costs of providing services, it may have a negative effect on earnings and cash flows and could result in downgrades of IDACORP, Inc.’s and Idaho Power Company’s credit ratings.

• Climate change could affect customer demand and hydroelectric generation and disrupt transmission and distribution systems, reducing earnings and cash flows. Long-term climate change could affect Idaho Power Company’s business in a variety of ways, including: (i) changes in temperature and precipitation could affect customer demand, (ii) extreme weather events could increase service interruptions, outages, and maintenance costs; (iii) changes in the amount and timing of snowpack and stream flows could adversely affect hydroelectric generation, and (iv) legislative and/or regulatory developments related to climate change could affect plans and operations including placing restrictions on the construction of new generation resources, the expansion of existing resources, or the operation of generation resources in general, and (v) consumer preference for, and resource planning decisions requiring, renewable or low GHG-emitting sources of energy could impact demand from existing sources and require significant investment in new generation and transmission resources. Any of these effects of climate change could reduce Idaho Power Company’s earnings and cash flows.

• Complying with environmental laws and regulations will increase capital expenditures and operating costs and may reduce Idaho Power Company’s earnings and cash flows and ability to meet the electricity needs of its customers. Idaho Power Company is subject to extensive federal, state and local environmental statutes, rules and regulations relating to air quality, water quality, natural resources and health and safety. Compliance with these environmental statutes, rules and regulations involves significant capital and operating expenditures. Congress is considering legislation to limit and reduce greenhouse gas emissions, and the Environmental Protection Agency is taking action to address climate change and regulate greenhouse gas emissions, including the adoption of new reporting requirements that apply to Idaho Power Company’s facilities. The Environmental Protection Agency has also made an “endangerment finding” for greenhouse gas emissions from motor vehicles and has indicated that the Clean Air Act will require it to regulate carbon dioxide and other greenhouse gas emissions from major stationary sources, including Idaho Power Company’s thermal facilities, once it adopts greenhouse gas emission standards for motor vehicles. The adoption of a mandatory federal program to reduce carbon dioxide and other greenhouse gas emissions would raise uncertainty about the future viability of fossil fuels, specifically coal, as an economical energy source for new and existing electric generation facilities. Mercury and other pollutant emissions from Idaho Power Company’s thermal facilities are also subject to extensive regulation. The adoption of new statutes, rules and regulations to reduce emissions, including controls to reduce carbon dioxide, greenhouse gas, mercury or other pollutant emissions will result in increased capital expenditures and could increase the cost of operating coal-fired generating plants or make them uneconomical to operate and result in reduced earnings and cash flows.

• Complying with state or federal renewable energy portfolio standards could increase capital expenditures and operating costs and reduce earnings and cash flows. A number of states have adopted renewable energy portfolio standards. Idaho Power Company’s operations in Oregon will be required to comply with a ten percent renewable energy portfolio standard beginning in 2025, and it is possible that Idaho and other states in which Idaho Power Company operates or sells power could adopt renewable energy portfolio standards in the future. A bill passed by the U.S. House of Representatives on June 26, 2009, would, if enacted, require utilities to obtain as much as 20 percent of their electricity from renewable sources by 2020 and reduce demand by an additional 5 percent through conservation and increased energy efficiency. A bill pending in the U.S. Senate would require 15 percent of electricity from renewable sources by 2021. New state or federal renewable energy portfolio standards could increase capital expenditures and operating costs and reduce earnings and cash flows.

• The listing as threatened or endangered under the Endangered Species Act of fish, wildlife or plant species that are found in the areas of Idaho Power Company’s generation facilities or transmission lines may require mitigation, affect the location of a project or the ability to construct a project and result in increased capital expenditures and operating costs. Relicensing of the Hells Canyon and Swan Falls hydroelectric projects and the construction of Langley Gulch and the Gateway West and Boardman to Hemingway transmission lines require consultation under the Endangered Species Act to determine the effects of these projects on any listed species within the project areas. The recent listing of slickspot peppergrass as a threatened species will require an Endangered Species Act consultation for the transmission and water lines for Langley Gulch as well as for the Gateway West and Boardman to Hemingway transmission lines. This listing may also affect Idaho Power Company’s ability to purchase wind power from any wind power farms that were to be built in these areas. Any negative effects of the listing of slickspot peppergrass or any other species under the Endangered Species Act may require mitigation, cause a delay in relicensing or construction of projects, affect the location or ability to construct a project and increase the costs of construction and operations.

• Conditions that may be imposed in connection with hydroelectric license renewals may require large capital expenditures, increase operating costs, reduce hydroelectric production and reduce earnings and cash flows. Idaho Power Company is currently involved in renewing federal licenses for several of its hydroelectric projects. The Federal Energy Regulatory Commission may impose conditions with respect to environmental, operating and other matters in connection with the renewal of Idaho Power Company’s licenses. These conditions could have a negative effect on Idaho Power Company’s operations, require large capital expenditures and increase operating costs, reduce hydroelectric production and reduce earnings and cash flows.

• Idaho Power Company’s business is subject to substantial governmental regulation and may be adversely affected by increased costs resulting from, or liability under, existing or future regulations or requirements. Idaho Power Company is subject to extensive federal and state laws, policies, and regulations, as well as regulatory actions and regulatory audits, including those of the Federal Energy Regulatory Commission, the Environmental Protection Agency, the North American Electric Reliability Corporation, the Western Electricity Coordinating Council and the public utility commissions in Idaho, Oregon and Wyoming. Some of these regulations are changing or subject to interpretation, and failure to comply may result in penalties or other adverse consequences. Idaho Power Company has reported compliance issues to the Federal Energy Regulatory Commission, and the Western Electricity Coordinating Council has recently completed an audit of reliability standards. Compliance with these requirements directly influences Idaho Power Company’s operating environment and may significantly increase Idaho Power Company’s operating costs.

• IDACORP, Inc., its affiliate IDACORP Energy and Idaho Power Company are subject to costs and other effects of legal and regulatory proceedings, settlements, investigations and claims. IDACORP, Inc., IDACORP Energy and Idaho Power Company are involved in a number of proceedings, including the California refund proceeding, a portion of which remains pending before the Federal Energy Regulatory Commission and the United States Court of Appeals for the Ninth Circuit; a refund proceeding affecting sellers of wholesale power in the spot market in the Pacific Northwest; and show cause proceedings originating at the Federal Energy Regulatory Commission, a portion of which remains pending in the United States Court of Appeals for the Ninth Circuit. It is possible that additional proceedings related to the western energy situation may be filed in the future against IDACORP, Inc., IDACORP Energy or Idaho Power Company. IDACORP, Inc. and Idaho Power Company are or may also be subject to costs and other effects of additional legal claims, actions and complaints, including those related to the Jim Bridger, Valmy and Boardman coal-fired plants, in which Idaho Power Company holds an ownership interest. State attorneys general have brought actions against companies, seeking additional disclosure of climate change-related risks and impacts, and private parties have brought tort actions against companies relating to their alleged contribution to climate change. If IDACORP, Inc., IDACORP Energy or Idaho Power Company are required to make payments in connection with any legal or regulatory proceeding, settlement, investigation or claim, earnings and cash flows could be negatively affected.

• As a holding company, IDACORP, Inc. does not have its own operating income and must rely on the upstream cash flows from its subsidiaries to pay dividends and make debt payments. IDACORP, Inc. is a holding company and thus its primary assets are shares or other ownership interests of its subsidiaries, primarily Idaho Power Company. Consequently, IDACORP, Inc.’s ability to pay dividends and to service its debt is dependent upon dividends and other payments received from its subsidiaries. IDACORP, Inc.’s subsidiaries are separate and distinct legal entities and have no obligation to pay any amounts to IDACORP, Inc., whether through dividends, loans or other payments. The ability of IDACORP, Inc.’s subsidiaries to pay dividends or make distributions to IDACORP, Inc. depends on several factors, including their actual and projected earnings and cash flow, capital requirements and general financial condition, regulatory restrictions, and the prior rights of holders of their existing and future first mortgage bonds and other debt securities.

• A downgrade in IDACORP, Inc.’s and Idaho Power Company’s credit ratings could negatively affect the companies’ ability to access capital, increase their cost of borrowing, and require the companies to post collateral with transaction counterparties. Credit rating agencies periodically review the corporate credit ratings and long-term ratings of IDACORP, Inc. and Idaho Power Company. IDACORP, Inc. and Idaho Power Company also have borrowing arrangements that rely on the ability of the banks to fund loans or support commercial paper. Downgrades of IDACORP, Inc.’s or Idaho Power Company’s credit ratings, or those affecting relationship banks, could limit the companies’ ability to access capital, including the commercial paper markets, require the companies to pay a higher interest rate on their debt and require the companies to post collateral with transaction counterparties.

• Volatility and decreased lending capacity in the financial markets may negatively affect IDACORP, Inc.’s and Idaho Power Company’s ability to access capital and/or increase their cost of borrowing. IDACORP, Inc. and Idaho Power Company require liquidity to pay operating expenses and principal of and interest on debt and to finance capital expenditures. Financial markets have experienced extreme volatility and disruption, causing the cost of borrowing to rise and the availability of liquidity and credit for borrowers to decrease; As a result, IDACORP, Inc. and Idaho Power Company may experience higher interest costs and/or be unable to access capital, including the commercial paper markets. These conditions may adversely affect IDACORP, Inc.’s and Idaho Power Company’s results of operations, financial condition and cash flows.

• One or more of the banks participating in IDACORP, Inc.’s and Idaho Power Company’s credit facilities could default on their obligations to fund loans requested by the companies or could withdraw from participation in the credit facilities, which could negatively affect cash flows and the ability to meet capital requirements. IDACORP, Inc. and Idaho Power Company have $100 million and $300 million multi-year revolving credit facilities, respectively, with a group of lender banks that expire in April 2012. These facilities supplement operating cash flow and provide a primary source of liquidity. The facilities are also used as backup for commercial paper borrowings and are available for general corporate purposes. IDACORP, Inc. and Idaho Power Company are subject to the risk that one or more of the participating banks may default on their obligations to make loans under the credit facilities. IDACORP, Inc. and Idaho Power Company’s inability to obtain loans under their respective credit facilities as needed could negatively affect cash flows and the ability to meet capital requirements.

• IDACORP and Idaho Power Company may incur losses on their investments or be unable to sell their investments when they desire to do so, which could adversely affect their liquidity and financial condition. IDACORP and Idaho Power Company invest cash in short-term interest bearing accounts, including money market funds. Volatility in the financial markets may result in a lack of liquidity and declines in value of some money market funds. The companies may realize additional losses on some or all of their invested funds or be unable to sell their investments when they desire to do so. This could adversely affect IDACORP’s and Idaho Power Company’s liquidity and financial condition.

• National and regional economic conditions may cause increased late payments and uncollectible accounts, which would reduce earnings and cash flows. Recent concerns over energy costs, the availability and cost of credit, declining business and increased unemployment have contributed to a recession. These factors have resulted, and may continue to result, in an increase in late payments and uncollectible accounts and reduce IDACORP Inc.’s and Idaho Power Company’s earnings and cash flows.

• National and regional economic conditions, in conjunction with increased electric rates, may reduce energy consumption, which may reduce revenues and future growth. The present economic recession and increased rates may reduce the amount of energy our customers consume, result in a loss of customers and reduce customer growth. A decrease in overall customer usage may reduce revenues, earnings, and future growth.

• Adverse results of income tax audits could reduce earnings and cash flows. The outcome of ongoing and future income tax audits could differ materially from the amounts currently recorded, and the difference could reduce IDACORP’s and Idaho Power Company’s earnings and cash flows.

• Employee workforce factors could increase costs and reduce earnings. Idaho Power Company is subject to workforce factors, including, but not limited to, loss or retirement of key personnel, availability of qualified personnel, an aging workforce, and impacts of efforts to organize workforce, including the possible unionization of one or more segments of the workforce. The costs of attracting and retaining appropriately qualified employees to replace an aging workforce could reduce earnings and cash flows.

• Terrorist threats and activities could result in reduced revenues and increased costs. IDACORP, Inc. and Idaho Power Company are subject to direct and indirect effects of terrorist threats and activities. Potential targets include generation and transmission facilities. The effects of terrorist threats and activities could prevent Idaho Power Company from purchasing, generating or transmitting power and result in reduced revenues and increased costs.

• IDACORP, Inc. and Idaho Power Company could be vulnerable to security breaches or other similar events that could disrupt their operations, require significant capital expenditures and/or result in claims against the companies. In the normal course of business, Idaho Power Company collects, processes and retains sensitive and confidential customer and proprietary information. Despite the security measures in place, Idaho Power Company’s facilities and systems, and those of third-party service providers, could be vulnerable to security breaches or other similar events that could interrupt operations, resulting in a shutdown of service and expose Idaho Power Company to liability. In addition, Idaho Power Company may be required to expend significant capital and other resources to protect against security breaches or to alleviate problems caused by security breaches.

ITEM 1B. UNRESOLVED STAFF COMMENTS

None

ITEM 2. PROPERTIES

Idaho Power’s system is comprised of 17 hydroelectric generating plants located in southern Idaho and eastern Oregon, two natural gas-fired plants located in southern Idaho and interests in three coal-fired steam electric generating plants located in Wyoming, Nevada and Oregon. The system also includes approximately 4,796 pole miles of high-voltage transmission lines, 23 step-up transmission substations located at power plants, 22 transmission substations, eight switching stations, 223 energized distribution substations (excluding mobile substations and dispatch centers) and approximately 26,675 pole miles of distribution lines.

Idaho Power holds FERC licenses for all of its hydroelectric projects that are subject to federal licensing. These projects and the other generating stations and their nameplate capacities are listed below:

					Nameplate
					Capacity	License
Project					(kW)	Expiration
Hydroelectric Developments:
		Properties subject to federal licenses:
			Lower Salmon		60,000	2034
			Bliss		75,000	2034
			Upper Salmon		34,500	2034
			Shoshone Falls		12,500	2034
			CJ Strike		82,800	2034
			Upper Malad - Lower Malad		21,770	2035
			Brownlee - Oxbow - Hells Canyon		1,166,900	2005	(1)
			Swan Falls		27,170	2010
			American Falls		92,340	2025
			Cascade		12,420	2031
			Milner		59,448	2038
			Twin Falls		52,897	2040
	Other Hydroelectric:
			Clear Lakes - Thousand Springs		11,300
				Total Hydroelectric	1,709,045
Steam and Other Generating Plants:
			Jim Bridger (coal-fired) (2)		770,501
			Valmy (coal-fired) (2)		283,500
			Boardman (coal-fired) (2)		64,200
			Danskin (gas-fired)		270,900
			Salmon (diesel-internal combustion)		5,000
			Bennett Mountain (gas-fired)		172,800
				Total Steam and Other	1,566,901
				Total Generation	3,275,946

⁽¹⁾ Licensed on an annual basis while application for new multi-year license is pending.
⁽²⁾ Idaho Power’s ownership interests are 33 percent for Jim Bridger, 50 percent for Valmy and 10 percent for Boardman. Amounts shown represent Idaho Power’s share.

Relicensing of Idaho Power’s hydroelectric projects is discussed in Part II, Item 7 - “MD&A – RELICENSING OF HYDROELECTRIC PROJECTS.”

Idaho Power owns in fee all of its principal plants and other important units of real property, except for portions of certain projects licensed under the FPA and reservoirs and other easements. Idaho Power’s property is also subject to the lien of its Mortgage and Deed of Trust and the provisions of its project licenses. In addition, Idaho Power’s property is subject to minor defects common to properties of such size and character that do not materially impair the value to, or the use by, Idaho Power of such properties. Idaho Power considers its properties to be well-maintained and in good operating condition.

IERCo owns a one-third interest in Bridger Coal Company and coal leases near the Jim Bridger generating plant in Wyoming from which coal is mined and supplied to the plant.

Ida-West holds 50 percent interests in nine operating hydroelectric plants with a total generating capacity of 45 MW. These plants are located in Idaho and California.

ITEM 3. LEGAL PROCEEDINGS

Please see Note 10 to IDACORP’s and Idaho Power’s consolidated financial statements.

ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS

None

EXECUTIVE OFFICERS OF THE REGISTRANTS

The names, ages and positions of all of the executive officers of IDACORP, Inc. and Idaho Power Company are listed below along with their business experience during the past five years. Mr. J. LaMont Keen and Mr. Steven R. Keen are brothers. There are no other family relationships among these officers, nor is there any arrangement or understanding between any officer and any other person pursuant to which the officer was elected.

J. LAMONT KEEN, 57

• President and Chief Executive Officer of IDACORP, Inc., July 1, 2006 – present.

• President and Chief Executive Officer of Idaho Power Company, November 17, 2005 – present.

• Executive Vice President of IDACORP, Inc., March 1, 2002 – July 1, 2006.

• President and Chief Operating Officer of Idaho Power Company, March 1, 2002 – November 17, 2005.

• Senior Vice President – Administration and Chief Financial Officer of IDACORP, Inc. and Idaho Power Company, May 1999 – March 2002.

• Member of the Boards of Directors of both IDACORP, Inc. and Idaho Power Company.

DARREL T. ANDERSON, 51

• Executive Vice President – Administrative Services and Chief Financial Officer of IDACORP, Inc. and Idaho Power Company, October 1, 2009 – present.

• Senior Vice President – Administrative Services and Chief Financial Officer of IDACORP, Inc. and Idaho Power Company, July 1, 2004 – October1, 2009.

• Vice President, Chief Financial Officer and Treasurer of IDACORP, Inc. and Idaho Power Company, March 2002 – July 2004

• Vice President – Finance and Treasurer of IDACORP, Inc. and Idaho Power Company, May 1999 – March 2002.

DANIEL B. MINOR, 52

• Executive Vice President – Operations of Idaho Power Company, October 1, 2009 – present.

• Senior Vice President – Delivery of Idaho Power Company, July 1, 2004 – October 1, 2009.

• Vice President – Administrative Services & Human Resources of IDACORP, Inc. and Idaho Power Company, November 2003, – July 2004

• Vice President - Corporate Services of Idaho Power Company, May 2003 – November 2003

• Director of Audit Services of Idaho Power Company, July 2001 – May 2003.

REX BLACKBURN, 54

• Senior Vice President and General Counsel, IDACORP, Inc. and Idaho Power Company, April 1, 2009 – present.

• Lead Counsel of Idaho Power Company, January 1, 2008 – March 31, 2009.

• Lawyer at Blackburn and Jones, LLP, January 2003 – December 31, 2007.

LISA A. GROW, 44

• Senior Vice President – Power Supply of Idaho Power Company, October 1, 2009 – present.

• Vice President – Delivery Engineering and Operations of Idaho Power Company, July 20, 2005 – September 30, 2009

• General Manager of Grid Operations and Planning of Idaho Power Company, October 2004 – July 20, 2005

• Operations Manager (Grid Ops) of Idaho Power Company, March 2002 – October 2004.

STEVEN R. KEEN, 49

• Vice President and Treasurer of IDACORP, Inc. and Idaho Power Company, June 1, 2006 – present.

• President of IDACORP Financial Services, September 1998 – May 31, 2007.

PATRICK A. HARRINGTON, 49

• Corporate Secretary of IDACORP, Inc. and Idaho Power Company, March 15, 2007 – present.

• Senior Attorney, June 2003 – March 15, 2007.

DENNIS C. GRIBBLE, 57

• Vice President and Chief Information Officer of IDACORP, Inc. and Idaho Power Company, June 1, 2006 – present.

• Vice President and Treasurer of IDACORP, Inc. and Idaho Power Company, July 2004 – June 1, 2006.

LORI D. SMITH, 49

• Vice President – Corporate Planning and Chief Risk Officer of IDACORP, Inc. and Idaho Power Company, January 1, 2008 – present.

• Vice President – Finance and Chief Risk Officer of IDACORP, Inc. and Idaho Power Company, July 2004 – January 1, 2008.

LUCI K. MCDONALD, 52

• Vice President – Human Resources of IDACORP, Inc. and Idaho Power Company, December 2004 – present.

• Corporate Staff Director of Human Resources of Boise Cascade Corporation, September 1999 – November 2004.

NAOMI SHANKEL, 38

• Vice President, Audit and Compliance of IDACORP, Inc. and Idaho Power Company, September 21, 2006 – present.

• Director, Audit Services of IDACORP, Inc. and Idaho Power Company, July 2003 – September 21, 2006.

JEFFREY MALMEN, 42

• Vice President – Public Affairs of IDACORP, Inc. and Idaho Power Company, October 1, 2008 – present.

• Senior Manager – Governmental Affairs of IDACORP, Inc. and Idaho Power Company, December xx, 2007 – October 1, 2008

• Chief of Staff of the Office of Idaho Governor C.L. “Butch” Otter, January 2007 – November 2007

• Chief of Staff of the Office of Idaho Congressman C.L. “Butch” Otter, January 2001 – December 2006.

JOHN R. GALE, 59

• Vice President – Regulatory Affairs of Idaho Power Company, March 2001 – present.

WARREN KLINE, 54

• Vice President – Customer Service and Regional Operations of Idaho Power Company, July 20, 2005 – present.

• General Manager of Regional Operations of Idaho Power Company, March 2002 – July 20, 2005.

N. VERN PORTER, 50

• Vice President – Delivery Engineering and Operations, Idaho Power Company, October 1, 2009 – present.

• General Manager of Power Production of Idaho Power Company, April 22, 2006 – October1, 2009.

• Senior Manager of Power Supply Operations of Idaho Power Company, August 2003 – April 22, 2006.

PART II

ITEM 5. MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES

IDACORP’s common stock, without par value, is traded on the New York Stock Exchange. On February 19, 2010, there were 13,803 holders of record and the stock price was $33.02 per share.

The outstanding shares of Idaho Power’s common stock, $2.50 par value, are held by IDACORP and are not traded. IDACORP became the holding company of Idaho Power on October 1, 1998.

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

A covenant under IDACORP’s credit facility and Idaho Power’s credit facility described in “MD&A - LIQUIDITY AND CAPITAL RESOURCES - Financing Programs – Credit Facilities” requires IDACORP and Idaho Power to maintain leverage ratios of consolidated indebtedness to consolidated total capitalization, as defined, of no more than 65 percent at the end of each fiscal quarter.

Idaho Power’s Revised Code of Conduct approved by the IPUC on April 21, 2008, states that Idaho Power will not pay any dividends to IDACORP that will reduce Idaho Power’s common equity capital below 35 percent of its total adjusted capital without IPUC approval. Idaho Power must obtain approval of the OPUC before it could directly or indirectly loan funds or issue notes or give credit on its books to IDACORP.

Idaho Power’s ability to pay dividends on its common stock held by IDACORP and IDACORP’s ability to pay dividends on its common stock are limited to the extent payment of such dividends would violate the covenants or Idaho Power’s Code of Conduct. At December 31, 2009, the leverage ratios for IDACORP and Idaho Power were 51 percent and 53 percent, respectively. Based on these restrictions, IDACORP’s and Idaho Power’s dividends were limited to $608 million and $514 million, respectively, at December 31, 2009.

Idaho Power’s articles of incorporation contain restrictions on the payment of dividends on its common stock if preferred stock dividends are in arrears. Idaho Power has no preferred stock outstanding. IDACORP and Idaho Power paid dividends of $57 million, $54 million and $53 million in 2009, 2008 and 2007, respectively.

The following table shows the reported high and low sales price of IDACORP’s common stock and dividends paid for 2009 and 2008 as reported in the consolidated transaction reporting system.

		Quarters
Common Stock, without par value:		1^st		2^nd		3^rd		4^th
2009
	High	$	30.47	$	26.20	$	29.56	$	32.83
	Low		20.91		22.22		24.68		27.71
	Dividends paid per share		0.30		0.30		0.30		0.30
2008
	High	$	35.11	$	33.36	$	33.89	$	30.66
	Low		28.74		28.55		27.96		21.88
	Dividends paid per share		0.30		0.30		0.30		0.30

Issuer Purchases of Equity Securities:

None

Performance Graph

The following performance graph shows a comparison of the five-year cumulative total shareholder return for IDACORP common stock, the S&P 500 Index and the Edison Electric Institute (EEI) Electric Utilities Index. The data assumes that $100 was invested on December 31, 2004, with beginning-of-period weighting of the peer group indices (based on market capitalization) and monthly compounding of returns.

Source: Bloomberg and Edison Electric Institute

					EEI Electric
	IDACORP		S & P 500		Utilities Index
2004	$	100.00	$	100.00	$	100.00
2005		99.86		104.91		116.05
2006		136.18		121.46		140.14
2007		128.56		128.13		163.34
2008		111.83		80.73		121.03
2009		126.99		102.10		133.99

The foregoing performance graph and data shall not be deemed “filed” as part of this Form 10-K for purposes of Section 18 of the Securities Exchange Act of 1934 or otherwise subject to the liabilities of that section and should not be deemed incorporated by reference into any other filing of IDACORP or Idaho Power under the Securities Act of 1933 or the Securities Exchange Act of 1934, except to the extent IDACORP or Idaho Power specifically incorporates it by reference into such filing.

ITEM 6. SELECTED FINANCIAL DATA

IDACORP, Inc.
SUMMARY OF OPERATIONS
(thousands of dollars except per share amounts)
			2009		2008		2007		2006		2005
Operating revenues		$	1,049,800	$	960,414	$	879,394	$	926,291	$	842,864
Operating income			203,583		190,667		152,078		169,704		154,653
Income from continuing operations			124,375		98,245		81,803		100,075		85,716
Diluted earnings per share from
	continuing operations		2.64		2.17		1.86		2.34		2.02
Dividends declared per share			1.20		1.20		1.20		1.20		1.20

Financial Condition:
Total assets		$	4,238,727	$	4,022,845	$	3,653,308	$	3,445,130	$	3,364,126
Long-term debt (including current portion)			1,419,070		1,269,979		1,168,336		1,023,773		1,039,852

Financial Statistics:
Times interest charges earned:
	Before tax ⁽¹⁾		2.88		2.47		2.35		2.78		2.65
	After tax ⁽²⁾		2.59		2.23		2.16		2.54		2.37
Book value per share ⁽³⁾		$	29.23	$	27.85	$	26.89	$	25.76	$	23.96
Market-to-book ratio ⁽⁴⁾			109%		106%		131%		151%		121%
Payout ratio ⁽⁵⁾			45%		55%		65%		48%		79%
Return on year-end common equity⁽⁶⁾			8.9%		7.5%		6.8%		9.5%		6.2%

The financial statistics listed above are calculated in the following manner:
⁽¹⁾ The sum of interest on long-term debt, other interest expense excluding the allowance for funds used during construction credits (AFUDC),and income before income taxes divided by the sum of interest on long-term debt and other interest expense excluding AFUDC credits.
⁽²⁾ The sum of interest on long-term debt, other interest expense excluding AFUDC credits, and income from continuing operations divided by the sum of interest on long-term debt and other interest expense excluding AFUDC credits.
⁽³⁾ Total equity at the end of the year divided by shares outstanding at the end of the year.
⁽⁴⁾ The closing price of IDACORP stock on the last day of the year divided by the book value per share, which is described in (3) above
⁽⁵⁾ Dividends paid per common share for the year divided by earnings per diluted share of the year.
⁽⁶⁾ Net income divided by total equity at the end of the year.

In the second quarter of 2006, IDACORP management designated the operations of two subsidiaries, IDACORP Technologies, Inc. and IDACOMM as assets held for sale, and the companies were sold in July 2006 and February 2007, respectively. IDACORP’s consolidated financial statements reflect the reclassification of the results of these businesses as discontinued operations for all periods presented. Beginning January 1, 2009, noncontrolling interests (previously known as minority interests) were required to be classified as equity. IDACORP’s consolidated financial statements reflect the reclassification of noncontrolling interests to equity for all periods presented.

ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

(Dollar amounts and Megawatt-hours (MWh) are in thousands unless otherwise indicated).

INTRODUCTION:

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

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

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

IDACORP’s other subsidiaries include:

• IDACORP Financial Services, Inc. (IFS), an investor in affordable housing and other real estate investments;

• Ida-West Energy Company (Ida-West), an operator of small hydroelectric generation projects that satisfy the requirements of PURPA; and

• IDACORP Energy (IE), a marketer of energy commodities, which wound down operations in 2003.

On February 23, 2007, IDACORP completed the sale of all of the outstanding common stock of IDACOMM to American Fiber Systems, Inc.

While reading the MD&A, please refer to the accompanying consolidated financial statements of IDACORP and Idaho Power, which present the financial position at December 31, 2009 and 2008, and the results of operations and cash flows for each company for the years ended December 31, 2009, 2008 and 2007.

FORWARD-LOOKING INFORMATION:

In connection with the safe harbor provisions of the Private Securities Litigation Reform Act of 1995, IDACORP and Idaho Power are hereby filing cautionary statements identifying important factors that could cause actual results to differ materially from those projected in forward-looking statements, as such term is defined in the Reform Act, made by or on behalf of IDACORP or Idaho Power in this Annual Report on Form 10-K, in presentations, in response to questions or otherwise. Any statements that express, or involve discussions as to expectations, beliefs, plans, objectives, assumptions or future events or performance, often, but not always, through the use of words or phrases such as “anticipates,” “believes,” “estimates,” “expects,” “intends,” “plans,” “predicts,” “projects,” “may result,” “may continue” or similar expressions, are not statements of historical facts and may be forward-looking. Forward-looking statements involve estimates, assumptions and uncertainties and are qualified in their entirety by reference to, and are accompanied by, the following important factors, which are difficult to predict, contain uncertainties, are beyond IDACORP’s or Idaho Power’s control and may cause actual results to differ materially from those contained in forward-looking statements:

• The effect of regulatory decisions by the Idaho Public Utilities Commission, the Oregon Public Utility Commission and the Federal Energy Regulatory Commission affecting our ability to recover costs and/or earn a reasonable rate of return including, but not limited to, the disallowance of costs that have been deferred;

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

• Changes in tax laws or related regulations or new interpretations of applicable law by the Internal Revenue Service or other taxing jurisdiction;

• Litigation and regulatory proceedings, including those resulting from the energy situation in the western United States, and penalties and settlements that influence business and profitability;

• Changes in and compliance with laws, regulations and policies including changes in law and compliance with environmental, natural resources and endangered species laws, regulations and policies and the adoption of laws and regulations addressing greenhouse gas emissions, global climate change, and energy policies;

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

• Over-appropriation of surface and groundwater in the Snake River Basin resulting in reduced generation at hydroelectric facilities;

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

• Operation of power generating facilities including performance below expected levels, breakdown or failure of equipment, availability of transmission and fuel supply;

• Changes in operating expenses and capital expenditures, including costs and availability of materials, fuel and commodities;

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

• Population growth rates and other demographic patterns;

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

• Increases in uncollectible customer receivables;

• Fluctuations in sources and uses of cash;

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

• Actions by credit rating agencies, including changes in rating criteria and new interpretations of existing criteria;

• Changes in interest rates or rates of inflation;

• Performance of the stock market, interest rates, credit spreads and other financial market conditions, as well as changes in government regulations, which affect the amount and timing of required contributions to pension plans and the reported costs of providing pension and other postretirement benefits;

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

• Increasing costs of insurance, changes in coverage terms and the ability to obtain insurance;

• Homeland security, acts of war or terrorism;

• Natural disasters and other natural risks, such as earthquake, flood, drought, lightning, wind and fire;

• Adoption of or changes in critical accounting policies or estimates; and

• New accounting or Securities and Exchange Commission requirements, or new interpretation or application of existing requirements.

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

EXECUTIVE OVERVIEW:

Business Strategy

IDACORP’s business strategy emphasizes Idaho Power as IDACORP’s core business. Idaho Power detailed a three-part strategy of responsible planning, responsible development and protection of resources, and responsible energy use to ensure adequate energy supplies. Idaho Power continues to evaluate and refine its business strategy to ensure coordination and integration with all functional areas of the company. Idaho Power’s business strategy balances the interest of owners, customers and employees while maintaining the company’s financial stability and flexibility. The strategy includes:

RESPONSIBLE PLANNING: Idaho Power’s planning process is intended to ensure adequate generation and transmission resources to meet population growth and increasing electricity demand. This planning process now integrates Idaho Power’s regulatory strategies and financial planning, including the consideration of regional economic development in the growing communities we serve.

RESPONSIBLE DEVELOPMENT AND PROTECTION OF RESOURCES: Idaho Power’s business strategy has included the development and protection of generation, transmission, distribution and associated infrastructure, and natural resources Idaho Power depends upon. The strategy now includes consideration of workforce planning, development and retention related to these strategic elements.

2009 Financial Results

IDACORP’s net income and earnings per diluted share for the last three years were as follows:

	2009		2008		2007
Net Income Attributable to IDACORP, Inc.	$	124,350	$	98,414	$	82,339
Average outstanding shares - diluted (000s)		47,182		45,379		44,365
Earnings per diluted share	$	2.64	$	2.17	$	1.86

The following table presents a reconciliation of IDACORP net income for 2008 to 2009 (in millions):

Net Income Attributable to IDACORP, Inc. - 2008				$	98.4
Change in Idaho Power net income before taxes:
	Rate and other regulatory changes, net of PCA and FCA mechanisms	$	48.8
	Reduced sales volumes		(23.3)
	Increase in other operations and maintenance expense, excluding FCA		(2.8)
	Increase in depreciation expense		(8.5)
	2008 OATT rate refund		5.0
	2008 investment impairment		6.8
	Other net increases		0.3
Decrease in income tax expense			2.1
	Total increase in Idaho Power net income				28.4
Decreased net income at IFS (net of tax)					(2.9)
Decrease in expenses at holding company (net of tax)					0.7
Other net decreases (net of tax)					(0.2)
	Net Income Attributable to IDACORP, Inc. - 2009			$	124.4

Changes to the Idaho power cost adjustment (PCA) mechanism and base rate increases that both took effect in the first quarter of 2009, positively impacted net income as did decreased net power supply costs. Earnings in 2009 also increased due to a May 2009 Oregon Public Utility Commission (OPUC) stipulation allowing the deferral for future recovery of $6.4 million of excess power supply costs incurred in 2007.

Idaho Power’s retail customer sales volumes decreased four percent in 2009 as compared to 2008. Irrigation usage decreased 14 percent primarily due to increased precipitation. Economic factors and energy conservation also contributed to the reduction in sales volume.

Other O&M expense increased due to an increase in payroll related expenses and uncollectible accounts and was partially offset by decreases in outside services and other office expenses. Depreciation expense increased mainly due to the accelerated depreciation of the existing meter infrastructure. Two items that positively impacted the comparison of 2009 to 2008 results relate to 2008 activities that did not recur in 2009; an OATT rate refund ordered by the FERC that reduced transmission revenue and an impairment of investments.

Idaho Power’s 2009 effective income tax rate decreased primarily due to examination settlements and the timing and amount of other regulatory flow-through tax adjustments, partially offset by the tax expense on higher pre-tax income.

There was no accelerated amortization of deferred investment tax credits during 2009 as the Idaho jurisdictional earnings exceeded 9.5 percent of the Idaho retail common equity, as permitted by the Idaho 2009 settlement agreement.

Regulatory Matters

Idaho Power has a number of pending or recently completed regulatory filings. Regulatory matters are discussed in more detail later in the MD&A.

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

Oregon 2009 General Rate Case: In December 2009, Idaho Power filed a Joint Stipulation and testimony in support of a stipulation that would settle the revenue requirement issues surrounding the general rate case filed on July 31, 2009. If approved by the OPUC, the Joint Stipulation would result in a $5 million, or 15.4 percent, increase to base rates. The new rates reflect a return on equity of 10.175 percent and an overall rate of return of 8.061 percent. The requested effective date for new rates is March 1, 2010.

Oregon 2010 Annual Power Cost Update: In October 2009, Idaho Power filed the October Update portion of its 2010 annual power cost update (APCU). The filing reflects that revenues associated with Idaho Power’s base net power supply costs would increase $2.6 million over the previous October Update, 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.

Oregon Excess Power Cost Deferrals – May-December 2007 Excess Power Costs: In May 2009, the OPUC adopted a stipulation allowing Idaho Power to defer excess net power supply costs of $6.4 million (including interest through the date of the order) for the period May 1 through December 31, 2007. Idaho Power recorded this deferral in the second quarter of 2009.

Idaho and Oregon Rate Orders: Idaho Power received five additional rate orders from the IPUC and the OPUC at the end of May 2009. The IPUC rate orders are for the Fixed Cost Adjustment mechanism, Idaho Energy Efficiency Rider, Advanced Metering Infrastructure (AMI), and PCA, and the OPUC rate order is for the Annual Power Cost Update. Each of these orders increases rates, but only the AMI order, relating to the installation of new meters, increases Idaho Power’s rate base.

Open Access Transmission Tariff (OATT) Amended Legacy Agreements: In 2009, Idaho Power submitted filings to the FERC to increase rates under two agreements Idaho Power has with PacifiCorp and to terminate certain contract services, replacing them with OATT service. The FERC accepted one of Idaho Power’s filings, effective June 13, 2009, for a net annualized revenue increase of $3.2 million. The FERC accepted the second filing and suspended the rates, setting the case for settlement judge procedures and hearing. Idaho Power began collecting the new rates effective August 19, 2009, with a net annualized revenue increase of $3.7 million. Settlement discussions are ongoing. The impact of these revised agreements on 2010 transmission revenue is expected to be a $3.8 million increase as compared with 2009.

Integrated Resource Plan (IRP): Idaho Power filed the 2009 IRP with the IPUC and OPUC in December, 2009. The IRP addresses available supply-side and demand-side resource options, planning period load forecasts, potential resource portfolios, a risk analysis and near-term and long-term action plans.

Liquidity

IDACORP and Idaho Power expect to continue financing capital requirements with a combination of internally generated funds and externally financed capital. In 2009, IDACORP issued 489,360 common stock shares through its continuous equity program at an average price of $28.79 per share for proceeds of $14 million. In March 2009, Idaho Power issued $100 million of its 6.15% First Mortgage Bonds and in November 2009, Idaho Power issued $130 million of its 4.5% First Mortgage Bonds. In December 2009, Idaho Power repaid $80 million of its 7.2% First Mortgage Bonds. These matters are discussed in more detail in “LIQUIDITY AND CAPITAL RESOURCES” later in the MD&A.
Capital Requirements: Idaho Power has several major projects in development. The most significant projects are summarized here and are discussed further in “LIQUIDITY AND CAPITAL RESOURCES – Capital Requirements – Major Projects.”

• Langley Gulch power plant: Langley Gulch will be a natural gas-fired combined cycle combustion turbine (CCCT) generating plant with a summer nameplate capacity of approximately 300 MWs and a winter capacity of approximately 330 MWs. The plant will be constructed at an estimated cost of $427 million near New Plymouth, Idaho commencing in summer 2010, and is anticipated to achieve commercial operation by November 1, 2012. Contract incentives may advance the commercial operation date to July 1, 2012. Idaho Power received cost recovery and ratemaking assurances from the IPUC for this project.

• Transmission Projects: The Boardman-Hemingway Line is a proposed 500-kV line between a substation near Boardman, Oregon and the Hemingway substation. Idaho Power estimates total construction costs of $600 million and expects its share of the project to be between 30 and 50 percent. Idaho Power estimates the project will be completed in 2015. Idaho Power and PacifiCorp are jointly exploring Gateway West, a project to build transmission lines between Windstar, a substation located near Douglas, Wyoming and Hemingway substation. The current estimated cost for Idaho Power’s share of the project is between $300 million and $500 million. Initial phases of the project could be completed by 2014. Idaho Power’s share may change and the timing of the projects segments may be deferred and constructed as demand requires.

Pension Plan: As Idaho Power’s pension plan is below the minimum required funding levels at January 1, 2010, future minimum contributions are required. Based on the assumptions allowed under the PPA, WRERA, Treasury guidance and IRS guidance, IDACORP and Idaho Power were not required to contribute to the pension plan in 2009, and estimated minimum required contributions will be approximately $6 million in 2010, $44 million in 2011, $47 million in 2012, $39 million in 2013, and $40 million in 2014. On October 20, 2009, Idaho Power filed an application with the IPUC requesting the clarification of a pension recovery method for cash contributions made to the pension plan. On February 17, 2010, the IPUC approved a recovery methodology that would permit Idaho Power to include in future rate cases a reasonable amortization and recovery of cash contributions. The amortization of deferred pension costs is expected to match the revenues received as future pension contributions are recovered through rates. Approximately $29 million, $8 million and $3 million of pension expenses were deferred as a regulatory asset in 2009, 2008, and 2007, respectively.

Other Issues

Water Management Issues: Power generation at the Idaho Power hydroelectric power plants on the Snake River depends on the state water rights held by Idaho Power and the long-term sustainability of the Snake River, tributary spring flows and the Eastern Snake Plain Aquifer that is connected to the Snake River. Idaho Power continues to participate in water management issues in Idaho that may affect those water rights and resources with the goal to preserve, to the fullest extent possible, the long-term availability of water for use at Idaho Power’s hydroelectric projects on the Snake River. For a further discussion of water management issues see “LEGAL MATTERS –Snake River Basin Water Rights.”

Environmental Issues: Long-term climate change could significantly affect Idaho Power’s business and climate change regulations are expected to have major implications for Idaho Power and the energy industry. On September 17, 2009, IDACORP’s and Idaho Power’s Board of Directors approved guidelines that established a goal to reduce the carbon dioxide (CO₂) emission intensity of Idaho Power’s utility operations. The guidelines are intended to further prepare Idaho Power for potential legislative and/or regulatory restrictions on greenhouse gas (GHG) emissions while minimizing the costs of complying with such restrictions on Idaho Power’s customers.

Idaho Power, along with its partners in its coal plants, is required to monitor and report quarterly to the Environmental Protection Agency (EPA) their GHG emissions beginning January 1, 2010. The EPA has indicated that it will begin to regulate GHG emissions from stationary sources, including Idaho Power’s facilities, through its new source review and operating permit programs when the regulations relating to GHG emissions from motor vehicles are finalized. Idaho Power’s thermal facilities are also subject to EPA and/or state-promulgated (i) national ambient air quality standards including those for ozone and fine particulate matter, (ii) laws and regulations limiting mercury emissions, (iii) regional haze – best available retrofit technology requirements and (iv) new source review and performance standards. Idaho Power’s environmental compliance costs will continue to be significant for the foreseeable future, particularly in light of possible additional regulation at the federal and state levels. These issues are discussed in more detail in “ENVIRONMENTAL ISSUES.”
Boardman Coal Plant: On January 14, 2010, Portland General Electric announced that it intended to pursue an alternative operating plan, subject to regulatory approval for its Boardman coal-fired electricity generation plant. Under the plan, near-term expenditures for pollution control equipment would be significantly reduced and the plant would either cease to operate in 2020, or it would discontinue the use of coal as a fuel source. Idaho Power is a ten percent owner of the plant, representing 64,200 kW of nameplate capacity. At December 31, 2009, Idaho Power’s net book value in the Boardman plant was $20 million with annual depreciation of approximately $1.2 million.

American Recovery and Reinvestment Act of 2009: Under the ARRA, Idaho Power submitted a grant application to the Department of Energy (DOE) in August 2009, requesting $47 million. This grant would match a $47 million investment by Idaho Power in Smart Grid technology as well as other incremental projects. In October 2009, Idaho Power received notice that its application was selected for negotiation. Negotiations with the DOE on the grant agreement terms are expected to be completed in the first quarter of 2010.

Key Operating and Financial Metrics

		2010	2009
		Estimate	Actual
Idaho Power Operation & Maintenance Expense (Millions)		$295-$305	$293
Idaho Power Capital Expenditures (Millions)		$355-$365	$273
Idaho Power Hydroelectric Generation (Million MWh)		6.5-8.5	8.1
Non-regulated subsidiary earnings and holding company expenses (Millions)		$0-$3.0	$1.8
Effective Income Tax Rates:
	Idaho Power	13% - 17%	23%
	Consolidated – IDACORP	6% - 10%	15%

The range for capital expenditures includes amounts for Langley Gulch power plant, the Hemingway-Bowmont transmission line, the Hemingway substation and expenditures for the siting and permitting of major transmission expansions for the Boardman to Hemingway and Gateway West transmission projects.

The projected range for annual hydroelectric generation is based on 2009-2010 Snake River Basin snowpack at 60 percent of average on February 21, 2010, with reservoir storage levels in selected federal reservoirs upstream of Brownlee at approximately 118 percent of average as of February 21, 2010.

The effective income tax rate ranges include the utilization of up to $25 million of additional deferred investment tax credit (ADITC) amortization at Idaho Power. The rates do not reflect discrete events such as examination settlements or method changes.

RESULTS OF OPERATIONS:

This section of the MD&A takes a closer look at the significant factors that affected IDACORP’s and Idaho Power’s earnings over the last three years. In this analysis, the results of 2009 are compared to 2008 and the results of 2008 are compared to 2007.

The following table presents earnings (losses) for IDACORP and its subsidiaries:

		2009		2008		2007
Idaho Power		$	122,559	$	94,115	$	76,579
IDACORP Financial Services			521		3,426		7,112
IDACORP Energy			(238)		406		(171)
Ida-West Energy			2,727		2,353		2,223
Holding company expenses			(1,219)		(1,886)		(3,471)
Discontinued operations			-		-		67
	Net Income Attributable to IDACORP, Inc.	$	124,350	$	98,414	$	82,339
Average outstanding shares - diluted (000s)			47,182	$	45,379		44,365
Earnings per diluted share		$	2.64		2.17	$	1.86

Utility Operations

Operating environment: Idaho Power primarily uses its hydroelectric and coal-fired generation facilities and long-term power purchase agreements to supply the energy needed to serve customers. Regional energy market purchases and sales are used to balance supply and demand throughout the year.

Idaho Power develops operation plans during the year to provide guidance for generation resource utilization and energy market activities. Idaho Power’s energy risk management policy and unit operating requirements provide the framework for the plans. The plans incorporate forecasts for generation unit availability, reservoir storage and stream flows, gas and coal prices, customer loads and energy market prices.

In developing its plans, Idaho Power determines to what extent its own resources can be used to meet forecast loads and when to transact in the regional energy market. The allocation of hydroelectric generation between heavy load and light load hours or calendar periods is also a consideration. This allocation is intended to utilize the flexibility of the hydroelectric system to shift generation to high value periods, while operating within the constraints imposed on the system.

Hydroelectric generation depends on stream flows in the Snake River, on which most of Idaho Power’s hydroelectric facilities are built. Stream flows are dependent on the amount of snow pack in the mountains upstream of Idaho Power’s hydroelectric facilities, springtime snow pack run-off, river base flows, spring flows, rainfall and other weather and stream flow management considerations. Idaho Power also leases water from third parties to augment stream flows and increase its ability to meet mid-summer electricity demands with lower-cost hydroelectric generation and to offset the impact of drought and changing water use patterns in southern Idaho.

When hydroelectric generation is reduced, Idaho Power has less electricity available for off-system sales and, most likely, will increase its use of purchased power to meet load requirements, resulting in increased power supply costs. During good water years, increased off-system sales and the decreased need for purchased power reduce power supply costs.

Regional energy market prices can also be affected by hydroelectric generating conditions. In times with high hydroelectric generation the availability of abundant energy tends to reduce wholesale prices, and during low hydroelectric generation wholesale prices tend to be higher.

A combination of increased precipitation, higher reservoir storage releases and the purchase of leased water resulted in 8.1 million MWh generated from Idaho Power’s hydroelectric facilities in 2009, compared to 6.9 million MWh in 2008 and 6.2 million in 2007. Hydroelectric generation was 99 percent of the 30-year average in 2009. The observed stream flow data released in August 2009, by the U.S. Army Corps of Engineers, Northwest Division indicated that Brownlee reservoir inflow for April through July 2009 was 5.6 million acre-feet (maf), compared to 4.4 maf in April-July 2008. Annual Brownlee reservoir inflow for 2009 was 11.3 maf, or 70 percent of the NWRFC average compared to 10.1 maf in 2008 and 8.5 maf in 2007. Storage in selected federal reservoirs upstream of Brownlee as of February 21, 2010, was 118 percent of average. The stream flow forecast released on February 19, 2010, by the NWRFC predicts that Brownlee reservoir inflow for April through July 2010 will be 2.9 maf, or 46 percent of the NWRFC average.

The following table presents Idaho Power’s energy sales and supply (in MWhs) for the last three years:

		2009		2008		2007
General business sales			13,948		14,544		14,542
Off-system sales			2,836		2,048		2,744
	Total energy sales		16,784		16,592		17,286
Hydroelectric generation			8,096		6,908		6,181
Coal generation			6,941		7,279		7,145
Natural gas and other generation			242		217		222
	Total system generation		15,279		14,404		13,548
Purchased power			2,912		3,716		5,196
Line losses			(1,407)		(1,528)		(1,458)
	Total energy supply		16,784		16,592		17,286

Idaho Power’s modeled median annual hydroelectric generation is 8.6 million MWh, based on hydrologic conditions for the period 1928 through 2009 and adjusted to reflect the current level of water resource development.

General Business Revenue: Rate actions have significantly impacted general business revenue over the last three years. The following table presents significant rate increases during that period. These and other rate actions are discussed further in “REGULATORY MATTERS” and in Note 3 to the consolidated financial statements.

		Percentage	Annualized $
Description	Effective Date	Increase	increase (millions)
2007-2008 PCA	6/1/2007	14.5	$	78
2007 Idaho general rate case	3/1/2008	5.2		32
2008-2009 PCA	6/1/2008	10.7		73
Danskin Plant	6/1/ 2008	1.37		9
2008 Idaho general rate case	2/1/2009	3.1		21
2008 Idaho general rate case	3/19/2009	0.9		6
2009-2010 PCA	6/1/2009	10.2		84
AMI	6/1/2009	1.8		11

The primary influences on electricity sales volumes are weather, customer demand and economic conditions. Extreme temperatures increase sales to customers who use electricity for cooling and heating, and moderate temperatures decrease sales. Precipitation levels during the agricultural growing season affect sales to customers who use electricity to operate irrigation pumps. Increased precipitation reduces electricity usage by these customers. The following table presents Boise, Idaho weather conditions for the last three years:

	2009	2008	2007	Normal
Heating degree-days ⁽¹⁾	5,612	5,586	5,128	5,727
Cooling degree-days ⁽¹⁾	1,188	1,068	1,290	807
Precipitation (inches)	11.3	9.3	8.1	12.1
⁽¹⁾ Heating and cooling degree-days are common measures used in the utility industry to analyze the demand for electricity and indicate when a customer would use electricity for heating and air conditioning. A degree-day measures how much the average daily temperature varies from 65 degrees. Each degree of temperature above 65 degrees is counted as one cooling degree-day, and each degree of temperature below 65 degrees is counted as one heating degree-day.

The following table presents Idaho Power’s general business revenues, MWh sales and average and year-end number of customers for the last three years:

			2009		2008		2007
Revenue
	Residential		$	409,479	$	353,262	$	308,208
	Commercial			232,816		203,035		170,001
	Industrial			141,530		122,302		101,409
	Irrigation			109,655		105,712		88,685
	Deferred revenue related to Hells Canyon relicensing AFUDC			(9,715)		-		-
		Total	$	883,765	$	784,311	$	668,303
MWh
	Residential			5,300		5,297		5,227
	Commercial			3,858		3,970		3,937
	Industrial			3,140		3,355		3,454
	Irrigation			1,650		1,922		1,924
		Total		13,948		14,544		14,542
Customers (average)
	Residential			405,144		402,520		397,285
	Commercial			64,151		63,492		61,640
	Industrial			127		122		126
	Irrigation			18,753		18,401		18,043
		Total		488,175		484,535		477,094
Customers (year-end)
	Residential			406,631		404,373		400,637
	Commercial			64,349		64,125		62,765
	Industrial			129		125		123
	Irrigation			18,818		18,542		18,126
		Total		489,927		487,165		481,651

2009 vs. 2008:

• Rates: Rate changes positively impacted general business revenue by $128 million in 2009 as compared to 2008. PCA rate increases accounted for $79 million of the increases and base rate changes contributed $49 million. Also, a new tiered rate structure for residential and small commercial customers was implemented February 1, 2009, as part of the general rate case. The table below presents the residential rates by tier.

Idaho Residential Rate Structure
February 1, 2008	Summer	Non-Summer	February 1, 2009	Summer	Non-Summer
0-300 kWh	5.6973 cents	5.6973 cents	0-800 kWh	5.9750 cents	5.5792 cents
Above 300 kWh	6.4125 cents	5.6973 cents	801-2,000 kWh	7.2798 cents	6.1991 cents
			Above 2,000 kWh	8.7358 cents	7.1290 cents

• Customers: General business revenues increased $10 million due to customer growth of one percent.

• Usage: Changes in usage decreased general business revenue $38 million. Irrigation usage decreased 14 percent primarily due to increased precipitation. Commercial and industrial usage also declined due to a weaker economy and increased energy efficiency. Idaho Power does have in place the Load Growth Adjustment Rate (LGAR) and FCA mechanisms, both of which diminish the impact of changes in sales volumes from levels included in base rates.

2008 vs. 2007:

• Rates: Rate changes positively impacted general business revenue by $114 million in 2008 as compared to 2007. PCA rate increases accounted for $82 million of the increases and base rate changes contributed $31 million of the increase.

• Customers: General business customer growth of two percent increased revenue $8 million.

• Usage: Changes in usage, primarily resulting from cooler summer temperatures, decreased general business revenue $5 million.

Off-system sales: Off-system sales consist primarily of long-term sales contracts and opportunity sales of surplus system energy. The following table presents Idaho Power’s off-system sales for the last three years:

	2009		2008		2007
Revenue	$	94,373	$	121,429	$	154,948
MWh sold		2,836		2,048		2,744
Revenue per MWh	$	33.28	$	59.29	$	56.47

2009 vs. 2008: Off-system sales revenue declined 22 percent in 2009 due to lower market prices, partially offset by increased sales. Prices for wholesale power in the Northwest were much lower than in 2008 due to an abundance of energy in the region during the spring and fall and due to lower energy commodity prices. Improved hydroelectric generating conditions and lower system load increased the amount of electricity available for sale.

The off-system sales revenue per MWh is nearly 40 percent lower than the purchased power cost per MWh. In accordance with Idaho Power’s risk management policy, Idaho Power made forward purchases of energy for delivery in the third quarter of 2009. Most of the purchases were identified and made months in advance when market prices were higher. In the third quarter, reduced demand and improved generating conditions caused regional energy market prices to drop and Idaho Power to have additional surplus energy available for sale off-system into that lower price energy market.

2008 vs. 2007: Off-system sales revenue declined 22 percent in 2008. Sales volumes decreased due to changes to Idaho Power’s risk management policy guidelines implemented in 2008 that resulted in less forward sales activity. Revenue per MWh increased due to the impact of higher energy commodity prices through much of 2008.

Other revenues: The following table presents the components of other revenues:

		2009		2008		2007
Transmission services and property rental		$	36,037	$	31,456	$	38,663
Energy efficiency			31,821		18,880		13,487
	Total	$	67,858	$	50,336	$	52,150

2009 vs. 2008: Other revenues increased $18 million due mainly to the following:

• Transmission revenues increased $5 million due primarily to OATT rate refunds ordered by the FERC reducing 2008 revenues. Idaho Power recorded approximately $4 million of refunds related to transmission sales from prior years. The OATT is discussed in more detail in Note 3 to the consolidated financial statements; and

• Energy efficiency revenues increased $13 million. These revenues mirror program expenditures and result in a zero net impact on net income. Energy efficiency revenues and expenses have steadily increased as program activity has increased.

2008 vs. 2007: Other revenues decreased $2 million due mainly to the following:

• Transmission revenues decreased $7 million, due primarily to the aforementioned OATT rate refunds and to OATT rate decreases; and

• Energy efficiency revenues increased $5 million.

Energy efficiency activities are funded through a rider mechanism on customer bills. Energy efficiency program expenditures are reported as an operating expense with an equal amount of revenues recorded in other revenues, resulting in no net impact on earnings. The cumulative variance between expenditures and amounts collected through the rider is recorded as a regulatory asset or liability pending future collection from or obligation to customers. An asset balance indicates that Idaho Power has spent more than it has collected and a liability balance indicates that Idaho Power has collected more than it has spent. At December 31, 2009, Idaho Power’s rider balance was a regulatory asset of $11 million.

Purchased power: The following table presents Idaho Power’s purchased power expenses and volumes:

	2009		2008		2007
Expense	$	160,569	$	231,137	$	289,484
MWh purchased		2,912		3,716		5,196
Cost per MWh purchased	$	55.14	$	62.20	$	55.71

2009 vs. 2008: Purchased power expense decreased $71 million due to lower system load and more favorable hydroelectric generating conditions, which decreased the amount of purchased power Idaho Power needed to serve loads.

2008 vs. 2007: Purchased power expense decreased $58 million due to improved hydroelectric generation conditions and more normal weather, which allowed Idaho Power to better utilize its own generation resources. Despite improved water conditions in the region, overall market prices remained higher early in the year due to a gradual spring runoff and a need to re-fill reservoirs. In addition, increases in energy commodity prices impacted the electricity market.

Fuel expense: The following table presents Idaho Power’s fuel expenses and generation at its coal and natural gas generating plants:

			2009		2008		2007
Expense
	Coal		$	130,234	$	132,015	$	114,837
	Natural gas and other			19,332		17,388		19,485
		Total fuel expense	$	149,566	$	149,403	$	134,322
MWh generated
	Coal			6,941		7,279		7,145
	Natural gas and other			242		217		222
		Total MWh generated		7,183		7,496		7,367
Cost per MWh
	Coal		$	18.76	$	18.14	$	16.07
	Natural gas		$	79.88	$	80.13	$	87.77
	Weighted average, all sources		$	20.82	$	19.93	$	18.23

2009 vs. 2008: Fuel expense remained nearly the same due to offsetting variances. The decrease in generation is due to lower system loads and lower wholesale energy prices, which resulted in reduced dispatch due to economics, and an unplanned mid-year maintenance outage at Boardman. Coal prices were higher in 2009 due to an increase in operating costs at Bridger Coal Company, which supplies coal to the Jim Bridger plant, as well as higher prices for coal delivered to the Boardman plant.

2008 vs. 2007: Fuel expense increased $15 million due to higher coal prices at the Valmy and Jim Bridger plants. Coal prices at Valmy increased 13 percent due to higher transportation costs. Production costs at Bridger Coal Company were 13 percent higher due to difficulties with its underground longwall mining operation in January and February, the continued transition to underground mining operations, and rising prices for fuel and other commodities. The increases were partially offset by a nine percent reduction in fuel expense at Idaho Power’s natural gas fired plants, which had favorable market conditions in the fourth quarter due to pipeline transportation constraints in the region.

PCA: PCA expense represents the effects of the Idaho and Oregon power supply costs deferral mechanisms, which are discussed in more detail below in “REGULATORY MATTERS – Power Supply Cost Deferrals.” In each year presented, net power supply costs were higher than the amounts estimated in the annual PCA forecast, resulting in the deferral of costs for recovery in subsequent rate years. As the deferred costs are recovered in rates, the deferred balances are amortized.

The following table presents the components of the PCA:

		2009		2008		2007
Idaho power supply cost deferral		$	(42,533)	$	(108,688)	$	(118,850)
Oregon power supply cost deferral			184		(5,196)		(1,994)
Oregon 2007 excess power cost order			(6,358)		-		-
Amortization of prior year authorized balances			115,417		66,471		(287)
	Total power cost adjustment	$	66,710	$	(47,413)	$	(121,131)

2009 vs. 2008: The $114 million change in the PCA is due primarily to lower deferral of power supply costs and higher amortization of previously deferred power supply costs. In addition, an order from the OPUC that allows Idaho Power to defer for future recovery $6 million of costs incurred in 2007 was recorded in May 2009.

2008 vs. 2007: The $74 million change in 2008 PCA expense is due primarily to higher amortization from prior year excess net power supply costs to match increased revenues.

Other operations and maintenance (O&M) expenses:
2009 vs. 2008: Other O&M expenses increased $6 million due primarily to an $8 million increase in labor related charges and a $2 million increase in charges for uncollectible accounts, partially offset by decreases of $4 million in legal, other contracted services and office supplies due to cost containment measures.

The deterioration of the economy across Idaho Power’s service area led to an increase in uncollectible accounts to approximately $5 million representing approximately a half percent of general business revenues for 2009. The reserve for uncollectible accounts has also increased over 2008 levels most notably the residential and commercial reserves.

2008 vs. 2007: Other O&M expenses increased $8 million due mainly to an $11 million increase in labor related charges, a $2 million increase due to new water leases, a $2 million increase in uncollectible accounts due to economic conditions, and an increase of $4 million for workers’ compensation, legal and other outside services. The increases were partially offset by a $6 million decrease in FCA charges, a $3 million decrease in transmission costs due to lower purchased power volumes and lower thermal O&M expense of $4 million due to lower annual outage costs.

Energy efficiency: Energy efficiency activities are funded through a rider mechanism on customer bills. Energy efficiency program expenditures are reported as an operating expense with an equal amount of revenues recorded in other revenues, resulting in no net impact on earnings. Energy efficiency expenses were $32 million, $19 million and $14 million in 2009, 2008 and 2007, respectively.

Gain on the sale of emission allowances: Gain on sale of emission allowances was $0.3 million, $0.5 million and $3 million in 2009, 2008 and 2007, respectively. The bulk of Idaho Power’s accumulated excess emission allowances were sold from 2005 to 2007.

Non-utility Operations

IFS: IFS contributed $1 million, $3 million and $7 million to net income in 2009, 2008 and 2007, respectively; principally from the generation of federal income tax credits and accelerated tax depreciation benefits related to its investments in affordable housing and historic rehabilitation developments.

IFS made $14 million in new investments in 2009 and $8 million in 2008. IFS generated tax credits of $8 million, $11 million and $15 million during 2009, 2008 and 2007, respectively. IFS will continue to pursue new opportunities for investment commensurate with the ongoing needs of IDACORP.

Ida-West: Ida-West had net income of $3 million in 2009 and $2 million in 2008 and 2007. Ida-West continues to hold joint venture investments in independent power projects.

Energy Marketing: In 2003, IE wound down its power marketing operations, closed its business locations and sold its forward book of electricity trading contracts to Sempra Energy Trading. In 2007, all trading contracts expired. IE has not recorded any material net income for the years presented. Currently, IE has no operations but has been working to settle outstanding legal matters surrounding transactions in the California energy markets in 2000 and 2001.

Discontinued Operations: Discontinued operations presents the results of operations of IDACOMM, Inc. prior to its sale in early 2007.

Income Taxes
Idaho Power is currently evaluating a tax accounting method change that would allow a current income tax deduction for repair related expenditures on its utility assets that are currently capitalized for book and tax purposes. The deduction would be computed for tax years 1999 and forward. Idaho Power has the ability to apply for this method change following the automatic consent procedures and could make such application with the filing of IDACORP’s 2009 consolidated federal income tax return in September 2010. Idaho Power’s prescribed regulatory accounting treatment requires immediate income recognition for temporary tax differences of this type. A regulatory asset is established to reflect Idaho Power’s ability to recover increased income tax expense when such temporary differences reverse.

Status of audit proceedings: In December 2008, the IRS began its examination of IDACORP’s 2006 tax year. The 2006 exam was completed in May 2009. The IRS began its examination of IDACORP’s 2007-2008 tax years in July 2009 and completed the exam in December. The 2006 examination report was submitted to the U.S. Congress Joint Committee on Taxation (JCT) for review in June 2009 and was accepted without change in July. Tax years 2007-2008 did not require JCT review. The settlement of these years resulted in a net income tax benefit of $4 million for 2009 at both IDACORP and Idaho Power.

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 2009 examination is expected to be completed in 2010. In January 2010, IDACORP was accepted into CAP for its 2010 tax year. IDACORP and Idaho Power are unable to predict the outcome of these examinations.

Specifically within the 2009 CAP examination, the IRS began its audit of Idaho Power’s current method of uniform capitalization. In September 2009, the IRS issued Industry Director Directive #5 (IDD) which discusses the IRS’s compliance priorities and audit techniques related to the allocation of mixed service costs in the uniform capitalization methods of electric utilities. The IRS and Idaho Power are jointly evaluating the impact the IDD guidance has on Idaho Power’s uniform capitalization method. Idaho Power expects that the examination will be completed during 2010.

LIQUIDITY AND CAPITAL RESOURCES:

Operating Cash Flows

IDACORP’s operating cash flows are driven principally by Idaho Power. General business revenues and the costs to supply power to general business customers are factors that have the greatest impact on Idaho Power’s operating cash flows, and are subject to risks and uncertainties relating to weather and water conditions and Idaho Power’s ability to obtain rate relief to cover its operating costs and provide a return on investment.

IDACORP’s and Idaho Power’s operating cash inflows for the year ended December 31, 2009, were $284 million and $272 million, respectively. These amounts were an increase of $148 million and $153 million, respectively, compared to the year ended December 31, 2008. The following are significant items that affected operating cash flows in 2009:

• In 2009, PCA rates more closely matched actual net power supply costs than in 2008. This more timely recovery of current costs improved cash flows by approximately $65 million compared to 2008. In addition, the collection of deferred net power supply costs increased $49 million compared to 2008.

• Changes in net cash paid and refunded for income taxes improve cash flows by $42 million and $50 million at IDACORP and Idaho Power, respectively, primarily due to audit settlements.

• A refund of $13 million was made to Idaho Power’s transmission customers upon a final order from the FERC on Idaho Power’s OATT. The OATT is discussed further in Note 3 to the consolidated financial statements.

• Net income increased by approximately $26 million and $28 million at IDACORP and Idaho Power, respectively, compared to 2008.

IDACORP’s and Idaho Power’s operating cash flows for the year ended December 31, 2008 were $137 million and $120 million, respectively. These amounts were an increase of $56 million and $38 million, respectively, compared to the year ended December 31, 2007. The following are significant items that affected operating cash flows in 2008:

• Collection of previously deferred net power supply costs increased $66 million compared to 2007.

• Income tax payments increased $17 million and $33 million for IDACORP and Idaho Power, respectively, due to the timing of and increases in taxable income.

Investing Cash Flows

Idaho Power’s construction expenditures were $252 million, $244 million and $287 million in 2009, 2008 and 2007, respectively. Idaho Power is experiencing a cycle of heavy infrastructure investment needed to address customer growth, peak demand growth, and aging plant and equipment.

Net proceeds from the sales of emission allowances provided investing cash of approximately $2 million, $3 million and $20 million in 2009, 2008 and 2007, respectively. The changes were primarily caused by changes in the number of allowances sold each year as well as changes in market prices.

In August 2007, Idaho Power reimbursed IDACORP for the $44 million refundable tax deposit IDACORP made on Idaho Power’s behalf with the IRS related to a disputed income tax assessment. In May 2008, Idaho Power withdrew $20 million from the deposit and in December 2008 the remainder of the deposit was applied to accrued taxes and interest. Income tax matters are discussed further in Note 2 to the consolidated financial statements.

In 2009 and 2008, Idaho Power had cash inflows of $2 million and $5.7 million, respectively, from the sale of Southwest Intertie Project rights-of-way. IDACORP made cash investments in affordable housing through IFS of $6 million and $8 million in 2009 and 2008, respectively. In 2009, IFS received $9 million from the sale of investments.

Financing Cash Flows

Debt: On December 1, 2009, Idaho Power repaid $80 million of its 7.2% First Mortgage Bonds. On November 20, 2009, Idaho Power issued $130 million of its 4.5% First Mortgage Bonds, Secured Medium Term Notes, Series H, due March 1, 2020. On August 20, 2009, Idaho Power completed the remarketing of its $166.1 million Pollution Control Revenue Refunding Bonds and on August 25, 2009, Idaho Power used the proceeds from the remarketed bonds plus other funds to prepay its $170 million Term Loan Credit Agreement. The Pollution Control Revenue Refunding Bonds and Term Loan Credit Agreement are discussed further in Note 4 to the consolidated financial statements. On March 30, 2009, Idaho Power issued $100 million of its 6.15% First Mortgage Bonds, Secured Medium-Term Notes, Series H, due April 1, 2019. On February 27, 2009, IFS repaid $7 million of its outstanding debt. IDACORP and Idaho Power reduced short-term debt by $94 million and $109 million, respectively.

On July 10, 2008, Idaho Power issued $120 million of its 6.025% First Mortgage Bonds, Secured Medium-Term Notes, Series H, due July 15, 2018. On October 18, 2007, Idaho Power issued $100 million of 6.25% First Mortgage Bonds, Secured Medium-Term Notes, Series G, due October 15, 2037. On June 22, 2007, Idaho Power issued $140 million of 6.30% First Mortgage Bonds, Secured Medium-Term Notes, Series F, due June 15, 2037. These issuances were used to retire short-term and long-term debt and finance capital expenditures.

Equity: IDACORP has entered into Sales Agency Agreements as a means of selling its common stock from time to time in at-the-market offerings. Under these agreements IDACORP sold 881,337 shares in 2007 at an average price of $32.32. In 2008, IDACORP sold 1,453,967 shares an average price of $28.72. In 2009, IDACORP received $14 million, net of agent’s fees, from the issuance of 489,360 shares. The average price of the shares sold was $28.79. IDACORP’s current Sales Agency Agreement is with BNY Mellon Capital Markets, LLC. As of December 31, 2009, there were 2.1 million shares remaining on the current agency agreement.
IDACORP uses original issue common stock for its Dividend Reinvestment and Stock Purchase Plan and 401(k) plan for the purpose of adding additional common equity to its capital structure. Under these plans, IDACORP issued 366,673 shares in 2009, 280,250 shares in 2008 and 250,020 shares in 2007, for proceeds of $9.6 million, $8.4 million and $8.4 million, respectively.

IDACORP issued 25,800 shares in 2009, 30,700 shares in 2008 and 10,070 shares in 2007, in connection with the exercise of stock options, for proceeds of $0.6 million, $0.9 million and $0.3 million, respectively.

IDACORP and Idaho Power paid dividends of $57 million, $54 million and $53 million in 2009, 2008 and 2007, respectively. IDACORP made capital contributions of $20 million, $37 million and $51 million to Idaho Power in 2009, 2008 and 2007, respectively.

Financing Programs

IDACORP’s consolidated capital structure consisted of common equity of 49 percent and debt of 51 percent at December 31, 2009. Idaho Power’s consolidated capital structure consisted of common equity of 47 percent and debt of 53 percent at December 31, 2009.

Shelf Registrations: IDACORP currently has approximately $574 million remaining on its shelf registration statement that can be used for the issuance of debt securities and common stock. Effective with the November 20, 2009, issuance noted above, Idaho Power has no securities remaining registered on its shelf registration statement. Idaho Power intends to file a new shelf registration statement that can be used for the issuance of first mortgage bonds and unsecured debt. Please see Note 4 to IDACORP’s and Idaho Power’s consolidated financial statements for more information regarding long-term financing arrangements.

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

Each facility contains a covenant requiring a leverage ratio of consolidated indebtedness to consolidated total capitalization of no more than 65 percent as of the end of each fiscal quarter. At December 31, 2009, the leverage ratio for IDACORP was 51 percent and for Idaho Power was 53 percent. There are additional covenants, subject to exceptions, that prohibit or restrict: certain investments or acquisitions; mergers or sale or disposition of property without consent; the creation of certain liens; and any agreements restricting dividend payments to the company from any material subsidiary. At December 31, 2009, IDACORP and Idaho Power were in compliance with all facility covenants.

The events of default under the facilities include: nonpayment of principal, interest and fees, when due or subject to a grace period; materially false representations or warranties; breach of covenants, subject in some instances to grace periods; bankruptcy or insolvency-related events; default in the payment of indebtedness in excess of $25 million, defaults that will permit acceleration of such debt, or the acceleration of any of such debt; the acquisition of 20 percent of the outstanding voting shares of the company; the failure of IDACORP to own all of the outstanding voting stock of Idaho Power; unfunded liabilities of all single employer plans under the Employee Retirement Income Security Act of 1974 (ERISA) exceeding $75 million; and environmental proceedings, investigations or violations of law, which could reasonably be expected to have a material adverse effect.

The facilities were amended effective February 2, 2010 at the request of IDACORP and Idaho Power because of their concern about continuing compliance with the unfunded liability provisions. The amendments removed representations and default provisions relating to unfunded liabilities of all single employer plans in excess of $75 million and replaced them with representations and default provisions relating to meeting the minimum funding standards and not requesting a funding waiver under the Internal Revenue Code or ERISA. Unfunded liabilities will now be relevant and measured only upon notice of termination of a plan and will then constitute a default only if they exceed $75 million.

A default or an acceleration of indebtedness of IDACORP or Idaho Power in excess of $25 million, including indebtedness under the applicable facility, will result in a cross default under the other facility. Upon any bankruptcy or insolvency-related event of default, the obligations of the lenders to make loans under the facility will automatically terminate and all unpaid obligations will become due and payable. Upon any other event of default, the lenders holding 51 percent of the outstanding loans or of the aggregate commitments may terminate or suspend the obligations to make loans or declare the obligations to be due and payable.

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

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

The following table outlines available liquidity as of December 31, 2009 and 2008.

	IDACORP⁽²⁾				Idaho Power
	2009		2008		2009		2008

Revolving credit facility	$	100,000	$	100,000	$	300,000	$	300,000
Commercial paper outstanding		(53,750)		(13,400)		-		(108,950)
Floating rate draw		-		(25,000)		-		-
Identified for other use ⁽¹⁾		-		-		(24,245)		(24,245)
Net balance available	$	46,250	$	61,600	$	275,755	$	166,805
⁽¹⁾ Port of Morrow and American Falls bonds that holders may put to Idaho Power.
⁽²⁾ Holding company only.

At February 19, 2010, IDACORP had no loans and $25 million of commercial paper outstanding and Idaho Power had no loans and no commercial paper outstanding.

Credit Ratings

Access to capital markets at a reasonable cost is determined in large part by credit quality. The following table outlines the current S&P, Moody’s and Fitch Ratings, Inc. (Fitch) ratings of IDACORP’s and Idaho Power’s securities:

	S&P		Moody’s		Fitch
	Idaho Power	IDACORP	Idaho Power	IDACORP	Idaho Power	IDACORP
Corporate Credit Rating	BBB	BBB	Baa 1	Baa 2	None	None
Senior Secured Debt	A-	None	A3	None	A-	None
Senior Unsecured Debt	BBB	BBB-	Baa 1	Baa 2	BBB+	BBB
Short-Term Tax-Exempt Debt	BBB-/A-2	None	Baa 1/	None	None	None
			VMIG-2
Commercial Paper	A-2	A-2	P-2	P-2	F-2	F-2
Credit Facility	None	None	Baa 1	Baa 2	None	None
Rating Outlook	Stable	Stable	Negative	Negative	Negative	Negative

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

Capital Requirements

Idaho Power is experiencing a cycle of heavy infrastructure investment, adding capacity to its baseload generation, transmission system and distribution facilities to ensure adequate supply of electricity, to provide service to new customers and to maintain system reliability. Idaho Power’s aging hydroelectric and thermal generation facilities require continuing upgrades and component replacement, and the costs related to relicensing hydroelectric facilities and complying with the new licenses are substantial. Due to the heavy infrastructure requirements from 2010-2012, Idaho Power will continue to focus on critical infrastructure needs that relate to system reliability and resource adequacy and has reduced ongoing capital expenditures and major projects from prior estimates. The table below presents the low and high ranges of the capital expenditure categories. Idaho Power expects that total capital expenditures will be at or slightly above $1 billion from 2010-2012. Internal cash generation after dividends is expected to provide less than the full amount of total capital requirements for 2010 through 2012. While IDACORP and Idaho Power expect minimal need for external financing in 2010, except for issuances under the dividend reinvestment and employee-related plans, and potential pre-funding of 2011 debt maturities should IDACORP and Idaho Power decide to access the capital markets, IDACORP has access to its registered securities including its Continuous Equity Program (CEP) which has approximately 2.1 million shares of common stock available and Idaho Power intends to file a new shelf registration statement that can be used for the issuance of first mortgage bonds and unsecured debt. IDACORP and Idaho Power expect to continue financing capital requirements with a combination of internally generated funds and externally financed capital.

The following table presents Idaho Power’s estimated cash requirements for construction, excluding AFUDC, for 2010 through 2012 (in millions of dollars):

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

Major Projects:

AMI: The AMI project provides the means to automatically retrieve energy consumption information, eliminating manual meter reading expense. Idaho Power intends to install this technology for approximately 99 percent of its customers and is on pace to complete the installations by the end of 2011. The total cost estimates for the project are approximately $74 million. Idaho Power has expended approximately $24 million of the total costs as of December 31, 2009. The remaining costs are included in the table above.

Langley Gulch Power Plant: On September 1, 2009, the IPUC issued an order granting Idaho Power’s March 6, 2009, request for a CPCN authorizing Idaho Power to construct, own and operate the Langley Gulch power plant. Langley Gulch will be a natural gas-fired CCCT generating plant with a summer nameplate capacity of approximately 300 MWs and a winter capacity of approximately 330 MWs. The plant will be constructed near New Plymouth, Idaho, commencing in summer 2010, and is anticipated to achieve commercial operation by November 1, 2012. Contract incentives may advance the commercial operation date to July 1, 2012. The total cost estimate for the project including AFUDC is $427 million, $54 million of which Idaho Power incurred as of December 31, 2009. The remaining costs are included in the table above. The plant will connect to Idaho Power’s existing grid.

Idaho Power requested in its application that the IPUC provide Idaho Power with assurances of future ratemaking treatment for construction costs up to Idaho Power’s cost estimate. In the order, the IPUC found that Idaho Power had satisfied statutory requirements that would entitle Idaho Power to receive such ratemaking assurances. The order grants Idaho Power assurance and pre-approval to include $396.6 million of construction costs in Idaho Power’s rate base when Langley Gulch achieves commercial operation. The order contemplates that Idaho Power may request recovery of additional costs if they exceed $396.6 million provided that Idaho Power is able to demonstrate that the additional costs were reasonably and prudently incurred.

Idaho Power is responsible for specific portions of the Langley Gulch Project, which include permitting the site under the Payette County planning and zoning ordinance, design and construction of the cooling water pump station and pipeline from the Snake River to the site, design and construction of the gas pipeline from the Williams Northwest Pipeline to the site, and design and construction of the new electric transmission lines to the existing grid. The cost of these activities are included in the $427 million estimated total cost for Langley Gulch.

Other Major Projects:

Hemingway Station: Construction is underway for the new 500-kV Hemingway station, located near Boise, Idaho. This station will relieve capacity and operating constraints to ensure reliable service to Idaho Power’s network and native load customers. The station was originally part of the Gateway West Project, but construction was accelerated to help meet forecast deficits and improve reliability. The station is expected to be in service by summer 2010 at a total cost of approximately $57 million. The 2010 cost estimate for the project, including substation interconnections, is $20 million and is included in the above table.

Hemingway-Bowmont Transmission Line: A part of the Hemingway Station Project, the Hemingway-Bowmont transmission line, currently under construction, is 12 miles of new 230-kV double circuit transmission line that will provide power to the Treasure Valley in southwest Idaho. The project is scheduled to be in service by summer 2010 at a total cost of approximately $16 million. The 2010 cost estimate for the project is $6.5 million and is included in the above table.

Boardman-Hemingway Line: The Boardman-Hemingway Line is a proposed 500-kV transmission project between a substation near Boardman, Oregon and the Hemingway station. This line will provide transmission service for existing network and native load customers and other requests pursuant to Idaho Power’s OATT, and will improve reliability and relieve existing congestion. The line will allow for the transfer of up to 1,500 MW of additional energy between Idaho and the Northwest, depending on the outcome of WECC rating studies to determine project capacity limits. On March 9, 2009, Idaho Power initiated a community advisory project to engage the public in route selection alternatives. Idaho Power’s preferred route selection will be processed in compliance with the National Environmental Policy Act and Oregon Energy Facility Siting Council requirements. The initial phase of the project, estimated at $50 million, will be funded primarily by Idaho Power and includes the engineering, environmental review, permitting and rights-of-way. Cost estimates for the 2010-2012 timeframe of the initial phase are included in the table above. Total cost estimates for the project (including initial phase project estimate and construction costs of the line) are approximately $600 million. Idaho Power expects its share of the project to be between 30 and 50 percent, to meet needs identified in the 2009 IRP and forecast growth of network customers. Idaho Power and PacifiCorp are exploring potential joint development and ownership opportunities regarding the Boardman-Hemingway project. The Bonneville Power Administration is also currently investigating whether participation in project may be feasible. This project is expected to be completed in 2015 subject to siting, permitting and regulatory approvals. Construction costs beyond the initial phase are not included in Idaho Power’s 2010 to 2012 forecast.

Gateway West Project: Idaho Power and PacifiCorp are jointly exploring the Gateway West project to build transmission lines between Windstar, a substation located near Douglas, Wyoming and the Hemingway station. This project will provide transmission service for existing network and native load customers, forecasted growth and requests pursuant to Idaho Power’s OATT transmission obligations. The project is expected to improve reliability and relieve existing congestion. Idaho Power and PacifiCorp have a cost sharing agreement for expenses incurred for analysis work of the initial phases.

Idaho Power’s share of the initial phase of engineering, environmental review, permitting and rights-of-way is approximately $40 million and cost estimates for the 2010-2012 timeframe of the initial phase are included in the above table. Construction costs are not included in Idaho Power’s 2010 to 2012 forecast. Initial phases of the project could be completed by 2014 depending on the timing of rights-of-way acquisition, siting and permitting, and construction sequencing. Idaho Power’s share will vary by segment across the project and the current estimated cost for its share is between $300 million and $500 million. However, based on the 2009 IRP and the withdrawal of some third-party transmission service requests, Idaho Power’s share may change and the timing of the projects segments may be deferred and constructed as demand requires. The Bureau of Land Management has indicated the draft environmental impact statement is expected to be issued during the summer of 2010.

For a discussion of environmental considerations relating to the above projects, see “ENVIRONMENTAL ISSUES – Endangered Species.”

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

Environmental Regulation Costs: Idaho Power anticipates approximately $42 million in annual capital and operating costs for environmental facilities during 2010. Hydroelectric facility expenses including costs for relicensing Hells Canyon and thermal plant expenses account for approximately $22 million and $20 million, respectively. From 2011 through 2012, total environmental related operating and capital costs are estimated to be approximately $122 million. Expenses related to the hydroelectric facilities are expected to be $62 million and include costs associated with the relicensing of Hells Canyon. Thermal plant expenses are expected to total $60 million during this period. These amounts are included in the table above but do not include costs related to possible changes in the environmental laws or regulations and enforcement policies that may be enacted in response to issues such as climate change and other pollutant emissions from coal-fired generation plants.

Other capital requirements: IDACORP’s non-regulated capital expenditures are expected to be $7 million in 2010 and primarily relate to IFS’s tax-structured investments. Currently there are no expenditures anticipated for 2011 or 2012.

American Recovery and Reinvestment Act of 2009

Under the ARRA, Idaho Power submitted a grant application to the Department of Energy (DOE) in August 2009, requesting $47 million. This grant would match a $47 million investment by Idaho Power in Smart Grid technology as well as other incremental projects. In October 2009, Idaho Power received notice that its application was selected for negotiation. Negotiations with the DOE on the grant agreement terms are expected to be complete in the first quarter of 2010.

Off-Balance Sheet Arrangements

Idaho Power has agreed to guarantee the performance of reclamation activities at Bridger Coal Company of which IERCo owns a one-third interest. This guarantee, which is renewed each December, was $63 million at December 31, 2009. Bridger Coal Company has a reclamation trust fund set aside specifically for the purpose of paying these reclamation costs. At this time Bridger Coal Company is revising their estimate of future reclamation costs. To ensure that the reclamation trust fund maintains adequate reserves, Bridger Coal Company has the ability to add a per ton surcharge if it is determined that future liabilities exceed the trust’s assets. 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.

Contractual Obligations

The following table presents IDACORP’s and Idaho Power’s contractual cash obligations for the respective periods in which they are due:

			Payment Due by Period
			Total		2010		2011-2012		2013-2014		Thereafter
			(millions of dollars)
Idaho Power:
Long-term debt ⁽¹⁾			$	1,414	$	1	$	222	$	72	$	1,119
Future interest payments ⁽²⁾				1,256		77		146		129		904
Operating leases				15		3		3		3		6
Purchase obligations:
	Cogeneration and small power
		production		2,214		83		222		229		1,680
	Large power production ⁽³⁾			260		128		132		-		-
	Fuel supply agreements			383		64		117		107		95
	Purchased power & transmission ⁽⁴⁾			89		44		31		6		8
	Other ⁽⁵⁾			149		65		36		21		27
		Total purchase obligations		5,780		465		909		567		3,839
Pension and postretirement plans ⁽⁶⁾				256		13		106		95		42
Other long-term liabilities - Idaho Power				4		3		1		-		-
	Total Idaho Power			6,040		481		1,016		662		3,881
Other:
Long-term debt ⁽¹⁾⁽⁷⁾				9		8		-		-		1
	Total IDACORP		$	6,049	$	489	$	1,016	$	662	$	3,882
⁽¹⁾ For additional information, see Note 4 to IDACORP’s and Idaho Power’s Consolidated Financial Statements.
⁽²⁾ Future interest payments are calculated based on the assumption that all debt is outstanding until maturity. For debt instruments with variable rates, interest is calculated for all future periods using the rates in effect at December 31, 2009.
⁽³⁾ Large power production relates to the Langley Gulch power plant and includes two contracts with Siemens Energy, Inc. relating to the purchase of a gas turbine and the purchase of a steam turbine and an Engineering, Procurement and Construction Services 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 Langley Gulch.
⁽⁴⁾ Approximately $21 million of the obligations included in purchased power and transmission have contracts that do not specify terms related to expiration. As these contracts are presumed to continue indefinitely, 10 years of information estimated based on current contract terms, have been included in the table for presentation purposes.
⁽⁵⁾ Approximately $51 million of the amounts in other purchase obligations are contracts that do not specify terms related to expiration. As these contracts are presumed to continue indefinitely, 10 years of information, estimated based on current contract terms, have been included in the table for presentation purposes.
⁽⁶⁾ Idaho Power estimates pension contributions based on actuarial data. Idaho Power cannot estimate pension contributions beyond 2014 at this time. For more information on pension, please refer to Note 11 of IDACORP’s and Idaho Power’s Consolidated Financial Statements.
⁽⁷⁾ Amounts include the obligations of IDACORP’s subsidiaries other than Idaho Power, which is shown separately.

REGULATORY MATTERS:

Rate changes and regulatory decisions have a significant impact on results of operations and cash flows. This section discusses several important rate matters that have affected results during the past two years, as well as significant pending regulatory issues. Regulatory matters and the financial impact of rate decisions are also discussed in Note 3 to the consolidated financial statements.

Idaho Power has continued to focus on timely recovery of its costs through filings with the IPUC and OPUC. The table below summarizes the most significant base rate changes during the last two years.

		Annualized
	Effective	$ Impact
Description	Date	(millions)		Notes
Base rate increases
Idaho
2007 general rate case	3/1/2008	$	32.1	No rates of return were specified in the settlement
Danskin power plant	6/1/2008		8.9	Adds $64.2 million to rate base for this project
2008 general rate case	2/1/2009 3/19/2009		20.9 6.1	Provides a return on equity of 10.5 percent and overall rate of return of 8.18 percent. Approximately $15 million related to increases in base net power supply costs. Allowed Idaho Power to include in rates approximately $10.6 million relating to AFUDC on the Hells Canyon Complex relicensing project.
AMI	6/1/2009		10.5	Order is based on Idaho Power’s projected investment in AMI through December 31, 2009. Allowed Idaho Power to begin three-year accelerated depreciation of existing metering equipment on June 1, 2009. The associated increase in annualized depreciation expense is $9.2 million.
Oregon
2008 annual power cost update	6/1/2008		4.8	Represents a 15.7 percent increase in Oregon rates.
Depreciation filing	1/1/2009		(0.4)
AMI	6/1/2009		0.8	Authorizes accelerated depreciation and recovery of existing meters in the Oregon jurisdiction over an 18-month period beginning January 2009. The associated increase in annual depreciation expense is $0.8 million
2009 annual power cost update	6/1/2009		3.9	Represents an 11.5 percent increase in Oregon rates.

2009 Idaho Settlement Agreement

On January 13, 2010, the IPUC approved a settlement agreement among Idaho Power, several of Idaho Power’s customers, the IPUC staff and others. Significant elements of the settlement agreement include:

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

• A specified distribution of the expected 2010 PCA. This distribution is intended to reduce customer rates, provide some general rate relief to Idaho Power and reset base power supply costs for the PCA. The associated rate change is expected to become effective June 1, 2010. This provision is in anticipation of a significant reduction in PCA rates for the 2010-2011 PCA year. The PCA reduction will be allocated as follows:

o The first $40 million will be allocated equally between customers and Idaho Power. Idaho Power’s share would be applied to increase permanent base rates on a uniform percentage basis to all customer classes and contract customers. The customers’ share would be a direct PCA rate reduction.

o All of the next $20 million will be allocated to customers as a direct PCA rate reduction.

o PCA reductions in excess of $60 million will be applied to absorb any increase in the base level of net power supply expenses.

o If the PCA reduction exceeds $60 million plus the increase in base net power supply expenses, the next $10 million will be allocated equally between Idaho Power and customers.

o Any remainder will go entirely to customers.

• A provision to share earnings with customers if Idaho Power’s actual rate of return on equity is more than 10.5 percent in any calendar year from 2009 to 2011 in its Idaho jurisdiction. Idaho Power will share with Idaho customers 50 percent of any returns in excess of 10.5 percent.

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

Because Idaho Power’s Idaho-jurisdiction return on equity was between 9.5 and 10.5 percent, the sharing and accelerated amortization provisions were not triggered in 2009.

The settlement agreement also included a provision to reestablish the base level for net power supply costs effective with the June 1, 2010, PCA rate change. On January 19, 2010, Idaho Power filed with the IPUC a request to increase base net power supply costs by $74.8 million in the Idaho jurisdiction. This amount, which is subject to approval by the IPUC, reflects the maximum increase to Idaho Power’s base net power supply costs, which would be used for both base rates and PCA calculations. The actual change in net power supply costs for rate purposes will depend upon the amount approved by the IPUC as well as the amount of any PCA decrease determined for the 2010-2011 PCA year. Written comments or protests with respect to Idaho Power’s application are due March 11, 2010.

2009 Oregon Rate Case: On December 16, 2009, Idaho Power filed a Joint Stipulation and testimony in support of a stipulation that would settle the revenue requirement issues surrounding the general rate case filed on July 31, 2009. If approved by the OPUC, the Joint Stipulation would result in a $5 million, or 15.4 percent, increase to base rates. The new rates reflect a return on equity of 10.175 percent and an overall rate of return of 8.061 percent. The requested effective date for new rates is March 1, 2010.

Power Supply Cost Deferrals

Idaho Power’s power supply costs can vary significantly from year to year, primarily because of weather, loads and commodity markets. Idaho Power has power cost adjustment mechanisms in both Idaho and Oregon. These mechanisms allow Idaho Power to recover from or refund to customers a majority of the fluctuations in power supply costs. Because of these mechanisms, the primary financial impacts of power supply cost variations is that cash is paid out but recovery from customers does not occur until a future period, resulting in fluctuations in operating cash flows from year to year.

The following table summarizes Idaho Power’s deferred power supply cost activity during the last two years.

	Idaho		Oregon ⁽¹⁾		Total
Balance at January 1, 2008	$	92,322	$	5,100	$	97,422
Costs deferred through PCA and PCAM		108,688		5,196		113,884
Prior costs expensed and recovered through rates		(64,030)		(2,441)		(66,471)
SO₂ allowances credited to account ⁽²⁾		(2,184)		(175)		(2,359)
Interest and other		6,025		598		6,623
Balance at December 31, 2008	$	140,821	$	8,278	$	149,099
Costs deferred through PCA and PCAM		42,533		(184)		42,349
Prior costs expensed and recovered through rates		(113,134)		(2,283)		(115,417)
SO₂ allowances credited to account⁽²		(2,034)		(83)		(2,117)
Interest and other		3,226		1,135		4,361
2007 Excess power costs order		-		6,358		6,358
Balance at December 31, 2009	$	71,412	$	13,221	$	84,633
⁽¹⁾ Oregon power supply cost deferrals are subject to a statute that specifically limits rate amortizations of deferred costs to six percent of gross Oregon revenue per year (approximately $2 million). Deferrals are amortized sequentially.
⁽²⁾ The IPUC has allowed Idaho Power to retain its PCA sharing percentage of the gain from sales of SO2 allowances as a shareholder benefit with the remainder recorded as a customer benefit, substantially all of which was used to reduce the PCA. Proceeds from the sale of renewable energy certificates (RECs) are also expected to reduce the PCA. RECs are acquired by Idaho Power through purchases of renewable energy.

PCA Workshops: In its order approving Idaho Power’s 2008-2009 PCA, the IPUC directed Idaho Power to set up workshops with the IPUC Staff and several of Idaho Power’s largest customers to address issues not resolved in that PCA filing. The workshops resulted in the following changes to the PCA mechanism, effective 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. The stipulation agreed on a new 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 Idaho Power’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.

Fixed Cost Adjustment Mechanism (FCA)

The FCA mechanism began as a pilot program for Idaho Power’s Idaho residential and small general service customers, running from 2007 through 2009. The FCA is a rate mechanism designed to remove Idaho Power’s disincentive to invest in energy efficiency programs by separating (or decoupling) the recovery of fixed costs from the variable kilowatt-hour charge and linking it instead to a set amount per customer. On October 1, 2009, Idaho Power filed an application with the IPUC to make the FCA mechanism permanent beginning January 1, 2010. The application is being processed under modified procedure.

Idaho Power accrued $6.6 million related to the FCA in 2009; subject to IPUC approval, recovery should begin June 1, 2010. 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. 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.

Langley Gulch Power Plant Ratemaking Treatment

On September 1, 2009, the IPUC issued an order providing cost recovery and ratemaking assurances related to Idaho Power’s Langley Gulch project. The IPUC found that Idaho Power had satisfied statutory requirements that would entitle Idaho Power to receive such ratemaking assurances and granted Idaho Power assurance and pre-approval to include $396.6 million of construction costs in Idaho Power’s rate base when Langley Gulch achieves commercial operation. The order contemplates that Idaho Power may request recovery of additional costs if they exceed $396.6 million; provided that Idaho Power is able to demonstrate that the additional costs were reasonably and prudently incurred. Please see further discussion of the Langley Gulch project in “LIQUIDITY AND CAPITAL RESOURCES - Major Projects - Langley Gulch Power Plant.”

Pension Expense

On October 20, 2009, Idaho Power filed an application with the IPUC to implement a mechanism to track and recover annually cash contributions made to the pension plan. Estimated minimum required contributions will be approximately $6 million in 2010, $44 million in 2011 $47 million in 2012, $39 million in 2013, and $40 million in 2014. In its comments, the IPUC Staff recommended against establishing an annual tracking mechanism but supported allowing the inclusion in a future rate case of reasonable amortization of cash contributions. Idaho Power met with the IPUC Staff to clarify its understanding of their recommendation. As a result of the meeting, Idaho Power filed reply comments with the IPUC stating that is was not opposed to the Staff’s recommendation with the clarification that the IPUC will approve amortization of future deferred cash contributions at the same time and in the same amounts as will be approved for recovery. On February 17, 2010, the IPUC issued its order approving the recovery methodology agreed to by Idaho Power and the IPUC Staff as clarified in Idaho Power’s reply comments. The IPUC also approved a carrying charge on the difference between actual contributions and the recovery of these amounts in rates.

Idaho Power recovers pension expense in its Oregon jurisdiction on the accrual basis.

Idaho Energy Efficiency Rider (Rider)

In the 2008 general rate case, Idaho Power requested that the IPUC explicitly find that Idaho Power’s expenditures between 2002 and 2007 of $29 million of funds obtained from the Rider were prudently incurred and no longer subject to potential disallowance. In 2009, the IPUC approved a stipulation identifying $14.3 million of Rider funding as prudent, and on January 25, 2010, Idaho Power and the IPUC Staff filed a stipulation for approval by the IPUC to find the remaining expenditures through 2007 were prudently incurred.

On October 5, 2009, Idaho Power and other investor-owned electric utilities serving in Idaho began a series of informal public workshop with the IPUC Staff to discuss how energy efficiency evaluation and prudency will be determined on a prospective basis. As a result a Memorandum of Understanding (MOU) written by Staff, Idaho Power and other investor-owned electric utilities in Idaho has been signed outlining a process for future energy expenditure approval. This document was filed with the IPUC on January 25, 2010.

In the first quarter of 2010, Idaho Power expects to request a similar prudency determination from the IPUC for Rider expenditures in 2008 and 2009. Idaho Power spent approximately $19 million in 2008 and $33 million in 2009 for rider-funded energy efficiency and demand response initiatives in its Idaho and Oregon jurisdictions combined. The increase in spending in 2009 reflects Idaho Power’s growing emphasis on these programs, such as implementation of a revised irrigation peak rewards program and commercial demand response program in 2009.

FERC OATT Proceeding: In 2006, Idaho Power moved from a fixed rate to a formula rate for its open access transmission tariff (OATT), which allows transmission rates to be updated each year. The FERC accepted Idaho Power’s new formula rates, effective June 1, 2006, subject to refund pending the outcome of a hearing and settlement process.

While the majority of issues related to Idaho Power’s 2006 revised OATT filing have been resolved, Idaho Power is awaiting an order upon reconsideration from the FERC regarding the treatment of “Legacy Agreements.” These agreements are contracts for transmission service that were in existence before the implementation of the OATT in 1996. The impact of FERC’s ruling is being mitigated by revising certain of the Legacy Agreements as provided for in the agreements. Revisions are expected to increase annual transmission revenue by approximately $3.8 million in 2010 compared to 2009.

Idaho Power’s OATT is discussed further in Note 3 to the consolidated financial statements.

FERC Compliance Program: The FERC issued Policy Statements on Enforcement in 2005 and 2008 and a Policy Statement on Compliance in 2008. These statements encourage companies to self-report to the FERC matters that constitute or may constitute violations of the Federal Power Act (FPA), the Natural Gas Act, the Natural Gas Policy Act and the requirements of FERC rules, regulations, orders and tariffs. The Policy Statements identify self-reporting as a factor the FERC will consider in determining the proper remedy for a violation and emphasize the role compliance programs play in identifying and correcting violations and in evaluating whether and the extent to which penalties may be imposed.

Idaho Power has implemented a compliance program to ensure that its operations conform to the FERC’s requirements and to provide a means of identifying, correcting and if warranted, self-reporting any such matters to the FERC. Idaho Power also self-reports matters relating to transmission reliability standards to the WECC. In 2007, FERC Order No. 693 approved mandatory reliability standards developed by the North American Electric Reliability Corporation. In 2008, FERC Order No. 706 also approved Critical Infrastructure Protection Reliability Standards (CIP) developed by the North American Electric Reliability Corporation. The WECC, a regional electric reliability organization, has responsibility for compliance and enforcement of these standards. As part of its compliance program, Idaho Power has reported compliance issues relating to the FERC’s Standards of Conduct and Idaho Power’s OATT to the FERC, as well as matters relating to CIP and other reliability standards to the WECC. Some of these matters have been resolved, while others are being reviewed by the FERC or the WECC. Those matters that have been resolved to date have resulted in no material impact to Idaho Power. Idaho Power is unable to predict what action if any the FERC or the WECC will take with regard to the unresolved matters. Idaho Power plans to continue its policy of using its compliance program to reduce potential violations and to self-report matters to the FERC and the WECC.

Bonneville Power Administration Residential Exchange Program: The Pacific Northwest Electric Power Planning and Conservation Act of 1980 (the Act), through the Residential Exchange Program (REP), has provided access to the benefits of low-cost federal hydroelectric power to residential and small farm customers of the region’s investor-owned utilities (IOUs). The REP is administered by the Bonneville Power Administration (BPA). Pursuant to agreements between the BPA and Idaho Power, benefits from the BPA were passed through to Idaho Power’s residential and small farm customers through electricity bill credits.

On May 3, 2007, the U.S. Court of Appeals for the Ninth Circuit ruled that the agreements entered into between the BPA and the IOUs (including Idaho Power) are inconsistent with the Act and shortly thereafter suspended REP payments to Idaho Power and the IOUs. Effective June 1, 2007, Idaho Power eliminated the credit on its customers’ bills. Subsequent BPA filings and decisions have provided no REP benefits to Idaho Power’s customers and Idaho Power has filed petitions for review of these decisions with the U.S. Court of Appeals for the Ninth Circuit.

Idaho Power has been working with the other northwest IOUs and consumer-owned utilities, northwest state public utility commissions and the BPA to resolve these issues.

Settlement efforts took place from August through November of 2009 and parties in the case have agreed to the selection of a mediator, with sessions expected to begin in the spring of 2010. Since these benefits were passed through to Idaho Power’s customers, the outcome of this matter is not expected to have an effect on Idaho Power’s financial condition or results of operations.

Relicensing of Hydroelectric Projects:

Idaho Power, like other utilities that operate nonfederal hydroelectric projects on qualified waterways, obtains licenses for its hydroelectric projects from the FERC. These licenses last for 30 to 50 years depending on the size, complexity, and cost of the project. Idaho Power is actively pursuing the relicensing of the Hells Canyon Complex (HCC) and Swan Falls projects.

The relicensing costs are recorded in construction work in progress until new multi-year licenses are issued by the FERC, at which time the charges will be transferred to electric plant in service. Relicensing costs and costs related to new licenses will be submitted to regulators for recovery through the ratemaking process. Relicensing costs of $117 million and $4 million for HCC and Swan Falls, respectively, were included in construction work in progress at December 31, 2009.

The IPUC authorized Idaho Power to include in rates approximately $6.8 million annually ($10.6 million grossed up for income taxes) of AFUDC relating to the HCC relicensing project. This became effective February 1, 2009, and Idaho Power collected approximately $9.7 million in 2009. Collecting these amounts in current rates will reduce the relicensing amount submitted to regulators for recovery through the ratemaking process.

Hells Canyon Complex: The most significant ongoing relicensing effort is the HCC, which provides approximately 68 percent of Idaho Power’s hydroelectric generating nameplate capacity and 36 percent of its total generating nameplate capacity. In July 2003, Idaho Power filed an application for a new license in anticipation of the July 2005 expiration of the then-existing license. Idaho Power is currently operating under an annual license issued by the FERC and expects to continue operating under annual licenses until the new license is issued.

Consistent with the requirements of the National Environmental Policy Act of 1969, as amended (NEPA), the FERC Staff issued on August 31, 2007, a final environmental impact statement (EIS) for the HCC, which the FERC will use to determine whether, and under what conditions, to issue a new license for the project. The purpose of the final EIS is to inform the FERC, federal and state agencies, Native American tribes and the public about the environmental effects of Idaho Power’s proposed operation of the HCC. Idaho Power has reviewed the final EIS and is developing comments for filing with the FERC. However, certain portions of the final EIS, involve issues that may be influenced by the water quality certifications for the project under section 401 of the Clean Water Act and formal consultations under the Endangered Species Act (ESA), which remain unresolved. Idaho Power anticipates filing comments to the final EIS as the section 401 and ESA processes progress and the manner in which they may affect pending issues becomes certain.

In conjunction with the issuance of the final EIS, on September 13, 2007, the FERC requested formal consultation under the ESA with the National Marine Fisheries Service (NMFS) and the U.S. Fish and Wildlife Service (USFWS) regarding the effect of HCC relicensing on several aquatic and terrestrial species listed as threatened under the ESA. However, formal consultation has not yet been initiated and NMFS and USFWS continue to gather and consider information relative to the effect of relicensing on relevant species. Idaho Power continues to cooperate with the USFWS, the NMFS and the FERC in an effort to address ESA concerns.

Because the HCC is located on the Snake River where it forms the border between Idaho and Oregon, Idaho Power has filed Water Quality Certification Applications, required under section 401 of the Clean Water Act, with the States of Idaho and Oregon requesting that each state certify that any discharges from the project comply with applicable state water quality standards. Temperature and other water quality issues are of interest to various federal and state agencies, Native American tribes, and other parties who may provide input to the states’ certification process. Section 401 of the Clean Water Act requires that a state either approve or deny a 401 water quality certification application within one-year of the filing of the application or the state may be considered to have waived its certification authority under the Act. As a consequence, Idaho Power has been filing and withdrawing its section 401 certification applications with Oregon and Idaho on an annual basis while it has been working through water quality certification issues with the states. Most recently, on December 23, 2009, Idaho Power withdrew the 401 certification applications filed with Oregon and Idaho, and immediately refiled the applications, in order to allow Idaho Power additional time to address unresolved issues associated with water quality certification for the project. One such issue involves the Temperature Enhancement Management Program that Idaho Power proposed in its application and whether that program provides reasonable assurance that discharges from the HCC will adequately address fall temperature water quality criteria below Hells Canyon Dam. Idaho Power is continuing to work with Idaho and Oregon to ensure that any discharges from the HCC will comply with the temperature and other applicable necessary state water quality standards so that appropriate water quality certifications can be issued for the project.

The FERC is expected to issue a license order for the HCC once the ESA consultation and the section 401 certification processes are completed.

Swan Falls Project: The license for the Swan Falls hydroelectric project expires in June 2010. In June 2008, Idaho Power filed a license application with the FERC. On January 9, 2009, the FERC issued a scoping document giving notice of scheduled scoping meetings, soliciting scoping comments and of its intent to prepare an EIS pursuant to the NEPA. FERC held scoping meetings on February 10 and 11, 2009. On May 5, 2009, FERC issued Scoping Document 2 for the project, advising that based on the scoping meetings and comments received that staff will prepare an EIS, which the FERC will use to determine whether, and under what conditions, to issue a new hydropower license for the project. On June 16, 2009, FERC issued its Notice of Application Ready for Environmental Analysis and Soliciting Comments, Recommendations, Terms and Conditions, and Prescriptions. The deadline for filing comments, recommendations, terms and conditions, and prescriptions was August 15, 2009. Filings were made by the USFWS and state of Idaho. The FERC expects to complete the EIS in 2010.

On June 6, 2008, Idaho Power filed an application with the Idaho Department of Environmental Quality (IDEQ) for section 401 water quality certification. On April 1, 2009, the IDEQ issued public notice, seeking public comment on a draft section 401 certification for the project. No public comments were submitted and the IDEQ issued the section 401 certification on May 4, 2009.

Shoshone Falls Expansion: On August 17, 2006, Idaho Power filed a license amendment application with the FERC, which would allow Idaho Power to upgrade the Shoshone Falls project from 12.5 MW to 62.5 MW. The license amendment is expected to be issued in 2010. In conjunction with the license amendment application, Idaho Power has filed a water rights application with the Idaho Department of Water Resources (IDWR).

LEGAL MATTERS:

Western Energy Proceedings at the FERC: Idaho Power and IE are parties to proceedings at the FERC arising from the “western energy situation” – the California energy crisis that occurred during 2000 and 2001, and the energy shortages, high prices and blackouts in the western United States. High prices for electricity in California and in western wholesale markets during 2000 and 2001 caused numerous purchasers of electricity in those markets to initiate proceedings seeking refunds or other forms of relief.

The three major sets of cases arising out of the western energy situation relate to (i) pricing of sales in the California Independent System Operator (Cal ISO) and California Power Exchange (CalPX) markets (the California refund proceeding); (ii) claims of market manipulation and tariff violations in those markets, some of which have been the subject of FERC show cause orders (the market manipulation cases); and (iii) pricing of sales in the spot power markets in the Pacific Northwest (the Pacific Northwest refund proceeding).

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

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

In the Pacific Northwest refund proceeding, after reviewing the FERC’s 2003 decision declining to order refunds, the Ninth Circuit remanded the case to the FERC on April 16, 2009 to consider whether evidence of market manipulation would have altered the agency’s conclusions about refunds and to include sales to the California Department of Water Resources (CDWR) in the proceedings. Although the FERC has not yet acted on the remand from the Ninth Circuit, in separate filings the California Parties (Pacific Gas & Electric Company, San Diego Gas & Electric Company, Southern California Edison Company, the California Public Utilities Commission, the California Department of Water Resources and the California Attorney General) and the City of Tacoma, Washington and the Port of Seattle, Washington asked the FERC to take actions to reorganize and restructure the case so that they may pursue claims that all spot market sales in the Cal ISO and CalPX markets and in the Pacific Northwest from January 1, 2000 through June 20, 2001 should be repriced, and thereby become subject to refund, because market manipulation and tariff violations affected spot market prices. This would expand the scope of the refund period in the Pacific Northwest proceeding from the December 25, 2000 through June 20, 2001 period previously considered by the FERC. In May 2009, the California Parties requested that the FERC sever the CDWR sales from the Pacific Northwest proceeding and consolidate the CDWR sales portion with ongoing proceedings in cases that Idaho Power and IE have settled, as well as with a new complaint filed on May 22, 2009 by the California Attorney General against some sellers, but not including Idaho Power and IE. In August 2009, the City of Tacoma, Washington and the Port of Seattle, Washington requested the FERC, either on a summary basis or after new evidentiary hearings, to require refunds from all sellers in the Pacific Northwest spot markets for the expanded period (January 1, 2000 through June 21, 2000). Idaho Power and IE are unable to predict the outcome of these matters or estimate the impact they may have on their consolidated financial positions, results of operations or cash flows.

Sierra Club Lawsuits at the Bridger and Boardman coal fired plants in which Idaho Power has ownership interests: In February 2007, the Sierra Club and the Wyoming Outdoor Council filed a complaint against PacifiCorp in the U.S. District Court in Cheyenne, Wyoming, alleging violations of air quality opacity standards at the Jim Bridger coal-fired plant in Sweetwater County, Wyoming. Opacity is an indication of the amount of light obscured by the flue gas of a power plant. The complaint alleged thousands of opacity permit violations by PacifiCorp and sought a declaration that PacifiCorp had violated opacity limits, a permanent injunction ordering PacifiCorp to comply with such limits, civil penalties of up to $32,500 per day per violation, and reimbursement of plaintiffs’ costs of litigation, including reasonable attorneys’ fees. Idaho Power is not a party to this proceeding but has a one-third ownership interest in the plant. PacifiCorp owns a two-thirds interest in and is the operator of the plant. On February 10, 2010, PacifiCorp and plaintiffs reached an agreement in principle to the settlement of the lawsuit in its entirety. The settlement is subject to the approval of the Environmental Protection Agency and the court. If approved, the settlement will not have a material adverse effect on Idaho Power’s consolidated financial positions, results of operations or cash flows.

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

Idaho Power is unable to predict the outcome of this matter or estimate the impact it may have on its consolidated financial positions, results of operations or cash flows.

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

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

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

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

Idaho Power has also filed an action in the U.S. District Court of Federal Claims in Washington, D.C. in October, 2007 against the U.S. Bureau of Reclamation relating to a contract right for delivery of water to its hydropower projects on the Snake River to recover damages from the U.S. Bureau of Reclamation for the lost generation resulting from reduced flows and a prospective declaration of contractual rights so as to prevent the U.S. Bureau of Reclamation from continued failure to fulfill its contractual and fiduciary duties to Idaho Power. Trial of the matter has not been scheduled.

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

For further information regarding legal proceedings, see Note 10 to the consolidated financial statements.

ENVIRONMENTAL ISSUES:

Global Climate Change:

Long-term climate change could significantly affect Idaho Power’s business in a variety of ways, including the following: (i) changes in temperature and precipitation could affect customer demand, (ii) extreme weather events could increase service interruptions, outages, and maintenance costs; (iii) changes in the amount and timing of snowpack and stream flows could adversely affect hydroelectric generation, and (iv) legislative and/or regulatory developments related to climate change could affect plans and operations including placing restrictions on the construction of new generation resources, the expansion of existing resources, or the operation of generation resources in general, and (v) consumer preference for, and resource planning decisions requiring, renewable or low GHG-emitting sources of energy could impact demand from existing sources and require significant investment in new generation and transmission resources.

Greenhouse Gas Emission Reduction Goals: In September 2009, IDACORP’s and Idaho Power’s Board of Directors approved guidelines that established a goal to reduce the carbon dioxide (CO₂) emission intensity of Idaho Power’s utility operations. Idaho Power’s goal is to reduce its resource portfolio’s average CO₂ emission intensity for the 2010 through 2013 time period to a level of 10 to 15 percent below Idaho Power’s 2005 CO₂ emission intensity of 1,194 lbs CO₂/MWh.

Since Idaho Power’s CO₂ emission intensity fluctuates with stream flows and production levels of anticipated renewable resource additions, Idaho Power believes an average intensity reduction goal to be achieved over several years is appropriate. Generation from Idaho Power-owned and any renewable resources under contract for which Idaho Power has long-term rights to the Renewable Energy Credits (RECs) will be included in the denominator of this calculation. Idaho Power’s progress toward achieving this intensity reduction goal, as well as additional information on Idaho Power’s CO₂ emissions, will be reported on Idaho Power’s website. The guidelines are intended to reduce Idaho Power’s average CO₂emission intensity in a manner that minimizes the costs of those reductions to Idaho Power’s customers.

In 2006 Idaho Power’s and Ida-West ranked as one of the 30 lowest emitters of CO₂/MWh produced among the nation’s 100 largest electricity producers, according to a collaborative report from CERES, the natural Resources Defense Council, Public Service Enterprise Group and PG&E Corporation using publicly reported 2006 generation and emissions data.

In May 2009, Idaho Power submitted information to the Carbon Disclosure Project (CDP), an independent, not-for-profit organization that claims the largest database of corporate climate change information in the world. The CDP posted responding companies’ information at its website in September 2009. Idaho Power’s estimated CO₂ emission intensity (Lbs/MWh) from its generation facilities as submitted to the CDP was 1,150 and 1,097 for 2007 and 2008, respectively. Idaho Power estimates that its CO₂ emission intensity from Idaho Power-owned generation facilities for 2009 was 1,003 Lbs CO₂/MWh.

Regulation of Greenhouse Gas Emissions: The American Clean Energy and Security Act of 2009, H.R. 2454, Passed the U.S. House of Representatives on June 26, 2009. Senate Environment and Public Works Chairman Barbara Boxer (D-CA) and Senator John Kerry (D-MA) introduced a climate change bill on the Senate floor on September 30, 2009. The timeline for action on the Senate floor remains unclear and debate continues on the direction, scope and timing of federal legislation to reduce GHG emissions. There are also state and regional initiatives (including the western Regional Climate Action Initiative) considering regional market-based mechanisms to reduce GHG emissions.

Oregon enacted legislation in August 2007 establishing economy-wide goals for the reduction of greenhouse gas emissions. Oregon’s goals seek to (i) by 2010, cease the growth of Oregon greenhouse gas emission; (ii) by 2020, reduce greenhouse gas levels to 10 percent below 1990 levels; and (iii) by 2050, reduce greenhouse gas levels to at least 75 percent below 1990 levels. The legislation also calls for state government-developed policy recommendations in the future to assist in the monitoring and achievement of these goals. The impact of the enacted legislation on Idaho Power cannot be determined at this time.

On January 14, 2010, Portland General Electric announced that it intended to pursue an alternative operating plan for its Boardman power plant. Under the alternative operating plan, near-term expenditures for pollution control equipment would be significantly reduced and Boardman would either cease to operate in 2020, or it would discontinue the use of coal as a fuel source. Idaho Power is a ten percent owner of the plant, representing 64,200 kW of nameplate capacity.

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

In September 2009, the EPA issued a final rule that requires monitoring and reporting of GHG emissions by a number of entities beginning on January 1, 2010. Most facilities will be required to report annually. Electric generation facilities (including Idaho Power’s facilities) already reporting CO₂emissions under the Clean Air Act (CAA) Acid Rain Program must report CO₂, nitrous oxide and methane emissions to the EPA on a quarterly basis.

In December 2009, the EPA issued an “endangerment finding” for GHG emissions from motor vehicles which has been appealed to the U.S. Court of Appeals for the District of Columbia Circuit. The “endangerment finding” is required for the EPA and the Department of Transportation National Highway Traffic Safety Administration to finalize their September 2009 proposal to adopt national GHG emission standards for motor vehicles. On September 30, 2009, the EPA acknowledged that the CAA will require it to regulate GHG emissions from stationary sources (including Idaho Power’s thermal facilities) through both its preconstruction and operating permit programs when it finalizes its proposal to adopt national GHG emission standards for motor vehicles. Under this proposed rule, EPA is seeking to establish an applicability threshold of 25,000 tons of GHGs per year (CO₂equivalent) for such programs.

Idaho Power will continue to monitor and evaluate any proposed international, federal, state or regional GHG legislation or initiatives as well as any judicial decisions that could affect its generating facilities. The majority of current initiatives regarding GHG emissions contemplate market-based compliance programs. The regulation of GHG emissions under the CAA could result in GHG emission limits on stationary sources that do not provide market-based compliance options such as cap-and-trade programs or emission offsets. Such a program could raise uncertainty about the future viability of fossil fuels, specifically coal, as an economical energy source for new and existing electric generation facilities because new technologies for reducing CO₂ emissions from coal, including carbon capture storage, are still in the development stage and are not yet proven. At this time, however, Idaho Power is unable to estimate the costs of compliance with any such legislation or initiatives because they are in the early stages of development and final legislation, if adopted, could vary from current proposals. In the 2009 IRP, Idaho Power did not include any new conventional coal resources in the resource portfolio due to the uncertainty regarding future carbon regulations.

Renewable Portfolio Standards (RPS): The American Clean Energy and Security Act of 2009 as passed in the U.S. House of Representatives on June 26, 2009, would require utilities to obtain 20 percent of their electricity from renewable sources by 2020, and reduce demand an additional five percent through conservation and increased energy efficiency. The Senate version would require electric utilities to meet 15 percent of their electricity sales through renewable sources of energy or energy efficiency by 2021. Resources eligible to meet these standards include wind, solar, geothermal, biomass, landfill gas, ocean, and incremental hydropower (efficiency improvements or new capacity). Both bills recognize the benefits of existing hydroelectric generation by allowing utilities to subtract generation from existing hydroelectric projects from their total sales base prior to calculating the percentage requirement. Idaho Power will be required to comply with a ten percent RPS in Oregon beginning in 2025. Idaho Power expects to meet these requirements with the REC’s from the Elkhorn Valley wind project. No RPS requirement currently exists in Idaho. Idaho Power continues to monitor proposed federal RPS legislation, which if passed could increase capital expenditures and operating costs and reduce earnings and cash flows.

Idaho Power is currently purchasing energy from seven wind projects with a combined nameplate rating of 192 MW. Idaho Power also has an additional 275 MW of wind generation with signed and IPUC approved contracts that have not yet been constructed; Because of IPUC rules related to PURPA contracts and the IPUC order for Idaho Power to sell some of its near-term RECs, Idaho Power does not hold the ‘green tags’ or RECs associated with all of these projects. Idaho Power continues to pursue additional geothermal, wind, and combined heat and power (CHP) generation resources with individual developers. Other renewable generation resources anticipated from future CSPP contracts include solar, biomass, CHP and additional wind projects. For additional discussion of how Idaho Power is preparing for potential RPS requirements, see “Item 1 BUSINESS – Utility Operations – Resource Planning.”

Air Quality

Idaho Power co-owns three coal-fired power plants and owns two natural gas combustion turbine power plants that are subject to air quality regulation. The coal-fired plants are: Jim Bridger (33 percent interest) located in Wyoming; Boardman (ten percent interest) located in Oregon; and Valmy (50 percent interest) located in Nevada. The natural gas-fired plants, Danskin and Bennett Mountain, are located in Idaho. The CAA establishes controls on the emissions from stationary sources like those owned by Idaho Power. The EPA adopts many of the standards and regulations under the CAA, while states have the primary responsibility for implementation and administration of these air quality programs. In February 2010, a bill was introduced in the Senate to impose limits on SO₂ and NO_x emissions from power plants starting in 2012 and to require at least a 90 percent reduction in mercury emissions from coal-fired generation. Idaho Power continues to actively monitor, evaluate and work on air quality issues pertaining to federal and state mercury emission rules, possible legislative amendment of the CAA as discussed above, National Ambient Air Quality Standards (NAAQS), and Regional Haze – Best Available Retrofit Technology (RH BART) and New Source Review (NSR) permitting.

Mercury Emissions: Mercury continuous emission monitoring systems have been installed on all of the coal-fired units at the Jim Bridger, Boardman and Valmy plants and tests to confirm the accuracy of the data being collected are currently underway. The EPA has announced that it is developing maximum achievable control technology standards to reduce mercury emissions from coal-fired power plants. In 2008, the State of Oregon adopted a mercury rule requiring Boardman to reduce mercury emissions by 90 percent or meet an emission rate of 0.6 lbs/trillion BTU by July 2012. The state is now considering allowing up to a two year extension. Idaho Power continues to monitor Wyoming and Nevada actions related to mercury emissions. Idaho Power is unable to predict at this time what actions the EPA or the other states may take to reduce mercury emissions from its coal-fired power plants.

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

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

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

On January 22, 2010, the EPA adopted a new NAAQS for NO₂ at a level of 100 parts per billion averaged over a 1-hour period. The EPA has not yet designated areas as attaining or not attaining the new NAAQS. In addition, on November 16, 2009, the EPA proposed a more stringent NAAQS for SO₂ to a level between 50 and 100 parts per billion averaged over a 1-hour period. Idaho Power is unable to predict what impact the adoption and implementation of these standards may have on its operations.

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

PacifiCorp submitted an RH BART application for the Jim Bridger plant in January 2007. On June 3, 2009, WDEQ issued a public notice requesting comment from the public on the draft RH BART State Implementation Plan (SIP) arising out of the application. WDEQ has proposed to issue an RH BART air quality permit for modification of Bridger requiring installation of low-NO_x burners with separated over-fire air for NO_xreduction, and flue gas conditioning to enhance performance of the electrostatic precipitator particulate controls. According to WDEQ, these controls will allow Bridger to meet the EPA’s presumptive RH BART emission limits. The plant is already in the process of installing low NO_x burners and SO₂ scrubber upgrades that are proposed in the application. The SO₂ scrubber upgrade project has been completed on Units 2 and 4 and is expected to be completed on the other two units by the end of 2011. Idaho Power expects to spend approximately $22 million between 2009 and 2012 to complete these projects. WDEQ is further proposing to require Bridger Units 3 and 4 to be equipped with selective catalytic reduction (SCR) NO_x controls before December 31, 2015 and December 31, 2016, respectively. WDEQ is requiring installation of the two SCR units as part of its long-term strategy in the regional haze SIP. Idaho Power’s estimated share of the cost to install the two SCRs is $120 million. Installation of this SCR pollution control equipment could require extended maintenance outages. In addition, WDEQ has proposed to require PacifiCorp to submit an application by January 15, 2015, to install add-on NO_x controls at Bridger Units 1 and 2 by December 31, 2023. Design and cost estimates for meeting this proposed requirement are not yet available. The comment period on the draft RH BART SIP ended on August 4, 2009. WDEQ will finalize the SIP and submit it to the EPA for approval. Legal challenges or appeals of the final SIP are possible. Idaho Power will continue to monitor this process.

In August 2008, the ODEQ issued a draft RH BART proposal for the Boardman plant. The RH BART proposal was approved by the Oregon Environmental Quality Commission in June 2009. The pollution control requirements for RH BART and the long-term strategy are estimated to cost between approximately $52 million and $56 million (Idaho Power share) based upon current market conditions for air quality control equipment. Approximately three-quarters of the costs will be incurred by 2014 with the remainder incurred by 2017. Installation of this pollution control equipment could require extended maintenance outages. On January 14, 2010, PGE announced that it intended to pursue an alternative operating plan for its Boardman plant. Under the alternative operating plan, near-term expenditures for pollution control equipment would be significantly reduced and Boardman would either cease to operate in 2020, or it would discontinue the use of coal as a fuel source. Idaho Power does not yet know what impact this decision will have on the ODEQ proposal.

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

New Source Review: Since 1999, the EPA and the U.S. Department of Justice have been pursuing a national enforcement initiative focused on the compliance status of coal-fired power plants with the New Source Review (NSR) permitting requirements and New Source Performance Standards (NSPS) of the CAA. This initiative has resulted in both enforcement litigation and significant settlements with a large number of public utilities and other owners of coal-fired power plants across the country. The administration has indicated an intention to continue this NSR enforcement initiative. The EPA sent information requests under section 114 of the CAA, requesting information relevant to NSR and NSPS compliance to the Jim Bridger plant in 2003, the Valmy plant in 2009 and the Boardman plant in 2008 with a follow up request for information in 2009. Idaho Power is a co-owner of these plants, but does not operate the plants. A number of utilities that have received section 114 information requests have engaged in negotiations with the EPA to address any allegations of non-compliance with NSR and NSPS requirements. In some cases, such negotiations have resulted in settlements requiring the payment of civil penalties, installation of additional pollution controls, the surrender of emission allowances, and the completion of supplemental environmental projects. Idaho Power cannot predict the outcome of these investigatory matters at this time.

The EPA has announced its intention to propose new regulations pursuant to the Resource Conservation and Recovery Act governing the management and storage of coal ash waste, and to determine whether to designate coal ash as a hazardous waste.

Endangered Species:

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

Sage Grouse: The sage grouse has been proposed for listing under the ESA. If the sage grouse is listed, this will add an additional requirement and species for consideration in ESA section 7 consultations for the Gateway West and Boardman to Hemingway 500-kV transmission lines and the Langley Gulch transmission and water lines and winter habitat may impact the expense and timing for these projects.

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

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

CRITICAL ACCOUNTING POLICIES AND ESTIMATES:

When preparing financial statements in accordance with generally accepted accounting principles (GAAP), IDACORP’s and Idaho Power’s management must apply accounting policies and make estimates that affect the reported amounts of assets, liabilities, revenues and expenses and related disclosure of contingent assets and liabilities. These estimates often involve judgment about factors that are difficult to predict and are beyond management’s control. Management adjusts these estimates based on historical experience and on other assumptions and factors that are believed to be reasonable under the circumstances. Actual amounts could materially differ from the estimates.

Management believes the following accounting policies and estimates are the most critical to the portrayal of their financial condition and results of operations and require management’s most difficult, subjective or complex judgments, often as a result of the need to make estimates about the effect of matters that are inherently uncertain and may change in subsequent periods.

Accounting for Rate Regulation

GAAP requires entities that meet specific conditions to reflect the impact of regulatory decisions in their consolidated financial statements and requires that certain costs be deferred as regulatory assets until matching revenues can be recognized. Similarly, certain items may be deferred as regulatory liabilities. Idaho Power must satisfy the following conditions to apply regulatory accounting: (1) an independent regulator must set rates; (2) the regulator must set the rates to cover specific costs of delivering service; and (3) the service territory must lack competitive pressures to reduce rates below the rates set by the regulator.

Idaho Power’s has determined that it meets these conditions and its financial statements reflect the effects of the different rate making principles followed by the jurisdictions regulating Idaho Power. The primary effect of this policy is that Idaho Power has recorded $721 million of regulatory assets and $297 million of regulatory liabilities at December 31, 2009. Idaho Power expects to recover these regulatory assets from customers through rates and refund these regulatory liabilities to customers through rates, but recovery or refund is subject to final review by the regulatory bodies. If future recovery or refund of these amounts ceases to be probable, or if Idaho Power determines that it no longer meets the criteria for applying regulatory accounting, Idaho Power would be required to eliminate those regulatory assets or liabilities, unless regulators specify some other means of recovery or refund. Either circumstance could have a material effect on Idaho Power’s results of operations and financial position.

Asset Impairment

Available-for-sale securities: Idaho Power has investments in four mutual funds that experienced a significant decline in fair value in 2008. Idaho Power is required to evaluate these and other securities periodically to determine whether a decline in fair value is other than temporary. If the decline in fair value is other than temporary, the cost of the investment is written down to fair value and the loss is recorded as a realized loss. Two significant factors that are considered when evaluating investments for impairment are the length of time and the extent to which the market value has been less than cost. Idaho Power’s investments had lost between 32 percent and 43 percent of their value, primarily during the stock market downturn in September and October 2008 and had been in loss positions from six to 12 months at December 31, 2008. Because of the severity of the declines in value, Idaho Power determined that the loss in value was other-than-temporary and recorded a pre-tax loss of $6.8 million in the fourth quarter of 2008. At December 31, 2009, the fair value of these investments was above their new cost basis and no impairment was recorded.

Equity-Method Investments: IFS has affordable housing investments with a net book value of $78 million at December 31, 2009, and Ida-West has investments in four joint ventures that own electric power generation facilities. Except for one investment which is consolidated, these investments are accounted for under the equity method of accounting. The standard for determining whether impairment must be recorded for these investments is whether the investment has experienced a loss in value that is considered an other-than-temporary decline in value. Impairment analyses on these investments were performed in 2009 and an immaterial impairment was recorded on one of the Ida-West joint ventures. These estimates required IDACORP to make assumptions about future stream flows, revenues, cash flows and other items that are inherently uncertain. Actual results could vary significantly from the assumptions used, and the impact of such variations could be material.

Pension and Other Postretirement Benefits

Idaho Power maintains a qualified defined benefit pension plan covering most employees, an unfunded nonqualified deferred compensation plan for certain senior management employees and directors called the Senior Management Security Plan (SMSP), and a postretirement medical benefit plan.

The costs IDACORP and Idaho Power record for these plans depend on the provisions of the plans, changing employee demographics, actual returns on plan assets and several assumptions used in the actuarial valuations from which the expense is derived. The key actuarial assumptions that affect expense are the expected long-term return on plan assets and the discount rate used in determining future benefit obligations. Management evaluates the actuarial assumptions on an annual basis, taking into account changes in market conditions, trends and future expectations. Estimates of future stock market performance, changes in interest rates and other factors used to develop the actuarial assumptions are uncertain. Actual results could vary significantly from the estimates.

The assumed discount rate is based on reviews of market yields on high-quality corporate debt. Specifically, IDACORP and Idaho Power utilize data published in the Citigroup Pension Liability Index and apply the rates therein against the projected cash outflows of the plans. The discount rate used to calculate the 2010 pension expense will be decreased to 5.9 percent from the 6.1 percent used in 2009.

Rate-of-return projections for plan assets are based on historical risk/return relationships among asset classes. The primary measure is the historical risk premium each asset class has delivered versus the return on 10-year U.S. Treasury Notes. This historical risk premium is then added to the current yield on 10-year U.S. Treasury Notes, and the result provides a reasonable prediction of future investment performance. Additional analysis is performed to measure the expected range of returns, as well as worst-case and best-case scenarios. Based on the current interest rate environment, current rate-of-return expectations are lower than the nominal returns generated over the past 20 years when interest rates were generally much higher.

Gross pension and other postretirement benefit expense for these plans totaled $40 million, $16 million, and $15 million for the three years ended December 31, 2009, 2008 and 2007, respectively, including amounts allocated to capitalized labor and amounts deferred as regulatory assets. For 2010, gross pension and other postretirement benefit costs are expected to total approximately $41 million, which takes into account the change in the discount rate noted above, as well as a decrease in expected return on plan assets. No changes were made to the other key assumptions used in the actuarial calculation.

Had different actuarial assumptions been used, pension expense could have varied significantly. The following table reflects the sensitivities associated with changes in the discount rate and rate-of-return on plan assets actuarial assumptions on historical and future pension and postretirement expense:

	Discount rate				Rate of return
	2010		2009		2010		2009
	(millions of dollars)
Effect of 0.5% increase	$	(4.1)	$	(3.8)	$	(1.7)	$	(1.5)
Effect of 0.5% decrease		4.5		4.1		1.7		1.5

No cash contributions were required or made to the qualified plan in 2007 or 2008. A $6 million contribution for 2009 is due in calendar year 2010, and estimated payments of $44 million, $47 million, $39 million, and $40 million are due in 2011, 2012, 2013, and 2014, respectively. Under the SMSP, Idaho Power makes payments directly to participants in the plan. Benefit payments are expected to be $3.3 million in 2010 and averaged $2.8 million per year from 2007 to 2009. Gross postretirement plan contributions are expected to be $4.2 million in 2010, and averaged $5.2 million from 2007 to 2009.

The IPUC has authorized Idaho Power to account for its defined benefit pension expense on a cash basis, and to defer and account for accrued pension expense as a regulatory asset. The IPUC acknowledged that it is appropriate for Idaho Power to seek recovery in its revenue requirement of reasonable and prudently incurred pension expense based on actual cash contributions. Idaho Power began deferring pension expense to a regulatory asset account to be matched with revenue when future pension contributions are recovered through rates. The deferral of pension expense began in 2007. At December 31, 2009, $38 million of expense was deferred as a regulatory asset. Approximately $30 million is expected to be deferred in 2010.

Please refer to Note 11 of the consolidated financial statements, which contains additional information about the pension and postretirement plans.

Contingent Liabilities

An estimated loss from a loss contingency is charged to income if (a) it is probable that a liability had been incurred at the date of the financial statements and (b) the amount of the loss can be reasonably estimated. If a probable loss cannot be reasonably estimated, no accrual is recorded but disclosure of the contingency in the notes to the financial statements is required. Gain contingencies are not recorded until realized.

IDACORP and Idaho Power have a number of unresolved issues related to regulatory and legal matters. If the recognition criteria have been met, liabilities have been recorded. Estimates of this nature are highly subjective and the final outcome of these matters could vary significantly from the amounts that have been included in the financial statements.

Income Taxes

IDACORP and Idaho Power use judgment and estimation in developing the provision for income taxes and the reporting of tax-related assets and liabilities. The interpretation of tax laws can involve uncertainty, since tax authorities may interpret such laws differently. Actual income taxes could vary from estimated amounts and may result in favorable or unfavorable impacts to net income, cash flows, and tax-related assets and liabilities.

RECENTLY ISSUED ACCOUNTING PRONOUNCEMENTS

See Note 1 to the consolidated financial statements for a discussion of recently issued accounting pronouncements.

INFLATION

IDACORP and Idaho Power believe that inflation has caused and may continue to cause increases in certain operating expenses and the replacement of assets at higher costs. Inflation affects the cost of labor, products and services required for operations and maintenance and capital expenditures. While inflation has not had a significant impact on IDACORP’s or Idaho Power’s operations, increases in utility expenses due to inflation could have an adverse effect on earnings because of the need to obtain regulatory approval to recover such increased expenses.

ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

IDACORP and Idaho Power are exposed to market risks, including changes in interest rates, changes in commodity prices, credit risk and equity price risk. The following discussion summarizes these risks and the financial instruments, derivative instruments and derivative commodity instruments sensitive to changes in interest rates, commodity prices and equity prices that were held at December 31, 2009.

Interest Rate Risk

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

Variable Rate Debt: As of December 31, 2009, IDACORP and Idaho Power had $43 million and $5 million, respectively, in floating rate debt net of temporary cash investments. Assuming no change in financial structure for either company, if variable interest rates were one percentage point higher than the rates in effect on December 31, 2009, interest rate expense would increase and pre-tax earnings would decrease by approximately $0.4 million for IDACORP and $0.1 million for Idaho Power.

Fixed Rate Debt: As of December 31, 2009, IDACORP and Idaho Power each had $1.4 billion in fixed rate debt, with a fair market value also equal to $1.4 billion. These instruments are fixed rate and, therefore, do not expose the companies to a loss in earnings due to changes in market interest rates. However, the fair value of these instruments would increase by approximately $131 million for both IDACORP and Idaho Power if interest rates were to decline by one percentage point from their December 31, 2009 levels.

Commodity Price Risk

Utility: Idaho Power’s exposure to changes in commodity price is related to its ongoing utility operations producing electricity to meet the demand of its retail electric customers. The weather is a major uncontrollable factor affecting the local and regional demand for electricity and the availability and cost of production. The objective of Idaho Power’s energy purchase and sale activity is to meet the demand of retail electric customers, maintain appropriate physical reserves to ensure reliability, and make economic use of temporary surpluses that may develop.

Idaho Power’s exposure to commodity price risk is largely offset by the previously discussed power cost adjustment mechanisms in Idaho and Oregon. Idaho Power has adopted a risk management program designed to reduce exposure to power supply cost-related uncertainty, further mitigating commodity price risk. This program has been reviewed and accepted by the IPUC. Idaho Power’s Energy Risk Management Policy (the Policy) describes a collaborative process with customers and regulators via a committee called the Customer Advisory Group (CAG). The Risk Management Committee (RMC), comprised of selected Idaho Power officers and other senior staff, oversees the risk management program. The RMC is responsible for communicating the status of risk management activities to the Idaho Power Board of Directors, and to the CAG.

The Policy requires monitoring monthly volumetric electricity position and total monthly dollar (net power supply cost) exposure on a rolling 18-month forward view. The Power Supply business unit produces and evaluates projections of the operating plan and orders risk mitigating actions dictated by the limits stated in the Policy. The RMC evaluates the actions initiated by Power Supply for consistency and compliance with the Policy. Idaho Power representatives meet with the CAG at least annually to assess effectiveness of the limits. Changes to the limits can be endorsed by the CAG and referred to the Board of Directors for approval. The primary tools for risk mitigation are physical and financial forward power transactions and fueling alternatives for utility-owned generation resources.

Credit Risk

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

The use of performance assurance collateral in the form of cash, letters of credit, or guarantees is common industry practice. Idaho Power maintains margin agreements that allow performance assurance collateral to be requested and/or posted with certain counterparties. As of December 31, 2009, Idaho Power had posted approximately $1.3 million of assurance collateral. Should Idaho Power experience a reduction in its credit rating on Idaho Power’s unsecured debt to below investment grade, Idaho Power could be subject to additional requests by its wholesale counterparties to post additional performance assurance collateral. Counterparties to derivative instruments could request immediate payment or demand immediate ongoing full daily collateralization on derivative instruments in net liability positions. Based upon Idaho Power’s current energy and fuel portfolio and current market conditions as of December 31, 2009, the approximate amount of additional collateral that could be requested upon a downgrade is approximately $16 million. Idaho Power actively monitors the portfolio exposure and the potential exposure to additional requests for performance assurance collateral calls, through sensitivity analysis, to minimize capital requirements.

Credit risk for Idaho Power’s retail customers is managed by credit and collection policies that are governed by rules issued by the IPUC. Idaho Power is obligated to provide service to all electric customers within its service area. Idaho Power records a provision for uncollectible accounts, based upon historical experience, to provide for the potential loss from nonpayment by these customers. Idaho Power will continue to monitor the impact of the current economic conditions on nonpayment from customers and will make any necessary adjustments to its provision for uncollectible accounts.

Idaho administrative code for utility customer relations rules prohibits Idaho Power from terminating electric service during the months of December through February to any residential customer who declares that he or she is unable to pay in full for utility service and whose household includes children, elderly or infirm persons. Idaho Power’s provision for uncollectible accounts could be affected by changes in future prices as well as changes in IPUC regulations.

Equity Price Risk

IDACORP and Idaho Power are exposed to price fluctuations in equity markets, primarily through their pension plan assets, a mine reclamation trust fund owned by an equity-method investment of Idaho Power and other equity investments at Idaho Power. As a result of market increases in 2009, the fair value of the pension plan’s assets increased; however, increases in the benefit obligation were greater than the increases in the pension plan’s assets, therefore resulting in an increase in future amounts required to be contributed to the plan. Based on current laws, Idaho Power estimates that the minimum contribution to Idaho Power’s pension plan in 2010 will be $5.8 million.

A hypothetical ten percent decrease in equity prices would result in an approximate $1.9 million decrease in the fair value of financial instruments that are classified as available-for-sale securities.

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

INDEX TO FINANCIAL STATEMENTS AND FINANCIAL STATEMENT SCHEDULES

		PAGE
Consolidated Financial Statements:

IDACORP, Inc.
Consolidated Statements of Income for the Years Ended December 31, 2009, 2008 and 2007		64
Consolidated Balance Sheets as of December 31, 2009 and 2008		65-66
Consolidated Statements of Cash Flows for the Years Ended December 31, 2009, 2008 and 2007		67
Consolidated Statements of Equity for the Years Ended December 31, 2009, 2008
	and 2007	68
Consolidated Statements of Comprehensive Income for the Years Ended December 31, 2009,
	2008 and 2007	69

Idaho Power Company
Consolidated Statements of Income for the Years Ended December 31, 2009, 2008 and 2007		70
Consolidated Balance Sheets as of December 31, 2009 and 2008		71-72
Consolidated Statements of Capitalization as of December 31, 2009 and 2008		73
Consolidated Statements of Cash Flows for the Years Ended December 31, 2009, 2008 and 2007		74
Consolidated Statements of Retained Earnings for the Years Ended December 31, 2009, 2008
	and 2007	75
Consolidated Statements of Comprehensive Income for the Years Ended December 31, 2009,
	2008 and 2007	75

Notes to the Consolidated Financial Statements		76-118
Reports of Independent Registered Public Accounting Firm		119-120


Supplemental Financial Information and Consolidated Financial Statement Schedules

Supplemental Financial Information (Unaudited)		121

Financial Statement Schedules for the Years Ended December 31, 2009, 2008 and 2007:
Schedule I - Condensed Financial Information of Registrant-IDACORP, Inc.		137-139
Schedule II-Consolidated Valuation and Qualifying Accounts-IDACORP, Inc.		140
Schedule II-Consolidated Valuation and Qualifying Accounts-Idaho Power Company		141

IDACORP, Inc.

Consolidated Statements of Income

		Year Ended December 31,
		2009		2008		2007
		(thousands of dollars except
		for per share amounts)
Operating Revenues:
Electric utility:
General business		$	883,765	$	784,311	$	668,303
Off-system sales		94,373		121,429		154,948
Other revenues		67,858		50,336		52,150
Total electric utility revenues		1,045,996		956,076		875,401
Other		3,804		4,338		3,993
Total operating revenues		1,049,800		960,414		879,394
Operating Expenses:
Electric utility:
Purchased power		160,569		231,137		289,484
Fuel expense		149,566		149,403		134,322
Third-party transmission expense		6,629		7,250		10,470
Power cost adjustment		66,710		(47,413)		(121,131)
Other operations and maintenance		293,111		286,779		276,040
Energy efficiency programs		31,821		18,880		13,487
Gain on sale of emission allowances		(298)		(504)		(2,754)
Depreciation		110,626		102,086		103,072
Taxes other than income taxes		21,069		19,083		17,634
Total electric utility expenses		839,803		766,701		720,624
Other expense		6,414		3,046		6,692
Total operating expenses		846,217		769,747		727,316
Operating Income (Loss):
Electric utility		206,193		189,375		154,777
Other		(2,610)		1,292		(2,699)
Total operating income		203,583		190,667		152,078
Other Income		21,064		11,861		20,524
Losses of Unconsolidated Equity-Method Investments		(1,033)		(3,997)		(4,824)
Other Expense		4,067		8,030		8,903
Interest Expense:
Interest on long-term debt		73,371		67,251		59,961
Other interest expense, net of AFUDC		(561)		5,805		3,380
Total interest expense		72,810		73,056		63,341
Income Before Income Taxes		146,737		117,445		95,534
Income Tax Expense		22,362		19,200		13,731
Income from Continuing Operations		124,375		98,245		81,803
Income from Discontinued Operations, attributable to
	IDACORP, Inc., net of tax	-		-		67
Net Income		124,375		98,245		81,870
Adjustment for (income) loss attributable to noncontrolling interests		(25)		169		469
Net Income Attributable to IDACORP, Inc.		$	124,350	$	98,414	$	82,339
Weighted Average Common Shares Outstanding - Basic (000’s)		47,124		45,268		44,291
Weighted Average Common Shares Outstanding - Diluted (000’s)		47,182		45,379		44,365
Earnings Per Share of Common Stock (basic and diluted):
Earnings Attributable to IDACORP, Inc. Continuing Operations		$	2.64	$	2.17	$	1.86
Earnings Attributable to IDACORP, Inc. Discontinued Operations		-		-		-
Earnings Attributable to IDACORP Inc.		$	2.64	$	2.17	$	1.86
Dividends Paid Per Share of Common Stock		$	1.20	$	1.20	$	1.20

The accompanying notes are an integral part of these statements.

IDACORP, Inc.

Consolidated Balance Sheets

	December 31,
	2009		2008
Assets	(thousands of dollars)

Current Assets:
Cash and cash equivalents	$	52,987	$	8,828
Receivables:
Customer	76,792		64,733
Other	12,995		10,439
Allowance for uncollectible accounts	(2,878)		(1,724)
Taxes receivable	-		18,111
Accrued unbilled revenues	51,272		43,934
Materials and supplies (at average cost)	48,054		50,121
Fuel stock (at average cost)	25,634		16,852
Prepayments	11,111		10,059
Deferred income taxes	31,773		37,550
Other	2,666		7,381
Total current assets	310,406		266,284

Investments	195,298		198,552

Property, Plant and Equipment:
Utility plant in service	4,160,178		4,030,134
Accumulated provision for depreciation	(1,558,538)		(1,505,120)
Utility plant in service - net	2,601,640		2,525,014
Construction work in progress	289,188		207,662
Utility plant held for future use	7,151		6,318
Other property, net of accumulated depreciation	19,029		19,171
Property, plant and equipment - net	2,917,008		2,758,165

Other Assets:
American Falls and Milner water rights	24,226		26,332
Company-owned life insurance	26,654		29,482
Regulatory assets	720,401		696,332
Long-term receivables (net of allowance of $2,157 and $2,478, respectively)	4,217		4,012
Other	40,517		43,686
Total other assets	816,015		799,844

Total	$	4,238,727	$	4,022,845

The accompanying notes are an integral part of these statements.

IDACORP, Inc.

Consolidated Balance Sheets

	December 31,
	2009		2008
Liabilities and Equity	(thousands of dollars)

Current Liabilities:
Current maturities of long-term debt	$	9,340	$	86,528
Notes payable	53,750		151,250
Accounts payable	83,818		96,785
Taxes accrued	10,184		-
Interest accrued	20,056		16,727
Other	41,081		44,378
Total current liabilities	218,229		395,668

Other Liabilities:
Deferred income taxes	574,450		515,719
Regulatory liabilities	287,780		276,266
Other	346,994		344,870
Total other liabilities	1,209,224		1,136,855

Long-Term Debt	1,409,730		1,183,451

Commitments and Contingencies

Equity:
IDACORP, Inc. shareholders’ equity:
Common stock, no par value (shares authorized 120,000,000;
47,925,882 and 46,929,203 shares issued, respectively)	756,475		729,576
Retained earnings	649,180		581,605
Accumulated other comprehensive loss	(8,267)		(8,707)
Treasury stock (29,191 and 9,022 shares at cost, respectively)	(53)		(37)
Total IDACORP, Inc. shareholders’ equity	1,397,335		1,302,437
Noncontrolling interest	4,209		4,434
Total equity	1,401,544		1,306,871

Total	$	4,238,727	$	4,022,845

The accompanying notes are an integral part of these statements.

IDACORP, Inc.

Consolidated Statements of Cash Flows

	Year Ended December 31,
	2009		2008		2007
Operating Activities:	(thousands of dollars)
Net income	$	124,375	$	98,245	$	81,870
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization	118,600		109,842		108,171
Deferred income taxes and investment tax credits	19,035		4,661		11,026
Changes in regulatory assets and liabilities	57,836		(64,068)		(128,089)
Non-cash pension expense	4,025		3,513		6,868
Losses of equity method investments	1,033		3,997		4,824
Distributions from equity method investments	12,477		1,178		1,100
Gain on sale of assets	(426)		(3,446)		(4,758)
Other non-cash adjustments to net income, net	3,078		8,859		(2,983)
Change in:
Accounts receivable and prepayments	(15,749)		(1,725)		(10,284)
Accounts payable and other accrued liabilities	(28,038)		16,248		2,206
Taxes receivable (accrued)	28,535		(26,454)		(9,466)
Other current assets	(14,053)		(14,056)		(11,159)
Other current liabilities	(7,485)		(6,130)		15,551
Other assets	1,621		1,498		2,157
Other liabilities	(20,439)		4,351		13,567
Net cash provided by operating activities	284,425		136,513		80,601
Investing Activities:
Additions to property, plant and equipment	(251,937)		(243,544)		(287,219)
Proceeds from the sale IDACOMM	-		-		7,283
Proceeds from the sale of non-utility assets	2,250		5,847		-
Investments in affordable housing	(5,802)		(8,314)		-
Proceeds from the sale of emission allowances	2,382		2,959		19,846
Investments in unconsolidated affiliates	-		(3,038)		(8,535)
Purchase of available-for-sale securities	-		-		(24,349)
Proceeds from the sale of available-for-sale securities	9,006		-		26,110
Purchase of held-to-maturity securities	-		(4,248)		(3,116)
Maturity of held-to-maturity securities	425		6,060		3,317
Withdrawal of refundable deposit for tax related liabilities	-		44,903		-
Other	1,271		(3,449)		(447)
Net cash used in investing activities	(242,405)		(202,824)		(267,110)
Financing Activities:
(Decrease) increase in term loans	(170,000)		170,000		-
Issuance of long-term debt	230,000		120,000		240,000
Remarketing (purchase) of pollution control revenue bonds	166,100		(166,100)		-
Retirement of long-term debt	(89,174)		(11,349)		(95,033)
Dividends on common stock	(56,820)		(54,239)		(53,012)
Net change in short-term borrowings	(93,600)		(39,095)		57,445
Issuance of common stock	24,328		50,863		37,181
Acquisition of treasury stock	(1,441)		(304)		(346)
Other	(7,254)		(2,603)		(1,652)
Net cash provided by financing activities	2,139		67,173		184,583
Net increase (decrease) in cash and cash equivalents	44,159		862		(1,926)
Cash and cash equivalents at beginning of the year	8,828		7,966		9,892
Cash and cash equivalents at end of the year	$	52,987	$	8,828	$	7,966
Supplemental Disclosure of Cash Flow Information:
Cash paid during the year for:
Income taxes (refunded) paid	$	(21,401)	$	20,407	$	3,021
Interest (net of amount capitalized)	$	67,039	$	67,027	$	62,031
Non-cash investing activities
Additions to property, plant and equipment in accounts payable	$	19,075	$	14,194	$	13,210
Investments in affordable housing	$	8,276	$	-	$	-

The accompanying notes are an integral part of these statements.

IDACORP, Inc.

Consolidated Statements of Equity

	Year Ended December 31,
	2009		2008		2007
	(thousands of dollars)
Common Stock
Balance at beginning of year	$	729,576	$	675,774	$	638,799
Issued	24,328		50,863		37,181
Other	2,571		2,939		(206)
Balance at end of year	756,475		729,576		675,774

Retained Earnings
Balance at beginning of year	581,605		537,699		493,363
Net Income Attributable to IDACORP, Inc.	124,350		98,414		82,339
Common stock dividends ($1.20 per share)	(56,776)		(54,508)		(53,138)
Adjustment upon adoption of ASC 740	-		-		15,136
Other	1		-		(1)
Balance at end of year	649,180		581,605		537,699

Accumulated Other Comprehensive Income (Loss)
Balance at beginning of year	(8,707)		(6,156)		(5,737)
Unrealized gain (loss) on securities (net of tax)	1,820		(568)		(743)
Unfunded pension liability adjustment (net of tax)	(1,380)		(1,983)		324
Balance at end of year	(8,267)		(8,707)		(6,156)

Treasury Stock
Balance at beginning of year	(37)		(2)		(2,242)
Issued	1,425		99		330
Acquired	(1,441)		(304)		(346)
Other	-		170		2,256
Balance at end of year	(53)		(37)		(2)
Total IDACORP, Inc. shareholders’ equity at end of year	1,397,335		1,302,437		1,207,315

Noncontrolling interests
Balance at beginning of year	4,434		4,478		5,062
Net Income (Loss) attributed to noncontrolling interest	25		(169)		(469)
Other	(250)		125		(115)
Balance at end of year	4,209		4,434		4,478
Total equity at end of year	$	1,401,544	$	1,306,871	$	1,211,793

The accompanying notes are an integral part of these statements.

IDACORP, Inc.

Consolidated Statements of Comprehensive Income

		Year Ended December 31,
		2009		2008		2007
		(thousands of dollars)

Net Income		$	124,375	$	98,245	$	81,870

Other Comprehensive Income (Loss):
Unrealized gains (losses) on securities:
Net unrealized holding gains (losses) arising during the period,
net of tax of $1,169, ($3,034) and $114		1,820		(4,727)		179
Reclassification adjustment for losses (gains) included
in net income, net of tax of $0, $2,670 and ($592)		-		4,159		(922)
Net unrealized gains (losses)		1,820		(568)		(743)
Unfunded pension liability adjustment, net of tax
of ($885), ($1,273) and $208		(1,380)		(1,983)		324
Total Comprehensive Income		124,815		95,694		81,451
Comprehensive (income) loss attributable to noncontrolling interests		(25)		169		469
Comprehensive Income attributable to IDACORP, Inc. common
	shareholders	$	124,790	$	95,863	$	81,920

The accompanying notes are an integral part of these statements.

Idaho Power Company

Consolidated Statements of Income

	Year Ended December 31,
	2009		2008		2007
	(thousands of dollars)
Operating Revenues:
General business	$	883,765	$	784,311	$	668,303
Off-system sales	94,373		121,429		154,948
Other revenues	67,858		50,336		52,150
Total operating revenues	1,045,996		956,076		875,401

Operating Expenses:
Operation:
Purchased power	160,569		231,137		289,484
Fuel expense	149,566		149,403		134,322
Third-party transmission expense	6,629		7,250		10,470
Power cost adjustment	66,710		(47,413)		(121,131)
Other	223,652		218,140		207,877
Energy efficiency programs	31,821		18,880		13,487
Gain on sale of emission allowances	(298)		(504)		(2,754)
Maintenance	69,459		68,639		68,163
Depreciation	110,626		102,086		103,072
Taxes other than income taxes	21,069		19,083		17,634
Total operating expenses	839,803		766,701		720,624

Income from Operations	206,193		189,375		154,777

Other Income (Expense):
Allowance for equity funds used during construction	7,555		3,141		5,995
Earnings of unconsolidated equity-method investments	8,256		6,772		5,553
Other income	13,020		8,174		12,636
Other expense	(5,012)		(6,262)		(8,215)
Total other income	23,819		11,825		15,969

Interest Charges:
Interest on long-term debt	73,270		66,145		58,097
Other interest	4,060		10,420		8,281
Allowance for borrowed funds used during construction	(5,398)		(7,080)		(7,597)
Total interest charges	71,932		69,485		58,781

Income Before Income Taxes	158,080		131,715		111,965

Income Tax Expense	35,521		37,600		35,386

Net Income	$	122,559	$	94,115	$	76,579

The accompanying notes are an integral part of these statements.

Idaho Power Company

Consolidated Balance Sheets

	December 31,
	2009		2008
Assets	(thousands of dollars)

Electric Plant:
In service (at original cost)	$	4,160,178	$	4,030,134
Accumulated provision for depreciation	(1,558,538)		(1,505,120)
In service - net	2,601,640		2,525,014
Construction work in progress	289,188		207,662
Held for future use	7,151		6,318
Electric plant - net	2,897,979		2,738,994

Investments and Other Property	108,299		106,057

Current Assets:
Cash and cash equivalents	21,625		3,141
Receivables:
Customer	76,792		64,433
Other	10,648		7,947
Allowance for uncollectible accounts	(1,990)		(1,724)
Taxes receivable	3,585		41,363
Accrued unbilled revenues	51,272		43,934
Materials and supplies (at average cost)	48,054		50,121
Fuel stock (at average cost)	25,634		16,852
Prepayments	10,960		9,865
Deferred income taxes	7,887		3,852
Other	2,115		4,968
Total current assets	256,582		244,752

Deferred Debits:
American Falls and Milner water rights	24,226		26,332
Company-owned life insurance	26,654		29,482
Regulatory assets	720,401		696,332
Other	39,249		42,907
Total deferred debits	810,530		795,053

Total	$	4,073,390	$	3,884,856

The accompanying notes are an integral part of these statements.

Idaho Power Company

Consolidated Balance Sheets

	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	547,695		482,047
Accumulated other comprehensive loss	(8,267)		(8,707)
Total common stock equity	1,273,966		1,187,878

Long-term debt	1,409,730		1,180,691
Total capitalization	2,683,696		2,368,569

Current Liabilities:
Long-term debt due within one year	1,064		81,064
Notes payable	-		112,850
Accounts payable	83,128		96,268
Notes and accounts payable to related parties	1,736		768
Interest accrued	20,056		16,675
Other	40,002		43,274
Total current liabilities	145,986		350,899

Deferred Credits:
Deferred income taxes	611,749		547,159
Regulatory liabilities	287,780		276,266
Other	344,179		341,963
Total deferred credits	1,243,708		1,165,388

Commitments and Contingencies

Total	$	4,073,390	$	3,884,856

The accompanying notes are an integral part of these statements.

Idaho Power Company

Consolidated Statements of Capitalization

	December 31,			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	547,695			482,047
Accumulated other comprehensive loss	(8,267)			(8,707)
Total common stock equity	1,273,966		47	1,187,878		50
Long-Term Debt:
First mortgage bonds:
7.20% Series due 2009	-			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			-
4.50% Series due 2020	130,000			-
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	1,215,000			1,065,000
Amount due within one year	-			(80,000)
Net first mortgage bonds	1,215,000			985,000
Pollution control revenue bonds:
5.15% Series due 2024	49,800			-
5.25% Series due 2026	116,300			-
Variable Rate Series 2003 due 2024	-			49,800
Variable Rate Series 2006 due 2026	-			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	(3,060)			(3,163)
Term Loan Credit Facility	-			166,100
Purchase of pollution control revenue bonds	-			(166,100)
Total long-term debt	1,409,730		53	1,180,691		50
Total Capitalization	$	2,683,696	100	$	2,368,569	100

The accompanying notes are an integral part of these statements.

Idaho Power Company

Consolidated Statements of Cash Flows

	Year Ended December 31,
	2009		2008		2007
	(thousands of dollars)
Operating Activities:
Net income	$	122,559	$	94,115	$	76,579
Adjustments to reconcile net income to net cash provided by
operating activities:
Depreciation and amortization	117,878		109,047		107,500
Deferred income taxes and investment tax credits	15,082		25,614		36,258
Changes in regulatory assets and liabilities	57,836		(64,068)		(128,089)
Non-cash pension expense	4,025		3,513		6,868
Earnings of equity method investments	(8,256)		(6,772)		(5,553)
Distributions from equity method investments	10,720		-		-
Gain on sale of assets	(451)		(3,460)		(4,589)
Other non-cash adjustments to net income	(1,455)		5,102		(5,660)
Change in:
Accounts receivables and prepayments	(14,828)		(2,462)		(13,298)
Accounts payable	(28,212)		16,728		3,654
Taxes receivable (accrued)	38,003		(43,608)		(12,862)
Other current assets	(14,053)		(14,055)		(11,234)
Other current liabilities	(7,438)		(6,130)		15,751
Other assets	1,475		1,492		2,147
Other liabilities	(20,521)		4,487		14,000
Net cash provided by operating activities	272,364		119,543		81,472
Investing Activities:
Additions to utility plant	(251,937)		(243,544)		(287,219)
Proceeds from the sale of non-utility assets	2,250		5,785		-
Purchase of available-for-sale securities	-		-		(24,349)
Proceeds from the sale of available-for-sale securities	-		-		26,110
Proceeds from sale of emission allowances	2,382		2,959		19,846
Investments in unconsolidated affiliates	-		(3,210)		(8,675)
Withdrawal (refundable deposit) for tax related liabilities	-		43,927		(43,927)
Other	1,171		(3,349)		(263)
Net cash used in investing activities	(246,134)		(197,432)		(318,477)
Financing Activities:
(Decrease) increase in term loans	(170,000)		170,000		-
Issuance of long-term debt	230,000		120,000		240,000
Remarketing (purchase) of pollution control revenue bonds	166,100		(166,100)		-
Retirement of long-term debt	(81,064)		(1,064)		(81,064)
Dividends on common stock	(56,911)		(54,368)		(53,491)
Net change in short term borrowings	(108,950)		(27,635)		84,385
Capital contribution from parent	20,000		37,000		51,000
Other	(6,921)		(2,150)		(882)
Net cash (used in) provided by financing activities	(7,746)		75,683		239,948
Net increase (decrease) in cash and cash equivalents	18,484		(2,206)		2,943
Cash and cash equivalents at beginning of the year	3,141		5,347		2,404
Cash and cash equivalents at end of the year	$	21,625	$	3,141	$	5,347

Supplemental Disclosure of Cash Flow Information:
Cash paid during the year for:
Income taxes (received from) paid to parent	$	(13,756)	$	36,053	$	2,877
Interest (net of amount capitalized)	$	66,231	$	63,448	$	57,355
Non-cash investing activities:
Additions to property, plant and equipment in accounts payable	$	19,075	$	14,194	$	13,210

The accompanying notes are an integral part of these statements.

Idaho Power Company

Consolidated Statements of Retained Earnings

	Year Ended December 31,
	2009		2008		2007
	(thousands of dollars)

Retained Earnings, Beginning of Year	$	482,047	$	442,300	$	404,076

Net Income	122,559		94,115		76,579

Cumulative effect of accounting change (adoption of FIN 48)	-		-		15,136

Dividends on common stock	(56,911)		(54,368)		(53,491)

Retained Earnings, End of Year	$	547,695	$	482,047	$	442,300

The accompanying notes are an integral part of these statements.

Idaho Power Company

Consolidated Statements Comprehensive Income

	Year Ended December 31,
	2009		2008		2007
	(thousands of dollars)

Net Income	$	122,559	$	94,115	$	76,579

Other Comprehensive Income (Loss):
Unrealized gains (losses) on securities:
Net unrealized holding gains (losses) arising during the period,
net of tax of $1,169, ($3,034) and $114	1,820		(4,727)		179
Reclassification adjustment for losses (gains) included
in net income, net of tax of $0, $2,670 and ($592)	-		4,159		(922)
Net unrealized gains (losses)	1,820		(568)		(743)
Unfunded pension liability adjustment, net of tax
of ($885), ($1,273) and $208	(1,380)		(1,983)		324
Total Comprehensive Income	$	122,999	$	91,564	$	76,160

The accompanying notes are an integral part of these statements.

IDACORP, INC. AND Idaho POWER COMPANY

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES:

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

Nature of Business

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

IDACORP’s other subsidiaries include:

• IDACORP Financial Services, Inc. (IFS), an investor in affordable housing and other real estate investments;

• Ida-West Energy Company (Ida-West), an operator of small hydroelectric generation projects that satisfy the requirements of the Public Utility Regulatory Policies Act of 1978 (PURPA); and

• IDACORP Energy (IE), a marketer of energy commodities, which wound down operations in 2003.

In the second quarter of 2006, IDACORP management designated the operations of IDACOMM, Inc. (IDACOMM) as assets held for sale, as defined by accounting principles generally accepted in the United States of America (GAAP), and IDACOMM was sold in February 2007. IDACORP’s consolidated financial statements reflect the reclassification of the immaterial results of IDACOMM as discontinued operations for all periods presented.

Principles of Consolidation

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

The entities that IDACORP and Idaho Power consolidate consist primarily of the wholly-owned subsidiaries discussed above. In addition, IDACORP consolidates one VIE, Marysville Hydro Partners (Marysville), which is a joint venture owned 50 percent by Ida-West and 50 percent by Environmental Energy Company (EEC). Marysville has approximately $26 million of assets, primarily a 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 result 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.

Prior to October 2008, IDACORP also consolidated IFS’ limited partnership investment in Empire Development Company, LLC, (Empire) an entity that earned historic tax credits through the rehabilitation of the Empire Building in Boise, Idaho. In 2008 the partnership agreement for Empire was amended and as a result of the amendment Empire no longer met the criteria to be a VIE. Empire was deconsolidated and is now accounted for under the equity method of accounting.

Through IFS, IDACORP also holds variable interests in VIEs for which it is not the primary beneficiary. These VIEs are historic rehabilitation and affordable housing developments in which IFS holds limited partnership interests ranging from five to 99 percent. 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. These investments were acquired between 1996 and 2009. IFS’s maximum exposure to loss in these developments is limited to its net carrying value, which was $78 million at December 31, 2009.

Management Estimates

Management makes estimates and assumptions when preparing financial statements in conformity with GAAP. These estimates and assumptions include those related to rate regulation, retirement benefits, contingencies, litigation, asset impairment, income taxes, unbilled revenues and bad debt. These estimates and assumptions affect the reported amounts of assets and liabilities and the disclosure of contingent assets and liabilities at the date of the financial statements, and the reported amounts of revenues and expenses during the reporting period. These estimates involve judgments with respect to, among other things, future economic factors that are difficult to predict and are beyond management’s control. As a result, actual results could differ from those estimates.

Subsequent Events

Subsequent events were evaluated through February 23, 2010, up to the time the financial statements were issued.

System of Accounts

The accounting records of Idaho Power conform to the Uniform System of Accounts prescribed by the FERC and adopted by the public utility commissions of Idaho, Oregon and Wyoming.

Regulation of Utility Operations

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

Cash and Cash Equivalents

Cash and cash equivalents include cash on hand and highly liquid temporary investments that mature within three months of the date of acquisition.

Derivative Financial Instruments

Financial instruments such as commodity futures, forwards, options and swaps are used to manage exposure to commodity price risk in the electricity market. All derivative instruments are recognized as either assets or liabilities at fair value on the balance sheet. Idaho Power’s physical forward contracts qualify for the normal purchases and normal sales exception to derivative accounting requirements with the exception of forward contracts for the purchase of natural gas for use at Idaho Power’s natural gas generation facilities. The objective of the risk management program is to mitigate the risk associated with the purchase and sale of electricity and natural gas. Because of Idaho Power’s regulatory accounting mechanisms, Idaho Power records the changes in fair value of derivative instruments related to power supply as regulatory assets or liabilities.

Revenues

Operating revenues for Idaho Power related to the sale of energy are recorded when service is rendered or energy is delivered to customers. Idaho Power accrues estimated unbilled revenues for electric services delivered to customers but not yet billed at period-end. Idaho Power 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, Idaho Power is collecting Allowance for Funds Used During Construction (AFUDC) in base rates for a specific capital project, as discussed in Note 3, “Regulatory Matters.” Cash collected under this ratemaking mechanism is recorded as a regulatory liability.

Property, Plant and Equipment and Depreciation

The cost of utility plant in service represents the original cost of contracted services, direct labor and material, AFUDC and indirect charges for engineering, supervision and similar overhead items. Repair and maintenance costs associated with planned major maintenance are expensed as the costs are incurred, as are maintenance and repairs of property and replacements and renewals of items determined to be less than units of property. For utility property replaced or renewed, the original cost plus removal cost less salvage is charged to accumulated provision for depreciation, while the cost of related replacements and renewals is added to property, plant and equipment.

All utility plant in service is depreciated using the straight-line method at rates approved by regulatory authorities. Annual depreciation provisions as a percent of average depreciable utility plant in service approximated 2.81 percent in 2009, 2.73 percent in 2008 and 2.95 percent in 2007.

Long-lived assets are periodically reviewed for impairment when events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. If the sum of the undiscounted expected future cash flows from an asset is less than the carrying value of the asset, impairment must be recognized in the financial statements. There were no material impairments of these assets in 2008 or 2009.

Allowance for Funds Used During Construction

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. Idaho Power’s weighted-average monthly AFUDC rates for 2009, 2008 and 2007 were 6.7 percent, 5.2 percent and 6.8 percent, respectively. Idaho Power’s reductions to interest expense for AFUDC were $5 million for 2009, $7 million for 2008 and $8 million for 2007. Other income included $8 million, $3 million and $6 million of AFUDC for 2009, 2008 and 2007, respectively.

Income Taxes

IDACORP and Idaho Power account for income taxes under the asset and liability method, which requires the recognition of deferred tax assets and liabilities for the expected future tax consequences of events that have been included in the financial statements. Under this method, deferred tax assets and liabilities are determined based on the differences between the financial statements and tax basis of assets and liabilities using enacted tax rates in effect for the year in which the differences are expected to reverse. The effect of a change in tax rates on deferred tax assets and liabilities is recognized in income in the period that includes the enactment date.

Consistent with orders and directives of the Idaho Public Utilities Commission (IPUC), the regulatory authority having principal jurisdiction, Idaho Power’s deferred income taxes (commonly referred to as normalized accounting) are provided for the difference between income tax depreciation and straight-line depreciation computed using book lives on coal-fired generation facilities and properties acquired after 1980. On other facilities, deferred income taxes are provided for the difference between accelerated income tax depreciation and straight-line depreciation using tax guideline lives on assets acquired prior to 1981 unless contrary to applicable income tax guidance, deferred income taxes are not provided for those income tax timing differences where the prescribed regulatory accounting methods do not provide for current recovery in rates. Regulated enterprises are required to recognize such adjustments as regulatory assets or liabilities if it is probable that such amounts will be recovered from or returned to customers in future rates.

The state of Idaho allows a three-percent investment tax credit on qualifying plant additions. Investment tax credits earned on regulated assets are deferred and amortized to income over the estimated service lives of the related properties. Credits earned on non-regulated assets or investments are recognized in the year earned.

Income taxes are discussed in more detail in Note 2.

Comprehensive Income

Comprehensive income includes net income, unrealized holding gains and losses on available-for-sale marketable securities and amounts related to a deferred compensation plan for certain senior management employees and directors called the Senior Management Security Plan (SMSP).

The following table presents IDACORP’s and Idaho Power’s accumulated other comprehensive loss balance at December 31 (net of tax):

		2009		2008
		(thousands of dollars)
Unrealized holding gains on available-for-sale securities		$	1,820	$	-
Senior Management Security Plan			(10,087)		(8,707)
	Total	$	(8,267)	$	(8,707)

Other Accounting Policies

Debt discount, expense and premium are deferred and being amortized over the terms of the respective debt issues.

Reclassifications

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

• Third-party transmission expense was broken out from electric utility other operations and maintenance in IDACORP’s consolidated statements of income and from other operation in Idaho Power’s 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 Idaho Power’s consolidated balance sheets due to the employee notes becoming an immaterial balance;

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

• 2007 investments in affordable housing was combined with other in the investing section of IDACORP’s consolidated statements of cash flows;

• Excess tax benefit from share-based payment arrangements was combined with the change in taxes receivable (accrued) in the operating section and excess tax benefit from share-based payment arrangements was combined with other in the financing section of IDACORP’s consolidated statements of cash flows;

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

• Other assets was combined with other in the financing section of IDACORP’s and Idaho Power’s consolidated statements of cash flows.

New Accounting Pronouncements

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 Idaho Power 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 Idaho Power, the amendments are effective as of January 1, 2010, and early adoption is prohibited. The adoption of this guidance is not expected to have a material effect on the consolidated financial statements of IDACORP and Idaho Power.

Adopted Accounting Pronouncements

The FASB has issued several new accounting pronouncements. IDACORP and Idaho Power adopted these pronouncements in 2009:

• 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. GAAP recognized by the FASB to be applied to nongovernmental entities. Rules and interpretive releases of the Securities and Exchange Commission (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 Idaho Power’s results of operations, cash flows or financial positions. This Form 10-K reflects the implementation of the Codification.

• On January 1, 2009, IDACORP and Idaho Power 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 equity on the December 31, 2008, balance sheet. Idaho Power does not have any noncontrolling interests. The adoption of this guidance modifies financial statement presentation, but does not impact financial statement results.

• In June 2009, IDACORP and Idaho Power 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. This guidance has not significantly impacted IDACORP’s or Idaho Power’s consolidated financial statements.

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

o 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;

o 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

o 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 Idaho Power’s consolidated financial statements.

2. INCOME TAXES:

The components of the net deferred tax liability are as follows:

			IDACORP				Idaho Power
			2009		2008		2009		2008
			(thousands of dollars)
Deferred tax assets:
	Regulatory liabilities		$	47,183	$	44,341	$	47,183	$	44,341
	Advances for construction			8,335		9,305		8,335		9,305
	Deferred compensation			21,134		20,481		20,661		19,722
	Tax credits			81,935		76,597		2,548		-
	Retirement benefits			84,019		85,034		84,019		85,034
	Other			9,976		14,456		9,104		13,614
		Total		252,582		250,214		171,850		172,016
Deferred tax liabilities:
	Property, plant and equipment			282,034		246,424		282,034		246,424
	Regulatory assets			382,136		333,882		382,136		333,882
	Conservation programs			4,772		1,902		4,772		1,902
	PCA			34,025		62,820		34,025		62,820
	Partnership investments			13,396		13,060		-		-
	Retirement benefits			65,690		69,334		65,690		69,334
	Other			13,206		961		7,055		961
		Total		795,259		728,383		775,712		715,323
Net deferred tax liabilities			$	542,677	$	478,169	$	603,862	$	543,307

A reconciliation between the statutory federal income tax rate and the effective tax rate is as follows:

				IDACORP							Idaho Power
				2009		2008			2007		2009		2008		2007
				(thousands of dollars)
Federal income tax expense at
	35% statutory rate			$	51,349	$	41,165	$		33,601	$	55,328	$	46,100	$	39,188
Change in taxes resulting from:
		AFUDC			(4,533)		(3,577)			(4,757)		(4,533)		(3,577)		(4,757)
		Capitalized interest			1,529		1,729			2,289		1,529		1,729		2,289
		Investment tax credits			(3,404)		(3,490)			(3,578)		(3,404)		(3,490)		(3,578)
		Repair allowance			(3,500)		(2,450)			(2,450)		(3,500)		(2,450)		(2,450)
		Removal costs			(3,810)		(2,954)			(3,787)		(3,810)		(2,954)		(3,787)
		Capitalized overhead costs			(3,500)		(4,200)			(4,200)		(3,500)		(4,200)		(4,200)
		Uncertain tax positions			1,138		1,280			(3,586)		1,138		1,280		(3,586)
		Settlement of prior years’ tax
			returns		(4,119)		(2,753)			-		(4,119)		(2,761)		-
		State income taxes, net of
			federal benefit		1,216		3,842			5,810		1,903		4,601		6,618
		Depreciation			3,895		5,562			7,576		3,895		5,562		7,576
		Affordable housing
			tax credits		(7,870)		(11,437)			(14,541)		-		-		-
		Other, net			(6,029)		(3,517)			1,354		(5,406)		(2,240)		2,073
Total income tax expense				$	22,362	$	19,200	$		13,731	$	35,521	$	37,600	$	35,386
		Effective tax rate			15.2%		16.3%			14.3%		22.5%		28.5%		31.6%

The items comprising income tax expense are as follows:

			IDACORP						Idaho Power
			2009		2008		2007		2009		2008		2007
			(thousands of dollars)
Income taxes currently payable:
	Federal		$	6,199	$	13,801	$	9,573	$	21,035	$	16,390	$	8,916
	State			108		1,541		(3,105)		2,385		(3,602)		(6,202)
		Total		6,307		15,342		6,468		23,420		12,788		2,714
Income taxes deferred:
	Federal			23,309		18,709		8,035		20,638		33,224		28,148
	State			(4,509)		(3,645)		926		(5,792)		2,794		6,223
		Total		18,800		15,064		8,961		14,846		36,018		34,371
Uncertain tax positions:
	Federal			(2,496)		(12,763)		(3,345)		(2,496)		(12,763)		(3,345)
	State			(485)		(712)		(241)		(485)		(712)		(241)
		Total		(2,981)		(13,475)		(3,586)		(2,981)		(13,475)		(3,586)
Investment tax credits:
	Deferred			3,640		5,759		5,466		3,640		5,759		5,465
	Restored			(3,404)		(3,490)		(3,578)		(3,404)		(3,490)		(3,578)
		Total		236		2,269		1,888		236		2,269		1,887
Total income tax expense			$	22,362	$	19,200	$	13,731	$	35,521	$	37,600	$	35,386

IDACORP’s tax allocation agreement provides that each member of its consolidated group compute its income taxes on a separate company basis. Amounts payable or refundable are settled through IDACORP.

Tax Credits Carryforwards
As of December 31, 2009, IDACORP had $61.8 million of general business credit carryforward for federal income tax purposes, and $20.1 million of Idaho investment tax credit carryforward. The general business credit carryforward period expires from 2025 to 2029, and the Idaho investment tax credit expires from 2019 to 2023.

Uncertain Tax Positions

IDACORP and Idaho Power adopted new guidance on uncertain tax positions on January 1, 2007. IDACORP and Idaho Power recorded an increase of $15.1 million to 2007 opening retained earnings for the cumulative effect of adopting this guidance. A reconciliation of the beginning and ending amount of unrecognized tax benefits for IDACORP and Idaho Power is as follows (in thousands of dollars):

	2009		2008		2007
Balance at January 1,	$	4,119	$	17,594	$	21,180
Additions for tax positions of prior years		1,138		1,280		848
Reductions for tax positions of prior years		(4,119)		(10,426)		(4,434)
Settlements with taxing authorities		-		(4,329)		-
Balance at December 31,	$	1,138	$	4,119	$	17,594

If recognized, the $1.1 million balance of unrecognized tax benefits would affect the effective tax rate.

Since 2006, Idaho Power had been disputing the Internal Revenue Service’s (IRS) disallowance of Idaho Power’s use of the simplified service cost method (SSCM) of uniform capitalization for tax years 2001-2004. The dispute had been under review with the IRS Appeals Office. In December 2008, the Appeals Office informed IDACORP that the SSCM settlement computations were complete. IDACORP reviewed the final computations and agreed to the result. The settlement was submitted to the U.S. Congress Joint Committee on Taxation (JCT) for review in January 2009. In March 2009, the JCT completed its review and accepted the settlement without change.

In November 2006, IDACORP made a $44.9 million refundable tax deposit with the IRS related to the disputed income tax assessment for SSCM. In May 2008, IDACORP withdrew $20 million from the deposit. Approximately $21 million from the deposit was applied to the settled income tax deficiency and interest charges with the remaining balance refunded to IDACORP during 2009.

The IRS completed its examination of IDACORP’s 2004 tax year in August 2008 and its 2005 tax year in October 2008. The 2004 examination report was submitted for JCT review as part of the SSCM settlement and the 2005 report was submitted in November 2008. The JCT accepted both reports without change in March 2009. As of December 31, 2008, all uncertain tax positions related to tax years 2001-2005 were considered effectively settled.

In December 2008, the IRS began its examination of IDACORP’s 2006 tax year. The 2006 exam was completed in May 2009. The IRS began its examination of IDACORP’s 2007-2008 tax years in July 2009 and completed the exam in December. The 2006 examination report was submitted for JCT review in June 2009 and was accepted without change in July. Tax years 2007-2008 did not require JCT review. As of December 31, 2009, all uncertain tax positions related to tax years 2006-2008 were considered effectively settled.

IDACORP and Idaho Power recognize interest accrued related to unrecognized tax benefits as interest expense and penalties as other expense. During the years ended December 31, 2009, 2008 and 2007, Idaho Power recognized a net reduction in interest expense of $0.2 million, $0.1 million and $1.0 million. Idaho Power had no accrued interest as of December 31, 2009 and $0.2 million as of December 31, 2008. No penalties are accrued.

IDACORP and Idaho Power are subject to examination by their major tax jurisdictions – U.S. federal and state of Idaho. The open tax years are 2009 for federal and 2007-2009 for Idaho. 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 2009 examination is expected to be completed in 2010. In January 2010, IDACORP was accepted into CAP for its 2010 tax year. IDACORP and Idaho Power are unable to predict the outcome of these examinations.

Specifically within the 2009 CAP examination, the IRS began its audit of Idaho Power’s current method of uniform capitalization. In September 2009, the IRS issued Industry Director Directive #5 (IDD) which discusses the IRS’s compliance priorities and audit techniques related to the allocation of mixed service costs in the uniform capitalization methods of electric utilities. The IRS and Idaho Power are jointly working through the impact the IDD guidance has on Idaho Power’s uniform capitalization method. Idaho Power expects that the examination will be completed during 2010. Resolution of this matter would result in a decrease to Idaho Power’s unrecognized tax benefits for its 2009 uniform capitalization deduction by $1.1 million.

3. REGULATORY MATTERS:

Regulatory Assets and Liabilities

The following is a breakdown of Idaho Power’s regulatory assets and liabilities (in thousands of dollars):

			Remaining			Not
			Amortization	Earning		Earning			Total as of December 31,
Description			Period	a Return		a Return			2009			2008
Regulatory Assets:
	Income taxes			$	-		$	389,910		$	389,910		$	335,644
	Unfunded postretirement benefits ⁽¹⁾				-			168,026			168,026			177,348
	Pension expense deferrals ⁽²⁾				-			39,251			39,251			10,583
	Energy efficiency program costs ⁽²⁾		2010		10,585			1,622			12,207			8,806
	Power supply costs ⁽²⁾		Varies ⁽²⁾		84,633			-			84,633			149,099
	Fixed cost adjustment ⁽²⁾		2011		7,836			-			7,836			2,721
	Asset retirement obligations ⁽³⁾				-			14,749			14,749			10,907
	Mark-to-market liabilities ⁽⁴⁾				-			280			280			3,074
	Other		2010-2015		1,914			1,875			3,789			1,224
		Total ⁽⁵⁾		$	104,968		$	615,713		$	720,681		$	699,406

Regulatory Liabilities:
	Income taxes			$	-		$	54,958		$	54,958		$	46,102
	Removal costs ⁽³⁾				-			155,405			155,405			156,837
	Investment tax credits				-			73,506			73,506			73,270
	Deferred revenue-AFUDC				6,096			3,798			9,894			-
	Mark-to-market assets ⁽⁴⁾				-			715			715			652
	Other		2011		479			1,100			1,579			1,818
		Total ⁽⁶⁾		$	6,575		$	289,482		$	296,057		$	278,679

⁽¹⁾Represents the Idaho jurisdiction unfunded obligation of Idaho Power’s pension and postretirement plans, which are discussed in note 11.
⁽²⁾ These items are discussed in more detail below.
⁽³⁾ Asset retirement obligations and removal costs are discussed in Note 13
⁽⁴⁾ Mark-to market assets and liabilities are discussed in Note 16
⁽⁵⁾ Includes $601 and $3,074 for 2009 and 2008, respectively, reported in other current assets on the balance sheets.
⁽⁶⁾ Includes $8,972, and $2,413 for 2009 and 2008, respectively, reported in other current liabilities on the balance sheets.

In the event that recovery of Idaho Power’s costs through rates becomes unlikely or uncertain, regulatory accounting would no longer apply to some or all of Idaho Power’s operations and the items above may represent stranded investments. If not allowed full recovery of these items, Idaho Power would be required to write off the applicable portion, which could have a significant financial impact.

Deferred Net Power Supply Costs:

Changes in deferred power supply costs over the last two years were as follows:

	Idaho		Oregon ⁽¹⁾		Total
Balance at January 1, 2008	$	92,322	$	5,100	$	97,422
Costs deferred through PCA and PCAM		108,688		5,196		113,884
Prior costs expensed and recovered through rates		(64,030)		(2,441)		(66,471)
SO₂ allowances credited to account		(2,184)		(175)		(2,359)
Interest and other		6,025		598		6,623
Balance at December 31, 2008	$	140,821	$	8,278	$	149,099
Costs deferred through PCA and PCAM		42,533		(184)		42,349
Prior costs expensed and recovered through rates		(113,134)		(2,283)		(115,417)
SO₂ allowances credited to account		(2,034)		(83)		(2,117)
Interest and other		3,226		1,135		4,361
2007 Excess power costs order		-		6,358		6,358
Balance at December 31, 2009	$	71,412	$	13,221	$	84,633
⁽¹⁾ Oregon power supply cost deferrals are subject to a statute that specifically limits rate amortizations of deferred costs to six percent of gross Oregon revenue per year (approximately $2 million). Deferrals are amortized sequentially.

Idaho:

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

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.

The following table summarizes the PCA adjustments during the last three years:

Effective	$ Change
Date	(millions)	Notes
June 1, 2009	$84.3	The IPUC’s order reflects revised methodology discussed below in “PCA Workshops.” The increase was net of $4.5 million of gains from sales of excess SO₂emission allowances which the IPUC ordered be applied against the PCA. The IPUC has allowed Idaho Power to retain its PCA sharing percentage of the gain from sales of excess SO₂ allowances as a shareholder benefit with the remainder recorded as a customer benefit, substantially all of which was used to reduce the PCA. Proceeds from the sale of renewable energy certificates (RECs) will also be used to reduce the PCA. RECs are acquired by Idaho Power through purchases of renewable energy.
June 1, 2008	73.3	Increase was net of $16.5 million of gains from sales of excess SO2emission allowances
June 1, 2007	77.5	Increase was net of $69.1 million of gains from sales of excess SO2 emission allowances

• 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.

Oregon

2006-2007 Excess Power Costs: In December 2007, the OPUC approved the deferral for future recovery of $2 million of excess power costs incurred from May 1, 2006, through April 30, 2007, and effective September 2009, these costs began being collected through rates and amortized. Idaho Power expects amortization of this deferral to be completed in December 2010.

May-December 2007 Excess Power Costs: In May 2009, the OPUC approved the deferral for future recovery of $6.4 million, including interest through the date of the order, of excess net power supply costs incurred from May-December 2007. Idaho Power recorded the $6.4 million deferral in the second quarter 2009 as a reduction to power cost adjustment expense. The amount to be recovered was reduced by $0.9 million of previously deferred emission allowance sales (including interest) during the same period.

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

The APCU allows Idaho Power to reestablish its Oregon base net power supply costs annually, separate from a general rate case, and to forecast net power supply costs for the upcoming water year. The APCU has two components: the “October Update,” Idaho Power’s calculation of estimated normalized net power supply expenses for the following April through March test period, and the “March Forecast,” Idaho Power’s forecast of expected net power supply expenses for the same test period, updated for a number of variables including the most recent stream flow data and future wholesale electric prices. New base rates are implemented each June 1 based on the APCU.

2010 APCU: Idaho Power’s October Update portion of the 2010 APCU indicates that revenues associated with Idaho Power’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 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: A rate increase of 11.5 percent, or $3.9 million annually, took effect June 1, 2009.

2008 APCU: A rate increase of 15.7 percent, or $4.8 million annually, took effect June 1, 2008.

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

2009 PCAM: Actual net power supply costs were within the deadband, resulting in no deferral.

2008 PCAM: Actual net power supply costs exceeded the forecast for the 2008 calendar year by $7.7 million and, after application of the deadband, resulted in a $5.1 million deferral in 2008. The OPUC approved deferral of this amount in January 2010, to be amortized sequentially after previously authorized deferrals.

Fixed Cost Adjustment Mechanism (FCA)

Idaho Power accrued $6.6 million related to the FCA in 2009; subject to IPUC approval, recovery should begin June 1, 2010. 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. In 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.

Idaho Rate Cases

2009 Settlement Agreement: On January 13, 2010, the IPUC approved a settlement agreement among Idaho Power, several of Idaho Power’s customers, the IPUC staff and others. Significant elements of the settlement agreement include:

o All of the next $20 million will be allocated to customers as a direct rate reduction through the PCA.

o PCA reductions in excess of $60 million will be applied to absorb any increase in the base level of net power supply expenses.

o If the PCA reduction exceeds $60 million plus the increase in base net power supply expenses, the next $10 million will be allocated equally between Idaho Power and customers in the same manner as the first $40 million.

o Any remainder will go entirely to customers.

Because Idaho Power’s Idaho-jurisdiction return on equity was between 9.5 and 10.5 percent, the sharing and accelerated amortization provisions were not triggered in 2009.

The settlement agreement also included a provision to reestablish the base level for net power supply costs effective with the June 1, 2010 PCA rate change. On January 19, 2010, Idaho Power filed with the IPUC a request to increase base net power supply costs by $74.8 million in the Idaho jurisdiction. This amount, which is subject to approval by the IPUC, reflects the maximum increase to Idaho Power’s base net power supply costs, which would be used for both base rates and PCA calculations. The actual change in net power supply costs for rate purposes will depend upon the amount approved by the IPUC as well as the amount of any PCA decrease determined for the 2010-2011 PCA year. Written comments or protests with respect to Idaho Power’s application are due March 11, 2010.

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, Idaho Power filed a request for reconsideration with the IPUC and on March 19, 2009, the IPUC issued an order that increased Idaho Power’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 January 30, 2009 order authorized approximately $15 million related to increases in base net power supply costs. It also allowed Idaho Power 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 Idaho Power’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.

The IPUC denied reconsideration with respect to a refund of $3.3 million of fees recovered by Idaho Power from the FERC. On April 2, 2009, Idaho Power filed an application with the IPUC for an accounting order approving amortization of the fees over a five-year period beginning October 2006 when Idaho Power received the FERC credit. The IPUC approved Idaho Power’s requested amortization period in an order issued on April 28, 2009. In the first quarter of 2009, Idaho Power 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.

Idaho 2007 General Rate Case: On February 28, 2008, the IPUC approved a settlement stipulation that included an average increase in base rates of 5.2 percent (approximately $32.1 million annually), effective March 1, 2008. The settlement did not specify an overall rate of return or a return on equity.

Danskin CT1 Power Plant Rate Case: On May 30, 2008, the IPUC authorized Idaho Power to add to its rate base $64.2 million for the Danskin CT1 plant and related facilities, effective June 1, 2008, resulting in a base rate increase of 1.37 percent, or $8.9 million in annual revenues. Danskin CT1 located near Mountain Home, Idaho, began commercial operations on March 11, 2008.

Oregon 2009 General Rate Case: On December 16, 2009, Idaho Power filed a Joint Stipulation and testimony in support of a stipulation that would settle the revenue requirement issues surrounding the general rate case filed on July 31, 2009. If approved by the OPUC, the Joint Stipulation would increase base rates $5 million, or 15.4 percent, based on a return on equity of 10.175 percent and an overall rate of return of 8.061 percent. The requested effective date is March 1, 2010.

Advanced Metering Infrastructure (AMI)

The AMI project provides the means to automatically retrieve energy consumption information, eliminating manual meter reading expense. Idaho Power intends to install this technology for approximately 99 percent of its customers and is on pace to complete the installations by the end of 2011.

Idaho: On February 12, 2009, the IPUC approved Idaho Power’s application requesting a Certificate of Public Convenience and Necessity for the deployment of AMI technology and approval of accelerated depreciation for the existing metering equipment. The IPUC subsequently clarified that Idaho Power 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 Idaho Power, that it does not anticipate that the immediate savings derived from the implementation of AMI throughout Idaho Power’s service territory will eliminate or wholly offset the increase in Idaho Power’s revenue requirement caused by the authorized depreciation period.

On May 29, 2009, the IPUC approved annual recovery of $10.5 million, effective June 1, 2009. The order was based on Idaho Power’s actual investment in AMI to date, annualized through December 31, 2009. The IPUC also allowed Idaho Power 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. Actual depreciation expense recorded over the last seven months of 2009 totaled $6.2 million.

Oregon: The OPUC approved accelerated depreciation and recovery of existing meters in the Oregon jurisdiction over an 18-month period beginning January 2009. Idaho Power’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 approval increased both rates and depreciation expense $0.8 million in 2009.

Depreciation Filings

In 2008 and 2009 Idaho Power filed revisions to its depreciation rates with the IPUC, OPUC and FERC. The commissions approved the new rates, which reduce depreciation expense approximately $8.5 million annually. Idaho Power began applying the new depreciation rates in August 2008.

OATT

Formula Rates: In 2006, Idaho Power moved from a fixed rate to a formula rate, which allows transmission rates to be updated annually based on financial and operational data Idaho Power files with the FERC. The FERC accepted Idaho Power’s initial formula rates effective June 1, 2006, subject to refund pending the outcome of a hearing and settlement process.

Idaho Power and the parties who had opposed the filing entered into a settlement agreement, which was approved by the FERC in August 2007. The settlement agreement reduced Idaho Power’s formula rates, established an authorized rate of return on equity of 10.7 percent and resulted in a $1.7 million refund by Idaho Power. The settlement agreement did not cover the treatment of “Legacy Agreements”, which were contracts for transmission service that contained their own terms, conditions and rates and were in existence before implementation of the OATT in 1996.

On January 15, 2009, the FERC issued an order that required Idaho Power to reduce its transmission service rates to FERC jurisdictional customers and refund $13.3 million to these customers. Based on the FERC order, Idaho Power reserved an additional $7.9 million (including $0.7 million of interest) in 2008 to bring its reserve to the $13.3 million ordered refunded. Idaho Power made the refunds in February 2009 and filed a request for rehearing with the FERC. Of the additional $7.9 million ordered refunded, $2.3 million related to transmission revenues recorded in 2007 and $1.7 million related to transmission revenues recorded in 2006. In March 2009, the FERC issued a tolling order that effectively relieved it from acting for an indefinite period of time on Idaho Power’s request for rehearing. Idaho Power cannot predict when the FERC will rule on its request for rehearing or the outcome of this matter.

As discussed below, Idaho Power received an accounting order from the IPUC on October 30, 2009, authorizing it to defer for potential future recovery approximately $4.7 million in unrecovered transmission-related revenues associated with the FERC order.

2009 OATT: On August 28, 2009, Idaho Power 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, Idaho Power 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. Idaho Power subsequently adjusted its rates to $13.81 per kW-year in compliance with a January 15, 2009, order.

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

The Restated Transmission Services Agreement and three long-term service agreements with PacifiCorp were amended to replace a portion of the services provided for in the agreement with OATT service, effective June 13, 2009. As calculated in the FERC filings, the estimated net transmission revenue increase for the period June 13, 2009 through June 12, 2010 is approximately $3.2 million. These amendments are expected to increase 2010 transmission revenue $1.3 million as compared to 2009.

Idaho Power also filed a request with the FERC on June 19, 2009, for an increase in rates for the Agreement for Interconnection and Transmission Services with PacifiCorp. As calculated in the filing, the estimated net transmission revenue increase for the period September 1, 2009 through August 31, 2010, would be approximately $3.7 million. PacifiCorp has intervened in this case. Idaho Power began collecting the new rates effective August 19, 2009, subject to refund pending settlement procedures and hearing. Settlement discussions are ongoing. This revision is expected to increase 2010 transmission revenue $2.5 million as compared to 2009.

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 Idaho Power’s overall revenue requirement. In the last two general rate cases, Idaho Power included an estimate of OATT revenues from third parties based on the forecasted OATT rate. However, as discussed above in “OATT”, a FERC order issued on January 15, 2009, significantly reduced actual third-party transmission revenues Idaho Power received from June 2006 to date, resulting in an overstatement of the revenue credits in the Idaho jurisdictional revenue requirement.

On October 30, 2009, the IPUC approved an Idaho Power request for authorization to defer the difference between the revenue credits in the last two general rate cases and the amount of OATT revenues Idaho Power has received since March 2008 and expects to receive through May 2010. The IPUC order authorizes Idaho Power to amortize the unrecovered transmission revenues on a straight-line basis over a three-year period beginning January 1, 2011 and did not authorize a carrying charge on the balance. Based on actual and projected transmission revenues from March 2008 through May 2010, Idaho Power recorded a $4.7 million regulatory asset in 2009 for potential future recovery.

Idaho Power 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 Idaho Power’s favor, Idaho Power will reduce the deferral.

Pension Expense

In the 2003 Idaho general rate case, the IPUC disallowed recovery of pension expense because there were no current cash contributions being made to the pension plan. On June 1, 2007, the IPUC issued an order authorizing Idaho Power to account for its defined benefit pension expense on a cash basis, and to defer and account for pension expense as a regulatory asset. On February 17, 2010, the IPUC approved a recovery methodology that would permit Idaho Power to include in future rate cases a reasonable amortization and recovery of cash contributions. Idaho Power deferred approximately $29 million, $8 million and $3 million of pension expense to a regulatory asset in 2009, 2008, and 2007 respectively. Deferred pension costs are expected to be amortized to expense to match the revenues received when future pension contributions are recovered through rates. Idaho Power does not receive a carrying charge on the current deferral balance. A carrying charge will be recorded on the difference between actual cash contributions and the recovery of those amounts in rates.

Idaho Energy Efficiency Rider (Rider)

Idaho Power’s Rider is the chief funding mechanism for Idaho Power’s investment in energy efficiency, conservation, and demand response programs. Effective June 1, 2009, Idaho Power collects 4.75 percent of base revenues, or approximately $29-$33 million annually, under the Rider. Idaho Power collected 2.5 percent of base revenues from June 2008-May 2009 and 1.5 percent prior to June 2008. Energy efficiency program expenditures are reported as an operating expense with an equal amount of revenues recorded in other revenues, resulting in no net impact on earnings. The cumulative variance between expenditures and amounts collected through the rider is recorded as a regulatory asset or liability pending future collection from or obligation to customers. An asset balance indicates that Idaho Power has spent more than collected and a liability balance indicates that Idaho Power has collected more than it has spent. At December 31, 2009, Idaho Power’s rider balance was a regulatory asset of $11 million.

In the 2008 general rate case, Idaho Power requested that the IPUC explicitly find that Idaho Power’s expenditures between 2002 and 2007 of $29 million of funds obtained from the Rider were prudently incurred and no longer subject to potential disallowance. In 2009, the IPUC approved a stipulation identifying $14.3 million of Rider funding as prudent, and on January 25, 2010, Idaho Power and the IPUC staff filed a stipulation for approval by the IPUC to find the remaining expenditures through 2007 were prudently incurred.

On October 5, 2009, Idaho Power and other investor-owned electric utilities serving in Idaho began a series of many informal public workshops with the IPUC Staff to discuss how energy efficiency evaluation and prudency will be determined on a prospective basis. As a result, a Memorandum of Understanding written by Staff, Idaho Power and other investor-owned electric utilities in Idaho has been signed outlining a process for future energy efficiency expenditure approval. This document was filed with the IPUC on January 25, 2010.

4. LONG-TERM DEBT

The following table summarizes long-term debt at December 31:

			2009		2008
			(thousands of dollars)
First mortgage bonds:			$		$
	7.20% Series due 2009			-		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		-
	4.50% Series due 2020			130,000		-
	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		1,215,000		1,065,000
Pollution control revenue bonds:
	Variable Rate Series 2003 due 2024⁽¹⁾			-		49,800
	Variable Rate Series 2006 due 2026⁽¹⁾			-		116,300
	5.15% Series due 2024⁽¹⁾			49,800		-
	5.25% Series due 2026⁽¹⁾			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
Unamortized discount - net				(3,060)		(3,163)
Term Loan Credit Facility				-		166,100
Purchase of pollution control revenue bonds				-		(166,100)
	Total Idaho Power outstanding debt⁽²⁾			1,410,794		1,261,755
Debt related to investments in affordable housing				8,276		8,224
	Total IDACORP outstanding debt			1,419,070		1,269,979
Current maturities of long-term debt				(9,340)		(86,528)
		Total long-term debt	$	1,409,730	$	1,183,451

⁽¹⁾ Humboldt County and Sweetwater County Pollution Control Revenue bonds are secured by first mortgage bonds, bringing the total first mortgage bonds outstanding at December 31, 2009, to $1.381 billion.
⁽²⁾At December 31, 2009 and 2008, the overall effective cost of Idaho Power’s outstanding debt was 5.76 percent and 5.59 percent, respectively.

At December 31, 2009, the maturities for the aggregate amount of long-term debt outstanding were (in thousands of dollars):

		2010		2011		2012		2013		2014		Thereafter

Idaho Power		$	1,064	$	121,064	$	101,064	$	71,064	$	1,064	$	1,118,534
Other subsidiary debt			8,276		-		-		-		-		-
	Total	$	9,340	$	121,064	$	101,064	$	71,064	$	1,064	$	1,118,534

IDACORP Long-Term Financing

IDACORP has approximately $574 million remaining on a shelf registration statement that can be used for the issuance of debt securities or common stock. Common stock is discussed further in Note 6.

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. In 2009, IFS issued $8.3 million in equity funding obligations to finance portions of its $14 million of investments in affordable housing. The obligations are scheduled to mature in 2010.

Idaho Power Long-Term Financing

On March 30, 2009, Idaho Power issued $100 million of its 6.15% first mortgage bonds, due April 1, 2019. On November 20, 2009, Idaho Power issued $130 million of its 4.5% first mortgage bonds, due March 1, 2020. Idaho Power used the net proceeds from the two bond issuances to repay short-term debt and to repay $80 million of its 7.20 % first mortgage bonds that matured on December 1, 2009. As of December 31, 2009, Idaho Power had issued all securities remaining registered under its shelf registration statement.

Mortgage: As of December 31, 2009, Idaho Power could issue under the mortgage approximately $431 million of additional first mortgage bonds based on total unfunded property additions of approximately $719 million. Idaho Power could issue an additional $612 million of first mortgage bonds based on retired first mortgage bonds. These amounts are further limited by the maximum amount of first mortgage bonds set forth in the mortgage discussed below.

The mortgage secures all bonds issued under the indenture equally and ratably, without preference, priority or distinction. First mortgage bonds issued in the future will also be secured by the mortgage. The lien of the indenture constitutes a first mortgage on all the properties of Idaho Power, subject only to certain limited exceptions including liens for taxes and assessments that are not delinquent and minor excepted encumbrances. Certain of the properties of Idaho Power are subject to easements, leases, contracts, covenants, workmen’s compensation awards and similar encumbrances and minor defects and clouds common to properties. The mortgage does not create a lien on revenues or profits, or notes or accounts receivable, contracts or choses in action, except as permitted by law during a completed default, securities or cash, except when pledged, or merchandise or equipment manufactured or acquired for resale. The mortgage creates a lien on the interest of Idaho Power in property subsequently acquired, other than excepted property, subject to limitations in the case of consolidation, merger or sale of all or substantially all of the assets of Idaho Power. The mortgage requires Idaho Power to spend or appropriate 15 percent of its annual gross operating revenues for maintenance, retirement or amortization of its properties. Idaho Power may, however, anticipate or make up these expenditures or appropriations within the five years that immediately follow or precede a particular year.

On February 17, 2010, Idaho Power entered into the Forty-fifth Supplemental Indenture, dated as of February 1, 2010, to the Indenture of Mortgage and Deed of Trust, dated as of October 1, 1937, between Idaho Power and Deutsche Bank Trust Company Americas (formerly known as Bankers Trust Company) and R.G. Page, as Trustees (Stanley Burg, successor individual trustee) for the purpose of increasing the maximum amount of first mortgage bonds issuable by Idaho Power from $1.5 to $2.0 billion. The amount issuable is also restricted by property, earnings and other provisions of the mortgage and supplemental indentures to the mortgage. Idaho Power may amend the indenture and increase this amount without consent of the holders of the first mortgage bonds. The indenture requires that Idaho Power’s net earnings must be at least twice the annual interest requirements on all outstanding debt of equal or prior rank, including the bonds that Idaho Power may propose to issue. Under certain circumstances, the net earnings test does not apply, including the issuance of refunding bonds to retire outstanding bonds that mature in less than two years or that are of an equal or higher interest rate, or prior lien bonds.

Pollution Control Revenue Refunding Bonds and Term Loan Credit Agreement: On April 3, 2008, Idaho Power made a mandatory purchase of two series of Pollution Control Revenue Refunding Bonds issued for the benefit of Idaho Power, 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). Idaho Power 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 Idaho Power 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, Idaho Power 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., Union Bank, N.A. and Wachovia Bank, National Association, as lenders.

5. NOTES PAYABLE:

IDACORP has a $100 million credit facility and Idaho Power has a $300 million credit facility each of which expires 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 December 31, 2009, Idaho Power had regulatory authority to incur up to $450 million of short-term indebtedness.

At December 31, 2009, no loans were outstanding on IDACORP’s or Idaho Power’s facilities. Balances and interest rates of IDACORP’s short-term borrowings were as follows at December 31 (in thousands of dollars):

	IDACORP				Idaho Power				Total
	2009		2008		2009		2008		2009		2008
									(thousands of dollars)
Balances:
At the end of year	$	53,750	$	38,400	$	-	$	112,850	$	53,750	$	151,250
Average during the year	$	39,338	$	57,734	$	46,386	$	151,192	$	85,724	$	208,927
Weighted-average interest rate:
At the end of year		0.41%		4.29%		-		4.89%		0.41%		4.74%

6. COMMON STOCK

IDACORP Common Stock

The following table summarizes common stock transactions during the last three years and shares reserved at December 31, 2009:

	Shares issued			Shares reserved
	2009	2008	2007	December 31, 2009
Balance at beginning of year	46,929,203	45,063,107	43,905,458
Continuous equity program	489,360	1,453,967	881,337	2,138,818
Dividend reinvestment and stock purchase plan	209,859	169,229	150,458	2,903,460
Employee savings plan	156,814	111,021	99,562	3,813,902
Long-term incentive and compensation plan⁽¹⁾	127,928	115,730	26,292	2,275,476
Restricted stock plan	28,518	16,149	-	269,447
Balance at end of year	47,941,682	46,929,203	45,063,107	11,401,103

⁽¹⁾ Included in long-term incentive and compensation plan are 15,800 shares that were issued pursuant to the exercise of stock options on December 30, 2009 and settled on January 4, 2010.

IDACORP enters into Sales Agency Agreements as a means of selling its common stock from time to time. Under these agreements IDACORP sold 881,337 in 2007 at an average price of $32.32. In 2008, IDACORP sold 1,453,967 shares an average price of $28.72. In 2009, IDACORP sold 489,360 shares at an average price of $28.79 per share. IDACORP’s current Sales Agency Agreement is with BNY Mellon Capital Markets, LLC. As of December 31, 2009, there were 2.1 million shares remaining on the current agency agreement.

Idaho Power Common Stock

In 2009, 2008 and 2007, IDACORP contributed $20 million, $37 million and $51 million respectively, of additional equity to Idaho Power. No additional shares of Idaho Power common stock were issued.

Dividend Restrictions

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

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

7. STOCK-BASED COMPENSATION

IDACORP has three share-based compensation plans. IDACORP’s employee plans are the 2000 Long-Term Incentive and Compensation Plan (LTICP) and the 1994 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 Director Stock 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, restricted stock, performance shares, and several other types of stock-based awards. The RSP permits only the grant of restricted stock or performance-based restricted stock. At December 31, 2009, the maximum number of shares available under the LTICP and RSP were 1,602,259 and 25,515, respectively.

Stock awards: Restricted stock awards have three-year vesting periods and entitle the recipients to dividends and voting rights. Unvested shares are restricted as to disposition and subject to forfeiture under certain circumstances. The fair value of these awards is based on the market price of common stock on grant date and is charged to compensation expense over the vesting period, based on the number of shares expected to vest.

Performance-based restricted stock awards have three-year vesting periods and entitle the recipients to voting rights. 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 and paid out only on shares that eventually vest.

The performance awards 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.

A summary of restricted stock and performance share activity is presented below. Idaho Power share amounts represent the portion of IDACORP amounts related to Idaho Power employees:

	IDACORP			Idaho Power
		Weighted-			Weighted-
		average			Average
	Number of	Grant Date		Number of	Grant Date
	Shares	Fair Value		Shares	Fair Value
Nonvested shares at January 1, 2009	325,793	$	26.72	303,257	$	26.68
Shares granted	153,196		21.49	144,143		21.49
Shares forfeited	(27,158)		23.43	(27,158)		23.43
Shares vested	(146,491)		26.29	(134,207)		26.42
Nonvested shares at December 31, 2009	305,340	$	24.59	286,035	$	24.49

The total fair value of shares vested during the years ended December 31, 2009, 2008 and 2007 was $3.9 million, $0.8 million and $0.9 million, respectively. At December 31, 2009, IDACORP had $3.6 million of total unrecognized compensation cost related to nonvested share-based compensation that was expected to vest. Idaho Power’s share of this amount was $3.4 million. These costs are expected to be recognized over a weighted-average period of 1.67 years. IDACORP uses original issue and/or treasury shares for these awards.

Stock options: 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. Beginning in 2006, stock options are not a significant component of share-based compensation awards under the LTICP. The following table presents information about options granted and exercised (in thousands of dollars, except for weighted-average amounts):

	IDACORP						Idaho Power
	2009		2008		2007		2009		2008		2007
Fair value of options vested	$	266	$	435	$	737	$	208	$	353	$	579
Intrinsic value of options exercised		204		182		79		204		182		11
Cash received from exercises		591		707		281		591		707		40
Tax benefits realized from exercises		80		71		31		80		71		4

As of December 31, 2009, IDACORP and Idaho Power had recognized all compensation cost related to stock options. IDACORP uses original issue and/or treasury shares to satisfy exercised options.

IDACORP’s and Idaho Power’s stock option transactions are summarized below. Idaho Power share amounts represent the portion of IDACORP amounts related to Idaho Power employees:

					Weighted
			Weighted-		Average	Aggregate
		Number	Average		Remaining	Intrinsic
		of	Exercise		Contractual	Value
		Shares	Price		Term	(000s)
IDACORP
Outstanding at December 31, 2008		783,985	$	34.84	3.57	$	641
	Exercised	(25,800)		22.92
	Forfeited	(3,632)		29.75
	Expired	(138,550)		39.69
Outstanding at December 31, 2009		616,003	$	34.27	2.74	$	965

Vested or expected to vest at December 31, 2009		615,961	$	34.27	2.74	$	965
Exercisable at December 31, 2009		597,409	$	34.41	2.67	$	923

Idaho Power
Outstanding at December 31, 2008		576,996	$	34.34	3.67	$	611
	Exercised	(25,800)		22.92
	Forfeited	(3,632)		29.75
	Expired	(133,600)		39.86
Outstanding at December 31, 2009		413,964	$	33.31	2.96	$	862

Vested or expected to vest at December 31, 2009		413,932	$	33.31	2.96	$	862
Exercisable at December 31, 2009		397,903	$	33.45	2.87	$	826

Compensation Expense: 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 Idaho Power for those costs associated with Idaho Power’s employees (in thousands of dollars):

	IDACORP						Idaho Power
	2009		2008		2007		2009		2008		2007
Compensation cost	$	4,199	$	3,897	$	2,745	$	3,986	$	3,683	$	2,473
Income tax benefit	$	1,642	$	1,524	$	1,073	$	1,587	$	1,440	$	967

No equity compensation costs have been capitalized.

8. EARNINGS PER SHARE

The following table presents the computation of IDACORP’s basic and diluted earnings per common share (in thousands, except for per share amounts):

				Year ended December 31,
				2009		2008		2007
Numerator:
	Income from continuing operations attributable to IDACORP, Inc.			$	124,350	$	98,414	$	82,272
Denominator:
	Weighted-average shares outstanding - basic				47,124		45,268		44,291
	Effect of dilutive securities:
		Options			16		37		45
		Restricted Stock			42		74		29
			Weighted-average shares outstanding – diluted		47,182		45,379		44,365

Basic and diluted earnings per share from continuing operations				$	2.64	$	2.17	$	1.86

The diluted EPS computation excluded 594,107 options in 2009, 556,518 options in 2008 and 487,100 options in 2007 because the options’ exercise prices were greater than the average market price of the common stock during those years. In total, 616,003 options were outstanding at December 31, 2009, with expiration dates between 2010 and 2015.

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. Adoption of this guidance did not have a material impact on IDACORP’s EPS.

9. COMMITMENTS:

Purchase Obligations:

At December 31, 2009, Idaho Power had the following long-term commitments relating to purchases of energy, capacity, transmission rights and fuel:

	2010		2011		2012		2013			2014		Thereafter
	(thousands of dollars)

Cogeneration and power production	$	210,999	$	229,740	$	124,051	$	113,884	$		114,850		$	1,680,001
Power and transmission rights		44,298		21,979		8,699		3,296			2,404			7,612
Fuel		64,132		64,130		52,671		54,032			53,136			95,346

As of December 31, 2009, Idaho Power had signed agreements to purchase energy from 96 CSPP facilities with contracts ranging from one to 30 years. Eighty of these facilities, with a combined nameplate capacity of 298 MW, were on-line at the end of 2009; the other 16 facilities under contract, with a combined nameplate capacity of 266 MW, are projected to come on-line during 2010 and 2011. The majority of the new facilities will be wind resources which will generate on an intermittent basis. During 2009, Idaho Power purchased 970,419 megawatt-hours (MWh) from these projects at a cost of $59 million, resulting in a blended price of 6.1 cents per kilowatt hour. Idaho Power purchased 756,014 megawatt-hours at a cost of $45.9 million in 2008, and 777,147 megawatt-hours at a cost of $45 million in 2007.

In addition, IDACORP has the following long-term commitments for lease guarantees, equipment, maintenance and services, and industry related fees.

		2010			2011			2012		2013				2014		Thereafter
		(thousands of dollars)

Operating leases		$	2,769	$		2,059	$		1,324		$	1,335	$		1,403		$	5,737
Equipment, maintenance, and service
	agreements		58,491			14,492			8,357			7,339			3,296			6,933
FERC and other industry related fees			7,016			6,475			6,540			6,505			4,199			20,534

IDACORP’s expense for operating leases was approximately $3.5 million in 2009, $3 million in 2008 and $3 million in 2007.

Guarantees
Idaho Power has agreed to guarantee the performance of reclamation activities at Bridger Coal Company of which IERCo owns a one-third interest. This guarantee, which is renewed each December, was $63 million at December 31, 2009. Bridger Coal Company has a reclamation trust fund set aside specifically for the purpose of paying these reclamation costs. At this time Bridger Coal Company is revising their estimate of future reclamation costs. To ensure that the reclamation trust fund maintains adequate reserves, Bridger Coal Company has the ability to add a per ton surcharge if it is determined that future liabilities exceed the trust’s assets. 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.

10. CONTINGENCIES

Legal Proceedings

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

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

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

In an August 2006 decision, the Ninth Circuit ruled that all transactions that occurred within the CalPX and the Cal ISO markets were proper subjects of the refund proceeding. In that decision the Ninth Circuit 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. Parts of the decision exposed sellers to increased claims for potential refunds. The Ninth Circuit issued its mandate on April 15, 2009, thereby officially returning the cases to the FERC for further action consistent with the court’s decision.

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

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

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

The orders establishing the scope of the show cause proceedings are presently the subject of review petitions in the Ninth Circuit. Although IE and Idaho Power are unable to predict how or when the Ninth Circuit will act on these review petitions, in light of the settlement described above, IE and Idaho Power believe this matter will not have a material adverse effect on their consolidated financial positions, results of operations or cash flows.

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

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

In separate filings, the California Parties, which no longer include the California Electricity Oversight Board, and the City of Tacoma, Washington and the Port of Seattle, Washington asked the FERC to take actions to reorganize and restructure the case so that they may pursue claims that all spot market sales in the Cal ISO and CalPX markets and in the Pacific Northwest from January 1, 2000 through June 20, 2001 should be repriced, and thereby become subject to refund, because market manipulation and tariff violations affected spot market prices. This would expand the scope of the refund period in the Pacific Northwest proceeding from the December 25, 2000 through June 20, 2001 period previously considered by the FERC. On May 22, 2009, the California Parties filed a motion with the FERC to sever the CDWR sales from the remainder of the Pacific Northwest proceedings and to consolidate the CDWR sales portion of the Pacific Northwest case with ongoing proceedings in cases that IE and Idaho Power have settled and with a new complaint filed on May 22, 2009 by the California Attorney General against parties with whom the California Parties have not settled (Brown Complaint). IE and Idaho Power, along with a number of other parties, filed their opposition to the motion of the California Parties. Many other parties also filed responses to the motion of the California Parties. The City of Tacoma, Washington and the Port of Seattle, Washington filed a motion on August 4, 2009 with the FERC in connection with the California refund proceeding, the Lockyer remand pending before the FERC (involving claims of failure to file quarterly transaction reports with the FERC, from which IE and Idaho Power previously were dismissed), the Brown Complaint and the Pacific Northwest refund remand proceeding. The City of Tacoma and the Port of Seattle motion asks the FERC, either on a summary basis or after new evidentiary hearings, to require refunds from all sellers in the Pacific Northwest spot markets for the expanded period (January 1, 2000 through June 20, 2001). IE and Idaho Power joined with a number of other sellers in the Pacific Northwest markets during 2000 and 2001 in opposing the motion of the City of Tacoma and the Port of Seattle. IE and Idaho Power intend to vigorously defend their positions in these proceedings, but are unable to predict the outcome of these matters or estimate the impact these matters may have on their consolidated financial positions, results of operations or cash flows.

Western Shoshone National Council: On April 10, 2006, the Western Shoshone National Council (which purports to be the governing body of the Western Shoshone Nation) and certain of its individual tribal members filed a First Amended Complaint and Demand for Jury Trial in the U.S. District Court for the District of Nevada, naming Idaho Power and other unrelated entities as defendants. Plaintiffs allege that Idaho Power’s ownership interest in certain land, minerals, water or other resources was converted and fraudulently conveyed from lands in which the plaintiffs had historical ownership rights and Indian title dating back to the 1860’s or before.

On May 31, 2007, the U.S. District Court granted the defendants’ motion to dismiss stating that the plaintiffs’ claims are barred by the finality provision of the Indian Claims Commission Act, and entered judgment in favor of Idaho Power on January 25, 2008. Plaintiffs appealed the district court’s decision to the Ninth Circuit which affirmed the district court’s dismissal of the action. The time within which plaintiffs could pursue further review has expired.

Sierra Club Lawsuit-Bridger: In February 2007, the Sierra Club and the Wyoming Outdoor Council filed a complaint against PacifiCorp in the U.S. District Court for the District of Wyoming alleging violations of air quality opacity standards at the Jim Bridger coal-fired plant in Sweetwater County, Wyoming. Opacity is an indication of the amount of light obscured by the flue gas of a power plant. The complaint alleged thousands of opacity permit violations by PacifiCorp and sought a declaration that PacifiCorp had violated opacity limits, a permanent injunction ordering PacifiCorp to comply with such limits, civil penalties of up to $32,500 per day per violation, and reimbursement of plaintiffs’ costs of litigation, including reasonable attorneys’ fees. Idaho Power is not a party to this proceeding but has a one-third ownership interest in the plant. PacifiCorp owns a two-thirds interest in and is the operator of the plant. On February 10, 2010, PacifiCorp and plaintiffs reached an agreement in principle to the settlement of the lawsuit in its entirety. The settlement is subject to the approval of the Environmental Protection Agency and the court. If approved, the settlement will not have a material adverse effect on Idaho Power’s consolidated financial positions, results of operations or cash flows.

100

Sierra Club Lawsuit – Boardman: In September 2008, the Sierra Club and four other non-profit corporations filed a complaint against Portland General Electric Company (PGE) in the U.S. District Court for the District of Oregon alleging opacity permit limit violations at the Boardman coal-fired plant located in Morrow County, Oregon. The complaint also alleged violations of the Clean Air Act, related federal regulations and the Oregon State Implementation Plan relating to PGE’s construction and operation of the plant. The complaint sought a declaration that PGE had violated opacity limits, a permanent injunction ordering PGE to comply with such limits, injunctive relief requiring PGE to remediate alleged environmental damage and ongoing impacts, civil penalties of up to $32,500 per day per violation, and reimbursement of plaintiffs’ costs of litigation, including reasonable attorneys’ fees. Idaho Power is not a party to this proceeding but has a 10 percent ownership interest in the Boardman plant. PGE owns 65 percent and is the operator of the plant.

On December 5, 2008, PGE filed a motion to dismiss nine of the twelve claims asserted by plaintiffs in their complaint, alleging among other arguments that certain claims are barred by the statute of limitations or fail to state a claim upon which the court can grant relief. On September 30, 2009, the court denied most of PGE’s motion to dismiss. Idaho Power continues to monitor the status of this matter but is unable to predict its outcome or what effect this matter may have on its consolidated financial position, results of operations or cash flows.

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

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

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

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U.S. Bureau of Reclamation: Idaho Power filed a complaint on October 15, 2007 and an amended complaint on September 30, 2008 in the U.S. District Court of Federal Claims in Washington, D.C. against the U.S. Bureau of Reclamation. The complaint relates to a contract right for delivery of water to its hydropower projects on the Snake River to recover damages from the U.S. for the lost generation resulting from reduced flows and a prospective declaration of contractual rights so as to prevent the U.S. from continued failure to fulfill its contractual and fiduciary duties to Idaho Power. In 1923, Idaho Power and the U.S. entered into a contract that facilitated the development of the American Falls Reservoir by the U.S. on the Snake River in southeast Idaho. This 1923 contract entitles Idaho Power to 45,500 acre-feet of primary storage capacity in the reservoir and 255,000 acre-feet of secondary storage that was to be available to Idaho Power between October 1 of any year and June 10 of the following year as necessary to maintain specified water flows at Idaho Power’s Twin Falls power plant below Milner Dam. Idaho Power believes that the U.S. has failed to deliver this secondary storage, at the specified flows, since 2001. Discovery is scheduled to be completed by March 3, 2010. Trial of the matter has not been scheduled. Idaho Power is unable to predict the outcome of this action.

Oregon Trail Heights Fire: On August 25, 2008, a fire ignited beneath an Idaho Power distribution line in Boise, Idaho. It was fanned by high winds and spread rapidly, resulting in one death, the destruction of 10 homes and damage or alleged fire related losses to approximately 30 others. Following the investigation, the Boise Fire Department determined that the fire was linked to a piece of line hardware on one of Idaho Power’s distribution poles and that high winds contributed to the fire and its resultant damage.

Idaho Power has received notice of claims from a number of the homeowners and their insurers and while it has continued investigation of these claims, Idaho Power has reached settlements with a number of the individuals or their insurers who have alleged damages resulting from the fire. Idaho Power is insured up to policy limits against liability for claims in excess of its self-insured retention. Idaho Power has accrued for any loss that is probable and reasonably estimable, including insurance deductibles, and believes this matter will not have a material adverse effect on its consolidated financial position, results of operations or cash flows.

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

11. BENEFIT PLANS:

Pension Plans

Idaho Power has a noncontributory defined benefit pension plan covering most employees. The benefits under the plan are based on years of service and the employee’s final average earnings. Idaho Power’s policy is to fund, with an independent corporate trustee, at least the minimum required under the Employee Retirement Income Security Act of 1974 (ERISA) but not more than the maximum amount deductible for income tax purposes. Idaho Power was not required to contribute to the plan in 2009, 2008 or 2007. The market-related value of assets for the plan is equal to the fair value of the assets. Fair value is determined by utilizing publicly quoted market values and independent pricing services depending on the nature of the asset, as reported by the trustee/custodian of the plan.

In addition, Idaho Power has a nonqualified, deferred compensation plan for certain senior management employees and directors called the Senior Management Security Plan (SMSP). At December 31, 2009 and 2008, approximately $40.3 million and $39.9 million, respectively, of life insurance policies and investments in marketable securities, all of which are held by a trustee, were designated to satisfy the projected benefit obligation of the plan but do not qualify as plan assets in the actuarial computation of the funded status.

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The following table summarizes the changes in benefit obligations and plan assets of these plans:

		Pension Plan				SMSP
		2009		2008		2009		2008
		(thousands of dollars)
Change in benefit obligation:
	Benefit obligation at January 1	$	464,416	$	420,526	$	48,393	$	43,153
	Service cost		16,514		14,920		1,610		1,278
	Interest cost		27,865		26,393		2,854		2,669
	Actuarial loss		16,193		19,547		3,156		3,376
	Benefits paid		(18,244)		(16,970)		(3,294)		(2,644)
	Plan amendments		-		-		-		561
	Benefit obligation at December 31		506,744		464,416		52,719		48,393
Change in plan assets:
	Fair value at January 1		295,324		407,970		-		-
	Actual return on plan assets		36,394		(95,676)		-		-
	Benefits paid		(18,244)		(16,970)		-		-
	Fair value at December 31		313,474		295,324		-		-
Funded status at end of year		$	(193,270)	$	(169,092)	$	(52,719)	$	(48,393)
Amounts recognized in the statement of
	financial position consist of:
Other current liabilities		$	-		-	$	(3,244)	$	(2,883)
Noncurrent liabilities ⁽¹⁾			(193,270)		(169,092)		(49,475)		(45,510)
Net amount recognized		$	(193,270)	$	(169,092)	$	(52,719)	$	(48,393)
Amounts recognized in accumulated other
	comprehensive income consist of:
Net loss		$	150,196	$	155,289	$	14,585	$	12,088
Prior service cost			2,505		3,155		1,977		2,209
Subtotal			152,701		158,444		16,562		14,297
Less amount recorded as regulatory asset			(152,701)		(158,444)		-		-
Net amount recognized in accumulated
	other comprehensive income	$	-	$	-	$	16,562	$	14,297
Accumulated benefit obligation		$	425,744	$	385,002	$	48,563	$	44,275
⁽¹⁾ Noncurrent liabilities are contained in IDACORP’s and Idaho Power’s Consolidated Balance Sheets under “Other liabilities” and “Other deferred credits,” respectively.

The following table shows the components of net periodic benefit cost for these plans:

		Pension Plan						SMSP
		2009		2008		2007		2009		2008		2007
		(thousands of dollars)

Service cost		$	16,514	$	14,920	$	15,213	$	1,610	$	1,278	$	1,409
Interest cost			27,865		26,393		24,457		2,854		2,669		2,372
Expected return on assets			(23,965)		(34,112)		(33,387)		-		-		-
Amortization of net loss			8,857		-		-		232		489		566
Amortization of prior service cost			650		650		650		659		192		173
	Net periodic pension cost	$	29,921	$	7,851	$	6,933	$	5,355	$	4,628	$	4,520

In 2010, IDACORP and Idaho Power expect to recognize as components of net periodic benefit cost $9.5 million from amortizing amounts recorded in accumulated other comprehensive income (or as a regulatory asset for the pension plan) as of December 31, 2009, relating to the pension and SMSP plans. This amount consists of $7.7 million of amortization of net loss, and $0.7 million of amortization of prior service cost for the pension plan and $0.9 million of amortization of net loss and $0.2 million of amortization of prior service cost for the SMSP.

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The following table summarizes the expected future benefit payments of these plans:

		2010		2011		2012		2013		2014		2015-2019
		(thousands of dollars)
Pension Plan	$	19,453	$	20,785	$	22,654	$	24,716	$	26,586	$	169,665
SMSP	$	3,332	$	3,349	$	3,483	$	3,703	$	3,890	$	21,000

Pension Protection Act: In accordance with the Pension Protection Act of 2006 (PPA), and the relief provisions of the Worker, Retiree, and Employer Recovery Act of 2008 (WRERA), which was signed into law on December 23, 2008, companies are required to meet minimum funding levels in order to avoid benefit restrictions. The WRERA also provides for asset smoothing, which allows the use of asset averaging, including expected returns (subject to certain limitations), for a 24-month period in the determination of the funding requirements. IDACORP and Idaho Power have elected to use asset smoothing.

On March 31, 2009, the U.S. Department of the Treasury (Treasury) provided guidance on the selection of the corporate bond yield curve for determining plan liabilities and allows companies to choose from a range of months in selecting a yield curve, rather than requiring the use of prescribed rates. The Treasury’s announcement specifically referenced 2009, but also indicated that technical guidance will be forthcoming to address future years. The revisions in the PPA, WRERA, Treasury guidance, and IRS guidance resulted in IDACORP and Idaho Power revising the funded status as of January 1, 2009, effectively reducing or delaying the required contributions from IDACORP and Idaho Power from what would otherwise be required, and what was previously disclosed. At January 1, 2009, Idaho Power’s pension plan was above the minimum required funding levels as revised by the PPA, WRERA, Treasury guidance and IRS guidance, but below the minimum required funding levels at January 1, 2010, and is projected to stay below the minimum required funding levels through 2015. As Idaho Power’s pension plan is below the minimum required funding levels at January 1, 2010, future minimum contributions are required. Based on the provisions and methodologies allowed under the PPA, WRERA, Treasury guidance and IRS guidance, IDACORP and Idaho Power were not required to contribute to their pension plan in 2009, and estimated minimum required contributions will be approximately $6 million in 2010, $44 million in 2011 $47 million in 2012, $39 million in 2013, and $40 million in 2014. IDACORP and Idaho Power may elect to make contributions earlier than the required dates.

The IRS and Treasury have issued final regulations effective October 15, 2009 that apply to plan years beginning on or after January 1, 2010. These regulations reflect provisions added by the PPA, as amended by the WRERA. These regulations affect sponsors, administrators, participants, and beneficiaries of single employer defined benefit pension plans. The regulations provide guidance regarding the determination of the value of plan assets and benefit liabilities for purposes of the funding requirements, regarding the use of certain funding balances maintained for those plans, and regarding benefit restrictions for certain underfunded defined benefit pension plans. These final regulations did not materially change existing estimates relating to pension plan contributions.

Additional legislative or regulatory measures, as well as fluctuations in financial market conditions, may impact funding requirements. IDACORP and Idaho Power continue to monitor the legislative and regulatory environments for additional changes, evaluating them for their potential impact on funding requirements and strategies.

Postretirement Benefits
Idaho Power maintains a defined benefit postretirement plan (consisting of health care and death benefits) that covers all employees who were enrolled in the active group plan at the time of retirement as well as their spouses and qualifying dependents. Benefits for employees who retire after December 31, 2002, are limited to a fixed amount, which will limit the growth of Idaho Power’s future obligations under this plan.

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The following table summarizes the changes in benefit obligation and plan assets (in thousands of dollars):

		2009		2008
Change in accumulated benefit obligation:
	Benefit obligation at January 1	$	59,648	$	56,826
	Service cost		1,221		1,154
	Interest cost		3,565		3,498
	Actuarial loss		2,128		1,656
	Benefits paid⁽¹⁾		(3,915)		(3,486)
	Benefit obligation at December 31		62,647		59,648

Change in plan assets:
	Fair value of plan assets at January 1		25,283		35,096
	Actual return on plan assets		5,609		(7,834)
	Employer contributions		3,915		1,507
	Benefits paid⁽¹⁾		(3,915)		(3,486)
	Fair value of plan assets at December 31		30,892		25,283
Funded status at end of year (included in noncurrent liabilities)⁽²⁾		$	(31,755)	$	(34,365)
⁽¹⁾ Benefits paid are net of $2,731 and $1,927 of plan participant contributions, and $385 and $421 of Medicare Part D subsidy receipts for 2009 and 2008, respectively.
⁽²⁾ Noncurrent liabilities are contained in “Other liabilities” for IDACORP, and “Other deferred credits” for Idaho Power.

Amounts recognized in accumulated other comprehensive income consist of:

Net loss		$	14,112	$	16,289
Prior service cost (credit)			(1,537)		(2,072)
Transition obligation			6,120		8,160
Subtotal			18,695		22,377
Less amount recognized in regulatory assets			(15,235)		(18,904)
Less amount included in deferred tax assets			(3,460)		(3,473)
Net amount recognized in accumulated other comprehensive income		$	-	$	-

The net periodic postretirement benefit cost was as follows (in thousands of dollars):

	2009		2008		2007
Service cost	$	1,221	$	1,154	$	1,368
Interest cost		3,565		3,498		3,512
Expected return on plan assets		(2,146)		(2,899)		(2,777)
Amortization of net loss		842		-		403
Amortization of prior service cost		(535)		(535)		(535)
Amortization of unrecognized transition obligation		2,040		2,040		2,040
Net periodic postretirement benefit cost	$	4,987	$	3,258	$	4,011

In 2010, IDACORP and Idaho Power expect to recognize as components of net periodic benefit cost $2.1 million from amortizing amounts recorded in accumulated other comprehensive income as of December 31, 2009 relating to the postretirement plan. This amount consists of ($0.5) million of prior service cost, $0.6 million of net loss and $2.0 million of transition obligation.

Medicare Act: The Medicare Prescription Drug, Improvement and Modernization Act of 2003 was signed into law in December 2003 and established a prescription drug benefit, as well as a federal subsidy to sponsors of retiree health care benefit plans that provide a prescription drug benefit that is at least actuarially equivalent to Medicare’s prescription drug coverage.

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The following table summarizes the expected future benefit payments of the postretirement benefit plan and expected Medicare Part D subsidy receipts (in thousands of dollars):

		2010		2011		2012		2013		2014		2015-2019

Expected benefit payments⁽¹⁾		$	4,200	$	4,400	$	4,500	$	4,700	$	4,800	$	25,200
Expected Medicare Part D
	subsidy receipts	$	500	$	500	$	600	$	600	$	700	$	4,500

⁽¹⁾ Expected benefit payments are net of expected Medicare Part D subsidy receipts.

The assumed health care cost trend rate used to measure the expected cost of health benefits covered by the plan was eight percent and ten percent in 2009 and 2008, respectively. The assumed health care cost trend rate for 2009 is assumed to decrease gradually to five percent by 2066. The assumed dental cost trend rate used to measure the expected cost of dental benefits covered by the plan was five percent in both 2009 and 2008. A 1-percentage point change in the assumed health care cost trend rate would have the following effects at December 31, 2009 (in thousands of dollars):

	1-Percentage-Point
	Increase			Decrease

Effect on total of cost components	$	288	$	(218)
Effect on accumulated postretirement benefit obligation	$	2,471	$	(1,949)

Plan Assumptions:
The following table sets forth the weighted-average assumptions used at the end of each year to determine benefit obligations for all Idaho Power-sponsored pension and postretirement benefits plans:

	Pension		Postretirement
	Benefits		Benefits
	2009	2008	2009	2008
Discount rate	5.9%	6.1%	5.9%	6.1%
Rate of compensation increase	4.5%	4.5%	-	-
Medical trend rate	-	-	8.0%	10.0%
Dental trend rate	-	-	5.0%	5.0%
Measurement date	12/31/09	12/31/08	12/31/09	12/31/08

The following table sets forth the weighted-average assumptions used to determine net periodic benefit cost for all Idaho Power-sponsored pension and postretirement benefit plans:

	Pension		Postretirement
	Benefits		Benefits
	2009	2008	2009	2008
Discount rate	6.1%	6.4%	6.1%	6.4%
Expected long-term rate of return on assets	8.5%	8.5%	8.5%	8.5%
Rate of compensation increase	4.5%	4.5%	-	-
Medical trend rate	-	-	8.0%	10.0%
Dental trend rate	-	-	5.0%	5.0%

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Plan Assets:

Idaho Power’s pension plan and postretirement benefit plan assets at December 31, by asset category, are as follows:

		Pension				Postretirement
		Plan				Benefits
Asset Category		2009		2008		2009		2008
Cash and cash equivalents		$	4,512	$	4,666	$	-	$	-
Short-term bonds			30,774		36,553		-		-
Core bonds			41,165		46,652		-		-
Equity securities			184,562		152,172		-		-
Real estate			20,783		37,418		-		-
Private market investments			20,202		17,863		-		-
Commodities			11,476		-		-		-
Other⁽¹⁾			-		-		30,892		25,283
	Total	$	313,474	$	295,324	$	30,892	$	25,283
⁽¹⁾ The postretirement benefits assets are primarily life insurance contracts.

Pension Asset Allocation Policy: The target allocation and actual allocations at December 31, 2009 for the portfolio by asset class are as follows:

			Actual
		Target	Allocation
		Allocation	December 31, 2009

Large-cap core stocks		14%	12.2%
Large-cap growth stocks		7%	9.2%
Large-cap value stocks		7%	9.0%
Small-cap growth stocks		5%	4.5%
Small-cap value stocks		5%	5.3%
Micro-cap stocks		3%	3.2%
International growth stocks		7%	7.2%
International value stocks		7%	8.3%
Commodities		3%	3.7%
Private market investments		7%	6.5%
Short-term bonds		10%	9.8%
Core bonds		13%	13.1%
Cash and cash equivalents		3%	1.4%
Real estate		9%	6.6%
	Total	100%	100%

Assets are rebalanced as necessary to keep the portfolio close to target allocations.

The plan’s principal investment objective is to maximize total return (defined as the sum of realized interest and dividend income and realized and unrealized gain or loss in market price) consistent with prudent parameters of risk and the liability profile of the portfolio. Emphasis is placed on preservation and growth of capital along with adequacy of cash flow sufficient to fund current and future payments to pensioners.

There are three major goals in Idaho Power’s asset allocation process:

• Determine if the investments have the potential to earn the rate of return assumed in the actuarial liability calculations.

• Match the cash flow needs of the plan. Idaho Power sets bond allocations sufficient to cover at least five years of benefit payments and cash allocations sufficient to cover the current year benefit payments. Idaho Power then utilizes growth instruments (equities, real estate, venture capital) to fund the longer-term liabilities of the plan.

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• Maintain a prudent risk profile consistent with ERISA fiduciary standards.

• Allowable plan investments include stocks and stock funds, investment-grade bonds and bond funds, core real estate funds, private equity funds, and cash and cash equivalents. With the exception of real estate holdings and private equity, investments must be readily marketable so that an entire holding can be disposed of quickly with only a minor effect upon market price.

Rate-of-return projections for plan assets are based on historical risk/return relationships among asset classes. The primary measure is the historical risk premium each asset class has delivered versus the return on 10-year U.S. Treasury Notes. This historical risk premium is then added to the current yield on 10-year U.S. Treasury Notes, and the result provides a reasonable prediction of future investment performance. Additional analysis is performed to measure the expected range of returns, as well as worst–case and best-case scenarios. Based on the current low interest rate environment, current rate-of-return expectations are lower than the nominal returns generated over the past 20 years when interest rates were generally much higher.

Idaho Power’s asset modeling process also utilizes historical market returns to measure the portfolio’s exposure to a “worst-case” market scenario, to determine how much performance could vary from the expected “average” performance over various time periods. This “worst-case” modeling, in addition to cash flow matching and diversification by asset class and investment style, provides the basis for managing the risk associated with investing portfolio assets.

Fair Value of Plan Assets: Idaho Power classifies its pension plan and postretirement plan investments using the following hierarchy:

• Level 1, which refers to securities valued using quoted prices from active markets for identical assets;

• Level 2, which refers to securities not traded on an active market but for which observable market inputs are readily available; and

• Level 3, which refers to securities valued based on significant unobservable inputs.

If the inputs used to measure the securities fall within different levels of the hierarchy, the categorization is based on the lowest level input (Level 3 being the lowest) that is significant to the fair value measurement of the security. The following table sets forth by level within the fair value hierarchy a summary of the plans’ investments measured at fair value on a recurring basis at December 31.

		Quoted Prices in		Significant		Significant
		Active Markets		Other		Unobservable
		for Identical		Observable		Inputs
		Assets (Level 1)		Inputs (Level 2)		(Level 3)		Total
Assets at December 31, 2009
Pension assets:
Cash and cash equivalents		$	4,512	$	-	$	-	$	4,512
Short-term bonds			30,774		-		-		30,774
Core bonds			41,165		-		-		41,165
Equity securities			126,049		58,513		-		184,562
Real estate			-		-		20,783		20,783
Private market investments			-		-		20,202		20,202
Commodities			-		11,476		-		11,476
	Total pension assets	$	202,500	$	69,989	$	40,985	$	313,474
Postretirement assets		$	-	$	30,892	$	-	$	30,892

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The following table presents a reconciliation of the beginning and ending balances of the fair value measurements using significant unobservable inputs (Level 3):

	Private		Real
	Equity		Estate		Total
Beginning balance - January 1, 2009	$	17,863	$	37,418	$	55,281
Realized losses		(1,040)		(671)		(1,711)
Unrealized gains (losses)		3,103		(14,912)		(11,809)
Purchases, issuances, and settlements, net		276		(1,052)		(776)
Ending balance - December 31, 2009	$	20,202	$	20,783	$	40,985

Employee Savings Plan

Idaho Power has an Employee Savings Plan that complies with Section 401(k) of the Internal Revenue Code and covers substantially all employees. Idaho Power matches specified percentages of employee contributions to the plan. Matching contributions amounted to $5 million in each of 2009, 2008 and 2007.

Post-employment Benefits

Idaho Power provides certain benefits to former or inactive employees, their beneficiaries and covered dependents after employment but before retirement. These benefits include salary continuation, health care and life insurance for those employees found to be disabled under Idaho Power’s disability plans and health care for surviving spouses and dependents. Idaho Power accrues a liability for such benefits. The post employment benefit amounts included in other deferred credits on IDACORP’s and Idaho Power’s consolidated balance sheets at December 31, 2009 and 2008 are $5.2 million and $3.7 million, respectively.

12. PROPERTY PLANT AND EQUIPMENT AND JOINTLY-OWNED PROJECTS:

The following table presents the major classifications of Idaho Power’s utility plant in service, annual depreciation provisions as a percent of average depreciable balance and accumulated provision for depreciation for the years 2009 and 2008 (in thousands of dollars):

		2009			2008
		Balance		Avg Rate	Balance		Avg Rate
Production		$	1,758,813	2.23%	$	1,736,670	2.34%
Transmission			768,260	2.07		742,871	2.11
Distribution			1,331,065	2.89		1,254,048	2.50
General and Other			302,040	7.88		296,545	7.53
	Total in service		4,160,178	2.81%		4,030,134	2.73%
Accumulated provision for depreciation			(1,558,538)			(1,505,120)
	In service - net	$	2,601,640		$	2,525,014

Idaho Power has interests in three jointly-owned generating facilities included in the table above. Under the joint operating agreements, each participating utility is responsible for financing its share of construction, operating and leasing costs. Idaho Power’s proportionate share of direct operation and maintenance expenses applicable to the projects is included in the Consolidated Statements of Income.

These facilities, and the extent of Idaho Power’s participation, were as follows at December 31, 2009 (in thousands of dollars):

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		Utility		Construction		Accumulated
		Plant In		Work in		Provision for		Ownership
Name of Plant	Location	Service		Progress		Depreciation		%	MW⁽¹⁾
Jim Bridger Units 1-4	Rock Springs, WY	$	505,343	$	21,922	$	274,852	33	771
Boardman	Boardman, OR		71,755		630		51,677	10	64
Valmy Units 1 and 2	Winnemucca, NV		334,152		6,040		207,808	50	284
⁽¹⁾Idaho Power share of nameplate capacity

Idaho Power’s wholly-owned subsidiary IERCo, is a joint venturer in Bridger Coal Company, which operates the mine supplying coal to the Jim Bridger generating plant. Idaho Power’s coal purchases from the joint venture were $66 million, $63 million and $51 million 2009, 2008 and 2007, respectively.

Idaho Power has contracts to purchase the energy from four PURPA qualified facilities that are 50 percent owned by Ida-West. Idaho Power’s power purchases from these facilities were $8.7 million in 2009 and $8 million in 2008 and 2007.

See Note 1 for a discussion of the property of IDACORP’s consolidated VIE.

13. ASSET RETIREMENT OBLIGATIONS (ARO):

The guidance relating to accounting for AROs requires that legal obligations associated with the retirement of property, plant and equipment be recognized as a liability at fair value when incurred and when a reasonable estimate of the fair value of the liability can be made. Under the guidance, when a liability is initially recorded, the entity increases the carrying amount of the related long-lived asset to reflect the future retirement cost. Over time, the liability is accreted to its present value and paid, and the capitalized cost is depreciated over the useful life of the related asset. If, at the end of the asset’s life, the recorded liability differs from the actual obligations paid, a gain or loss would be recognized. As a rate-regulated entity, Idaho Power records regulatory assets or liabilities instead of accretion, depreciation and gains or losses, as approved by Order No. 29414 from the IPUC. The regulatory assets recorded under this order do not earn a return on investment.

Idaho Power’s recorded AROs relate to the removal of polychlorinated biphenyls-contaminated equipment at its distribution facilities and the reclamation and removal costs at its jointly owned coal-fired generation facilities. In 2009, changes in estimates at the coal-fired generation facilities resulted in a net increase of $3.7 million in the recorded ARO.

Idaho Power also has AROs associated with its transmission system and hydroelectric facilities; however, due to the indeterminate removal date, the fair value of the associated liabilities currently cannot be estimated and no amounts are recognized in the consolidated financial statements.

The regulated operations of Idaho Power also collect removal costs in rates for certain assets that do not have associated AROs. Idaho Power is required to redesignate these removal costs as regulatory liabilities. Costs recorded as regulatory liabilities on IDACORP’s and Idaho Power’s Consolidated Balance Sheets as of December 31, 2009 and 2008, were $155 million and $157 million, respectively.

The following table presents the changes in the carrying amount of AROs (in thousands of dollars):

		IDACORP				Idaho Power
		2009		2008		2009		2008
Balance at beginning of year		$	12,415	$	14,515	$	12,415	$	14,515
Accretion expense			697		701		697		701
Revisions in estimated cash flows			3,684		(2,627)		3,684		(2,627)
Liability incurred			139		-		139		-
Liability settled			(695)		(174)		(695)		(174)
	Balance at end of year	$	16,240	$	12,415	$	16,240	$	12,415

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14. INVESTMENTS:

The following table summarizes IDACORP’s and Idaho Power’s investments as of December 31 (in thousands of dollars):

				2009		2008
Idaho Power Investments:
		Equity method investment		$	83,969	$	86,433
		Available-for-sale equity securities			18,842		14,451
		Executive deferred compensation plan			5,217		4,679
		Other investments			267		948
			Total Idaho Power investments		108,295		106,511
Investments in affordable housing					77,809		74,951
Equity method investments					9,991		10,030
Held-to-maturity debt securities					-		9,424
Executive deferred compensation plan					1,069		1,225
Other investments					18		66
	Total IDACORP investments			$	197,182	$	202,207

Equity Method Investments

Idaho Power, through its subsidiary IERCo, is a 33 percent owner of Bridger Coal Company, which supplies coal to the Jim Bridger generating plant owned in part by Idaho Power. Ida-West, through separate subsidiaries, owns 50 percent of three electric generation projects: South Forks Joint Venture; Hazelton/Wilson Joint Venture and Snow Mountain Hydro LLC. IFS invests in affordable housing developments. All projects are reviewed periodically for impairment.

The following table presents IDACORP’s and Idaho Power’s earnings (loss) of unconsolidated equity-method investments (in thousands of dollars):

		2009		2008		2007
Bridger Coal Company (Idaho Power)		$	8,256	$	6,772	$	5,553
Ida-West projects			1,933		1,830		1,820
IFS affordable housing projects
	(excluding tax credits)		(11,222)		(12,599)		(12,197)
	Total	$	(1,033)	$	(3,997)	$	(4,824)

Investments in Debt and Equity Securities

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

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

The following table summarizes investments in debt and equity securities (in thousands of dollars):

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		2009						2008
		Gross		Gross				Gross		Gross
		Unrealized		Unrealized		Fair		Unrealized		Unrealized		Fair
		Gain		Loss		Value		Gain		Loss		Value
Available-for-sale
	securities (Idaho Power)	$	2,989	$	-	$	18,842	$	-	$	-	$	14,451
Held-to-maturity debt
	securities (IFS)		-		-		-		3		25		9,448

The following table summarizes sales of available-for-sale securities (in thousands of dollars):

	2009		2008		2007

Proceeds from sales	$	9,006	$	-	$	26,110
Gross realized gains from sales		11		-		2,093
Gross realized losses from sales		35		-		762

These investments are evaluated to determine whether they have experienced a decline in market value that is other-than-temporary. IDACORP and Idaho Power analyze securities in loss positions as of the end of each reporting period. At December 31, 2009, IDACORP and Idaho Power did not have any securities that were in a loss position. At December 31, 2008, four available-for-sale and six held-to-maturity securities were in an unrealized loss position. The available-for-sale equity securities in unrealized loss positions were broadly diversified index funds used to fund Idaho Power’s SMSP. Due to the severity of the losses and the volatility of the market the available-for-sale securities were deemed other-than-temporarily impaired and written down $6.8 million to fair market value at December 31, 2008. The held-to-maturity debt securities were bonds with an aggregate fair value of approximately $4 million and an aggregate unrealized loss of $25 thousand at December 31, 2008. The bonds market values fluctuated based on the interest rate environment. IDACORP and Idaho Power did not recognize any other-than-temporary impairments in 2007.

15. DERIVATIVE FINANCIAL INSTRUMENTS

Commodity Price Risk

Idaho Power is exposed to certain risks relating to its ongoing business operations. The primary risk managed by using derivative instruments is commodity price risk related to Idaho Power’s ongoing utility operations providing electricity to meet the demand of its retail customers. Physical and financial forward contracts for both electricity and fuel used to produce electricity are entered into to manage the price risk associated with meeting forecasted loads. The objective of Idaho Power’s energy purchase and sale activity is to meet the demand of retail electric customers, maintain appropriate physical reserves to ensure reliability and make economic use of temporary surpluses that may develop.

All derivative instruments are recognized as either assets or liabilities at fair value on the balance sheet. Idaho Power’s physical forward contracts qualify for the normal purchases and normal sales exception to derivative accounting requirements with the exception of forward contracts for the purchase of natural gas for use at Idaho Power’s natural gas generation facilities. Because of Idaho Power’s power cost mechanisms, Idaho Power records the changes in fair value of derivative instruments related to power supply as regulatory assets or liabilities.

As of December 31, 2009, Idaho Power had the following outstanding derivative commodity forward contracts that were entered into for the purpose of economically hedging forecasted purchases and sales:

Commodity	Number of Units
Electricity purchases	705,625	MWh
Electricity sales	567,525	MWh
Natural gas	1,356,250	MMBtu
Diesel	901,932	gallons

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The following table presents the fair values of derivatives not designated as hedging instruments recorded in the balance sheet at December 31, 2009 (in thousands of dollars):

			Asset Derivatives			Liability Derivatives
			Balance Sheet	Fair		Balance Sheet	Fair
Commodity derivatives			Location	Value		Location	Value
Current:
	Financial swaps		Other current assets	$	2,931	Other current assets	$	2,087
	Financial swaps		Other current liabilities		9	Other current liabilities		610
	Forward contracts		Other current assets		354	Other current assets		-
Long-term:
	Financial swaps		Other assets		442	Other assets		229
		Total		$	3,736		$	2,926

The following table presents the effect on income of derivatives not designated as hedging instruments for the year ended December 31, 2009 (in thousands of dollars):

		Location of Gain/(Loss)	Amount of Gain/(Loss)
		Recognized in Income on	Recognized in Income on
Commodity derivatives		Derivative	Derivative⁽¹⁾
Year ended December 31, 2009:
	Financial swaps	Off-system sales	$	3,245
	Financial swaps	Purchased power		(3,966)
	Financial swaps	Fuel expense		(5,794)
	Forward contracts	Fuel expense		(986)
⁽¹⁾Excludes changes in fair value of derivatives, which are recorded on the balance sheet as regulatory assets or liabilities.

Idaho Power records changes in fair value of its derivative contracts as either regulatory assets or liabilities. Settlement gains and losses on electricity swap contracts are recorded on the income statement in off-system sales or purchased power depending on the forecasted position being economically hedged by the derivative contract. Settlement gains and losses on both financial and physical contracts for natural gas are reflected in fuel expense. Settlement gains and losses on diesel derivatives, which were immaterial for all three years, are recorded in fuel inventory on the balance sheet.

Credit Risk

At December 31, 2009, Idaho Power does not have material credit exposure from financial instruments, including derivatives. Idaho Power monitors credit risk exposure through reviews of counterparty credit quality, corporate-wide counterparty credit exposure, and corporate-wide counterparty concentration levels. Idaho Power manages these risks by establishing appropriate credit and concentration limits on transactions with counterparties and requiring contractual guarantees, cash deposits or letters of credit from counterparties or their affiliates, as deemed necessary. The majority of Idaho Power’s contracts are under the Western Systems Power Pool agreement that provides for adequate assurances if a counterparty has debt that is downgraded to below investment grade by at least one rating agency. Idaho Power also requires North American Energy Standards Board contracts as necessary for physical gas transactions, and International Swaps and Derivatives Association, Inc. contracts as needed for financial transactions.

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Credit-Contingent Features

Certain of Idaho Power’s derivative instruments contain provisions that require Idaho Power’s unsecured debt to maintain an investment grade credit rating from each of the major credit rating agencies. If Idaho Power’s unsecured debt were to fall below investment grade, it would be in violation of these provisions, and the counterparties to the derivative instruments could request immediate payment or demand immediate and ongoing full overnight collateralization on derivative instruments in net liability positions. The aggregate fair value of all derivative instruments with credit-risk-related contingent features that are in a liability position on December 31, 2009, is $2.9 million. Idaho Power has posted $1.3 million collateral related to this amount. If the credit-risk-related contingent features underlying these agreements were triggered on December 31, 2009, Idaho Power could have been required to post $0.5 million of cash collateral to its counterparties.

16. FAIR VALUE MEASUREMENTS:

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

Financial assets and liabilities recorded on the Consolidated Balance Sheets are categorized based on the inputs to the valuation techniques as follows:

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

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

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

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

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

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

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

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

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

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The following tables present information about IDACORP’s and Idaho Power’s assets and liabilities measured at fair value on a recurring basis (in thousands of dollars). IDACORP’s and Idaho Power’s assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy. Please see Note 11 for fair value information regarding IDACORP’s and Idaho Power’s benefit plans.

			Quoted Prices in		Significant			Significant
			Active Markets		Other			Unobservable
			for Identical		Observable			Inputs
			Assets (Level 1)		Inputs (Level 2)			(Level 3)		Total
2009
IDACORP
Assets:
	Derivatives		$	1,056		$	354	$	-	$	1,410
	Money market funds			38,221			-		-		38,221
	Trading securities			6,286			-		-		6,286
	Available-for-sale equity securities			18,842			-		-		18,842
Liabilities:
		Derivatives		(601)			-		-		(601)
Idaho Power
Assets:
	Derivatives		$	1,056		$	354	$	-	$	1,410
	Money market funds			19,364			-		-		19,364
	Trading securities			5,217			-		-		5,217
	Available-for-sale equity securities			18,842			-		-		18,842
Liabilities:
		Derivatives		(601)			-		-		(601)

2008
IDACORP
Assets:
	Derivatives		$	652		$	-	$	-	$	652
	Money market funds			4,610			-		-		4,610
	Trading securities			5,904			-		-		5,904
	Available-for-sale equity securities			14,451			-		-		14,451
Liabilities:
		Derivatives		-			(2,653)		-		(2,653)
Idaho Power
Assets:
	Derivatives		$	652		$	-	$	-	$	652
	Money market funds			1,224			-		-		1,224
	Trading securities			4,679			-		-		4,679
	Available-for-sale equity securities			14,451			-		-		14,451
Liabilities:
		Derivatives		-			(2,653)		-		(2,653)

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

	December 31, 2009				December 31, 2008
	Carrying		Estimated		Carrying		Estimated
	Amount		Fair Value		Amount		Fair Value
	(thousands of dollars)
IDACORP
Assets:
Notes receivable	$	2,946	$	2,946	$	5,703	$	5,726
Liabilities:
Long-term debt		1,422,130		1,406,815		1,277,042		1,199,699

Idaho Power
Assets:
Notes receivable	$	-	$	-	$	259	$	282
Liabilities:
Long-term debt		1,413,854		1,398,681		1,268,818		1,191,476

17. SEGMENT INFORMATION:

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

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

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

	Utility		All				Consolidated
	Operations		Other		Eliminations		Total
2009
Revenues	$	1,045,996	$	3,804	$	-	$	1,049,800
Operating income		206,193		(2,610)		-		203,583
Other income		10,704		1,227		-		11,931
Interest income		4,859		490		(283)		5,066
Equity method income (loss)		8,256		(9,289)		-		(1,033)
Interest expense		71,932		1,161		(283)		72,810
Income (loss) before income taxes		158,080		(11,343)		-		146,737
Income tax expense (benefit)		35,521		(13,159)		-		22,362
Income attributable to IDACORP, Inc.		122,559		1,791		-		124,350
Total assets		4,073,390		192,699		(27,362)		4,238,727
Expenditures for long-lived assets		251,937		14		-		251,951
2008
Revenues	$	956,076	$	4,338	$	-	$	960,414
Operating income		189,375		1,292		-		190,667
Other income (loss)		2,124		(1,912)		-		212
Interest income		2,929		1,582		(892)		3,619
Equity method income (loss)		6,772		(10,769)		-		(3,997)
Interest expense		69,485		4,463		(892)		73,056
Income (loss) before income taxes		131,715		(14,270)		-		117,445
Income tax expense (benefit)		37,600		(18,400)		-		19,200
Income attributable to IDACORP, Inc.		94,115		4,299		-		98,414
Total assets		3,884,856		164,339		(26,350)		4,022,845
Expenditures for long-lived assets		243,544		273		-		243,817
2007
Revenues	$	875,401	$	3,993	$	-	$	879,394
Operating income (loss)		154,777		(2,699)		-		152,078
Other income (loss)		7,436		(368)		-		7,068
Interest income		2,980		3,126		(1,553)		4,553
Equity method income (loss)		5,553		(10,377)		-		(4,824)
Interest expense		58,781		6,113		(1,553)		63,341
Income (loss) before income taxes		111,965		(16,431)		-		95,534
Income tax expense (benefit)		35,386		(21,655)		-		13,731
Income attributable to IDACORP, Inc.		76,579		5,760		-		82,339
Total assets		3,489,516		235,636		(71,844)		3,653,308
Expenditures for long-lived assets		287,219		46		-		287,265

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18. OTHER INCOME AND EXPENSE:

The following table presents the components of Other income and Other expense (in thousands of dollars):

		2009		2008		2007
Other income:
Allowance for funds used during construction-equity		$	7,555	$	3,141	$	5,995
Investment income, net			5,071		(5,273)		6,855
Carrying charges			4,471		6,709		3,437
Other			3,967		7,284		4,237
	Total	$	21,064	$	11,861	$	20,524

Other expense:
SMSP expense		$	5,355	$	4,628	$	4,520
Life Insurance, net of proceeds			(4,197)		(381)		(200)
Other			2,909		3,783		4,583
	Total	$	4,067	$	8,030	$	8,903

19. RELATED PARTY TRANSACTIONS (Idaho Power):

IDACORP

Idaho Power performs corporate functions such as financial, legal and management services for IDACORP and its subsidiaries. Idaho Power charges IDACORP for the costs of these services based on service agreements and other specifically identified costs. For these services Idaho Power billed IDACORP $0.9 million, $1 million and $2 million in 2009, 2008 and 2007, respectively.

Ida-West

Idaho Power purchases all of the power generated by four of Ida-West’s hydroelectric projects located in Idaho. Idaho Power paid $8.7 million in 2009 and $8 million in each of 2008 and 2007.

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

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

We have audited the accompanying consolidated balance sheets of IDACORP, Inc. and subsidiaries (the “Company”) as of December 31, 2009 and 2008, and the related consolidated statements of income, comprehensive income, equity, and cash flows for each of the three years in the period ended December 31, 2009. Our audits also included the financial statement schedules listed in the Index at Item 8. These financial statements and financial statement schedules are the responsibility of the Company’s management. Our responsibility is to express an opinion on the financial statements and financial statement schedules based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of IDACORP, Inc. and subsidiaries at December 31, 2009 and 2008, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2009, in conformity with accounting principles generally accepted in the United States of America. Also, in our opinion, such financial statement schedules, when considered in relation to the basic consolidated financial statements taken as a whole, present fairly, in all material respects, the information set forth therein.

As discussed in Note 1 to the consolidated financial statements, the accompanying 2008 consolidated balance sheet and 2008 and 2007 consolidated statements of income have been retrospectively adjusted for the adoption of accounting guidance for noncontrolling interests in consolidated financial statements and as discussed in Note 2 to the consolidated financial statements, the Company adopted guidance for accounting for uncertainty in income taxes on January 1, 2007.

We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the Company’s internal control over financial reporting as of December 31, 2009, based on the criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated February 23, 2010 expressed an unqualified opinion on the Company’s internal control over financial reporting.

/s/ DELOITTE & TOUCHE LLP

Boise, Idaho
February 23, 2010

119

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Shareholder of Idaho Power Company
Boise, Idaho

We have audited the accompanying consolidated balance sheets and statements of capitalization of Idaho Power Company and subsidiary (the “Company”) as of December 31, 2009 and 2008, and the related consolidated statements of income, comprehensive income, retained earnings, and cash flows for each of the three years in the period ended December 31, 2009. Our audits also included the financial statement schedule listed in the Index at Item 8. These financial statements and financial statement schedule are the responsibility of the Company’s management. Our responsibility is to express an opinion on the financial statements and financial statement schedule based on our audits.

In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of Idaho Power Company and subsidiary at December 31, 2009 and 2008, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2009, in conformity with accounting principles generally accepted in the United States of America. Also, in our opinion, such financial statement schedule, when considered in relation to the basic consolidated financial statements taken as a whole, presents fairly, in all material respects, the information set forth therein.

As discussed in Note 2 to the consolidated financial statements, the Company adopted guidance for accounting for uncertainty in income taxes on January 1, 2007.

/s/ DELOITTE & TOUCHE LLP

Boise, Idaho
February 23, 2010

120

SUPPLEMENTAL FINANCIAL INFORMATION, UNAUDITED

QUARTERLY FINANCIAL DATA:

The following unaudited information is presented for each quarter of 2009 and 2008 (in thousands of dollars except for per share amounts). In the opinion of each company, all adjustments necessary for a fair statement of such amounts for such periods have been included. The results of operations for the interim periods are not necessarily indicative of the results to be expected for the full year. Accordingly, earnings information for any three-month period should not be considered as a basis for estimating operating results for a full fiscal year. Amounts are based upon quarterly statements and the sum of the quarters may not equal the annual amount reported.

	Quarter Ended
	March 31			June 30		September 30		December 31
IDACORP, Inc.
2009
Revenues	$	228,574	$	243,634	$	324,509	$	253,083
Operating income		35,634		49,472		79,603		38,873
Net income		18,686		27,570		54,707		23,412
Net income attributable to IDACORP, Inc.		18,884		27,475		54,478		23,513
Basic earnings per share		0.40		0.59		1.16		0.49
Diluted earnings per share		0.40		0.58		1.16		0.49

2008
Revenues	$	213,440	$	230,226	$	299,716	$	217,032
Operating income		44,756		40,529		81,577		23,805
Net income		21,405		17,555		51,912		7,373
Net income attributable to IDACORP, Inc.		21,716		17,515		51,739		7,444
Basic earnings per share		0.48		0.39		1.15		0.16
Diluted earnings per share		0.48		0.39		1.14		0.16

Idaho Power Company
2009
Revenues	$	228,029	$	242,518	$	323,128	$	252,321
Income from operations		35,713		49,228		80,101		41,152
Net income		19,284		26,326		51,057		25,892

2008
Revenues	$	212,796	$	228,945	$	298,107	$	216,228
Income from operations		45,160		40,388		81,112		22,715
Net income		21,271		17,728		47,405		7,711

Operating income and net income were decreased in the fourth quarter of 2008 by $7.4 million following a decision received from the FERC increasing the OATT refund, and $6.8 million other-than-temporary impairment of diversified index funds due to the decline in market value.

ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE

None

ITEM 9A. CONTROLS AND PROCEDURES

Disclosure controls and procedures:

121

IDACORP:

The Chief Executive Officer and Chief Financial Officer of IDACORP, based on their evaluation of IDACORP’s disclosure controls and procedures (as defined in Exchange Act Rule 13a-15(e)) as of December 31, 2009, have concluded that IDACORP’s disclosure controls and procedures are effective.

Idaho Power:

The Chief Executive Officer and Chief Financial Officer of Idaho Power, based on their evaluation of Idaho Power’s disclosure controls and procedures (as defined in Exchange Act Rule 13a-15(e)) as of December 31, 2009, have concluded that Idaho Power’s disclosure controls and procedures are effective.

Internal control over financial reporting:

IDACORP:

Management’s Annual Report on Internal Control Over Financial Reporting

The management of IDACORP is responsible for establishing and maintaining adequate internal control over financial reporting for IDACORP. Internal control over financial reporting is defined in Rule 13a-15(f) promulgated under the Securities Exchange Act of 1934 as a process designed by, or under the supervision of, the company’s principal executive and principal financial officers and effected by the company’s board of directors, management and other personnel, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with accounting principles generally accepted in the United States of America and includes those policies and procedures that:

• Pertain to the maintenance of records that in reasonable detail accurately and fairly reflect the transactions and dispositions of the assets of the company;

• Provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with accounting principles generally accepted in the United States of America, and that receipts and expenditures of the company are being made only in accordance with the authorizations of management and directors of the company; and

• Provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of the company’s assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

IDACORP’s management assessed the effectiveness of the company’s internal control over financial reporting as of December 31, 2009. In making this assessment, the company’s management used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission in Internal Control-Integrated Framework.

Based on its assessment, management believes that, as of December 31, 2009 IDACORP’s internal control over financial reporting is effective based on those criteria.

IDACORP’s independent registered public accounting firm has audited the financial statements included in this Annual Report on Form 10-K for the year ended December 31, 2009 and issued a report, which appears on the next page and expresses an unqualified opinion on the effectiveness of IDACORP’s internal control over financial reporting as of December 31, 2009.

February 23, 2010

122

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

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

We have audited the internal control over financial reporting of IDACORP, Inc. and subsidiaries (the “Company”) as of December 31, 2009, based on the criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Annual Report on Internal Control over Financial Reporting. Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit.

We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.

A company’s internal control over financial reporting is a process designed by, or under the supervision of, the company’s principal executive and principal financial officers, or persons performing similar functions, and effected by the company’s board of directors, management, and other personnel to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

Because of the inherent limitations of internal control over financial reporting, including the possibility of collusion or improper management override of controls, material misstatements due to error or fraud may not be prevented or detected on a timely basis. Also, projections of any evaluation of the effectiveness of the internal control over financial reporting to future periods are subject to the risk that the controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

In our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2009, based on the criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission.

We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated financial statements and financial statement schedules as of and for the year ended December 31, 2009 of the Company and our report dated February 23, 2010 expressed an unqualified opinion on those financial statements and financial statement schedules and included an explanatory paragraph regarding the Company’s adoption of accounting guidance for noncontrolling interests in consolidated financial statements..

/s/ DELOITTE & TOUCHE LLP

123

Boise, Idaho
February 23, 2010

Idaho Power Company:

Management’s Annual Report on Internal Control Over Financial Reporting

The management of Idaho Power Company (Idaho Power) is responsible for establishing and maintaining adequate internal control over financial reporting of Idaho Power. Internal control over financial reporting is defined in Rule 13a-15(f) promulgated under the Securities Exchange Act of 1934 as a process designed by, or under the supervision of, the company’s principal executive and principal financial officers and effected by the company’s board of directors, management and other personnel, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with accounting principles generally accepted in the United States of America and includes those policies and procedures that:

• Pertain to the maintenance of records that in reasonable detail accurately and fairly reflect the transactions and dispositions of the assets of the company;

Idaho Power’s management assessed the effectiveness of the company’s internal control over financial reporting as of December 31, 2009. In making this assessment, the company’s management used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission in Internal Control-Integrated Framework.

Based on its assessment, management believes that, as of December 31, 2009, Idaho Power’s internal control over financial reporting is effective based on those criteria.

Idaho Power’s independent registered public accounting firm has audited the financial statements included in this Annual Report on Form 10-K for the year ended December 31, 2009 and issued a report, which appears on the next page and expresses an unqualified opinion on the effectiveness of Idaho Power’s internal control over financial reporting as of December 31, 2009.

February 23, 2010

124

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Shareholder of Idaho Power Company
Boise, Idaho

We have audited the internal control over financial reporting of Idaho Power Company and subsidiary (the “Company”) as of December 31, 2009, based on the criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Annual Report on Internal Control over Financial Reporting. Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit.

We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated financial statements and financial statement schedule as of and for the year ended December 31, 2009 of the Company and our report dated February 23, 2010 expressed an unqualified opinion on those financial statements and financial statement schedule.

/s/ DELOITTE & TOUCHE LLP

Boise, Idaho
February 23, 2010

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Changes in Internal Control Over Financial Reporting
There have been no changes in IDACORP’s or Idaho Power’s internal control over financial reporting during the quarter ended December 31, 2009, requiring disclosure that have materially affected, or are reasonably likely to materially affect, IDACORP’s or Idaho Power’s internal control over financial reporting.

ITEM 9B. OTHER INFORMATION

PART III

ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE

The portion of IDACORP’s definitive proxy statement appearing under the captions “Proposal No. 1: Election of Directors - Nominees for Election - Terms Expire 2013,” “Continuing Directors – Terms Expire 2012,” “Continuing Directors - Terms Expire 2011,” “Section 16(a) Beneficial Ownership Reporting Compliance,” “Corporate Governance - Audit Committee,” paragraph 1 and “Corporate Governance - Code of Ethics,” to be filed pursuant to Regulation 14A for the Annual Meeting of Shareholders to be held on May 20, 2010 is hereby incorporated by reference.

ITEM 11. EXECUTIVE COMPENSATION

The portion of IDACORP’s definitive proxy statement appearing under the caption “Executive Compensation” to be filed pursuant to Regulation 14A for the Annual Meeting of Shareholders to be held on May 20, 2010 is hereby incorporated by reference.

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ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS

The portion of IDACORP’s definitive proxy statement appearing under the caption “Security Ownership of Directors, Executive Officers and Five Percent Shareholders” to be filed pursuant to Regulation 14A for the Annual Meeting of Shareholders to be held on May 20, 2010 is hereby incorporated by reference.

The following table includes information as of December 31, 2009, with respect to equity compensation plans where equity securities of IDACORP may be issued. These plans are the 1994 Restricted Stock Plan (RSP), the IDACORP 2000 Long-Term Incentive and Compensation Plan (LTICP) and the Non-Employee Director Stock Compensation Plan (DSP).

			(a)	(b)		(c)
						Number of securities
						remaining available for
			Number of securities to	Weighted-average		future issuance under
			be issued upon exercise	exercise price of		equity compensation
			of outstanding options,	outstanding options,		plans (excluding securities
Plan Category			warrants and rights	warrants and rights		reflected in column (a))
Equity compensation
	plans approved by
	shareholders (1)		616,003	$	34.27	1,627,774 (2)(3)
Equity compensation
	plans not approved
	by shareholders(4)		-	$	-	13,927
		Total	616,003	$	34.27	1,641,701
⁽¹⁾ Consists of the RSP and the LTICP.
(2⁾ In addition to being available for future issuance upon exercise of options, 1,602,259 shares under the LTICP may instead be issued in connection with stock appreciation rights, restricted stock, restricted stock units, performance units, performance shares or other equity-based awards.
(3) 25,515 shares remain available for future issuance under the RSP.
(4) Consists of shares available for future issuance under the DSP.

Equity Compensation Plans Not Approved by IDACORP Shareholders:

The DSP was adopted by the Board of Directors effective May 17, 1999. The purpose of the DSP is to increase directors’ stock ownership through stock-based compensation. The DSP provides for an annual stock grant valued at $45,000. Effective January 1, 2009, directors may defer their annual stock awards, which are then held as deferred stock units with dividend equivalents reinvested in additional stock units.

ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE

The portion of IDACORP’s definitive proxy statement appearing under the captions “Related Person Transaction Disclosure” and “Corporate Governance – Director Independence” paragraphs 1 and 2 to be filed pursuant to Regulation 14A for the Annual Meeting of Shareholders to be held on May 20, 2010 is hereby incorporated by reference.

ITEM 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES

IDACORP:

The portion of IDACORP’s definitive proxy statement appearing under the caption “Independent Accountant Billings” in the proxy statement to be filed pursuant to Regulation 14A for the Annual Meeting of Shareholders to be held on May 20, 2010 is hereby incorporated by reference.

127

Idaho Power:

The following table presents fees billed for professional services rendered by Deloitte & Touche LLP, the member firms of Deloitte Touche Tohmatsu, and their respective affiliates (collectively, Deloitte Entities), for Idaho Power for the fiscal years ended December 31, 2009 and 2008.

		2009		2008
Audit fees		$	1,000,059	$	1,037,923
Audit-related fees⁽¹⁾			62,790		59,800
Tax fees⁽²⁾			304,118		138,606
All other fees ⁽³⁾			2,000		2,000
	Total	$	1,368,967	$	1,238,329
⁽¹⁾Includes fees for audits of Idaho Power’s benefit plans.
⁽²⁾ Includes fees for benefit plan tax returns and consultation related to uniform capitalization and repairs tax accounting.
⁽³⁾ Accounting research tool subscription.

Policy on Audit Committee Pre-Approval

Idaho Power and the Audit Committee are committed to ensuring the independence of the independent registered public accounting firm, both in fact and in appearance. In this regard, on February 4, 2004, the Audit Committee established a pre-approval policy in accordance with applicable securities rules. All fees were pre-approved by the Audit Committee in 2008 and 2009.

In addition to the audits of Idaho Power’s consolidated financial statements, the independent public accounting firm may be engaged to provide certain audit-related, tax and other services. The Audit Committee must pre-approve all services performed by the independent public accounting firm to assure that the provision of those services does not impair the public accounting firm’s independence. The services that the Audit Committee will consider include audit services such as attest services, changes in the scope of the audit of the financial statements, and the issuance of comfort letters and consents in connection with financings; audit-related services such as internal control reviews and assistance with internal control reporting requirements; attest services related to financial reporting that are not required by statute or regulation, and accounting consultations and audits related to proposed transactions and new or proposed accounting rules, standards and interpretations; and tax compliance and planning services. Unless a type of service to be provided by the independent public accounting firm has received general pre-approval, it will require specific pre-approval by the Audit Committee. In addition, any proposed services exceeding pre-approved cost levels will require specific pre-approval by the Audit Committee. Under the pre-approval policy, the Audit Committee has delegated to the Chairman of the Audit Committee pre-approval authority for proposed tax, audit and audit-related services. The Chairman must report any pre-approval decisions to the Audit Committee at its next scheduled meeting.

Any request to engage the independent public accounting firm to provide a service which has not received general pre-approval must be submitted as a written proposal to Idaho Power’s Chief Financial Officer with a copy to the General Counsel. The request must include a detailed description of the service to be provided, the proposed fee and the business reasons for engaging the independent public accounting firm to provide the service. Upon approval by the Chief Financial Officer, the General Counsel and the independent public accounting firm that the proposed engagement complies with the terms of the pre-approval policy and the applicable rules and regulations, the request will be presented to the Audit Committee or the Committee Chairman, as the case may be, for pre-approval.

In determining whether to pre-approve the engagement of the independent public accounting firm, the Audit Committee or the Committee Chairman, as the case may be, must consider, among other things, the pre-approval policy, applicable rules and regulations and whether the nature of the engagement and the related fees are consistent with the following principles, as stated in the SEC’s adopting release for the rules on auditor independence:

• the independent public accounting firm cannot function in the role of management of Idaho Power;

• the independent public accounting firm cannot audit its own work; and

• the independent public accounting firm cannot serve in any advocacy role on behalf of Idaho Power.

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The appendices to the pre-approval policy describe the specific audit, audit related, tax and other services that have the general pre-approval of the Audit Committee. The term of any pre-approval is 12 months from the date of pre-approval, unless the Audit Committee specifically provides for a different period. The Audit Committee will periodically revise the list of pre-approved services, based on subsequent determinations.

PART IV

ITEM 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES

(1) and (2) Please refer to Part II, Item 8 - “Financial Statements and Supplementary Data” for a complete listing of all consolidated financial statements and financial statement schedules.

(3) Exhibits.

*Previously Filed and Incorporated Herein by Reference

129

*2	Agreement and Plan of Exchange between IDACORP, Inc., and Idaho Power dated as of February 2, 1998. File number 333-48031, Form S-4, filed on 3/16/98, as Exhibit 2.

*3.1	Restated Articles of Incorporation of Idaho Power as filed with the Secretary of State of Idaho on June 30, 1989. File number 33-00440, Post-Effective Amendment No. 2 to Form S-3, filed on 6/30/89, as Exhibit 4(a)(xiii).

*3.2	Statement of Resolution Establishing Terms of Flexible Auction Series A, Serial Preferred Stock, Without Par Value (cumulative stated value of $100,000 per share) of Idaho Power, as filed with the Secretary of State of Idaho on November 5, 1991. File number 33-65720, Form S-3, filed on 7/7/93, as Exhibit 4(a)(ii).

*3.3	Statement of Resolution Establishing Terms of 7.07% Serial Preferred Stock, Without Par Value (cumulative stated value of $100 per share) of Idaho Power, as filed with the Secretary of State of Idaho on June 30, 1993. File number 33-65720, Form S-3, filed on 7/7/93, as Exhibit 4(a)(iii).

*3.4	Articles of Amendment to Restated Articles of Incorporation of Idaho Power, as filed with the Secretary of State of Idaho on June 15, 2000. File number 1-3198, Form 10-Q for the quarter ended June 30, 2000, filed on 8/4/00, as Exhibit 3(a)(iii).

*3.5	Articles of Amendment to Restated Articles of Incorporation of Idaho Power Company, as filed with the Secretary of State of Idaho on January 21, 2005. File number 1-3198, Form 8-K, filed on 1/26/05, as Exhibit 4.5.

*3.6	Articles of Amendment to Restated Articles of Incorporation of Idaho Power, as amended, as filed with the Secretary of State of Idaho on November 19, 2007. File number 1-3198, Form 8-K, filed on 11/19/07, as Exhibit 3.3.

*3.7	Articles of Share Exchange, as filed with the Secretary of State of Idaho on September 29, 1998. File number 33-56071-99, Post-Effective Amendment No. 1 to Form S-8, filed on 10/1/98, as Exhibit 3(d).

*3.8	Amended Bylaws of Idaho Power, amended on November 15, 2007, and presently in effect. File number 1-3198, Form 8-K, filed on 11/19/07, as Exhibit 3.2.

*3.9	Articles of Incorporation of IDACORP, Inc. File number 333-64737, Amendment No. 1 to Form S-3, filed on 11/4/98, as Exhibit 3.1.

*3.10	Articles of Amendment to Articles of Incorporation of IDACORP, Inc. as filed with the Secretary of State of Idaho on March 9, 1998. File number 333-64737, Amendment No. 1 to Form S-3, filed on 11/4/98, as Exhibit 3.2.

*3.11	Articles of Amendment to Articles of Incorporation of IDACORP, Inc. creating A Series Preferred Stock, without par value, as filed with the Secretary of State of Idaho on September 17, 1998. File number 333-00139-99, Post-Effective Amendment No. 1 to Form S-3, filed on 9/22/98, as Exhibit 3(b).

*3.12	Amended Bylaws of IDACORP, Inc., amended on November 15, 2007 and presently in effect. File number 1-14456, Form 8-K, filed on 11/19/07, as Exhibit 3.1.

*4.1	Mortgage and Deed of Trust, dated as of October 1, 1937, between Idaho Power and Deutsche Bank Trust Company Americas (formerly known as Bankers Trust Company) and R. G. Page, as Trustees. File number 2-3413, as Exhibit B-2.

*4.2	Idaho Power Supplemental Indentures to Mortgage and Deed of Trust:
	File number 1-MD, as Exhibit B-2-a, First, July 1, 1939
	File number 2-5395, as Exhibit 7-a-3, Second, November 15, 1943
	File number 2-7237, as Exhibit 7-a-4, Third, February 1, 1947
	File number 2-7502, as Exhibit 7-a-5, Fourth, May 1, 1948
	File number 2-8398, as Exhibit 7-a-6, Fifth, November 1, 1949
	File number 2-8973, as Exhibit 7-a-7, Sixth, October 1, 1951
	File number 2-12941, as Exhibit 2-C-8, Seventh, January 1, 1957
	File number 2-13688, as Exhibit 4-J, Eighth, July 15, 1957
	File number 2-13689, as Exhibit 4-K, Ninth, November 15, 1957
	File number 2-14245, as Exhibit 4-L, Tenth, April 1, 1958
	File number 2-14366, as Exhibit 2-L, Eleventh, October 15, 1958
	File number 2-14935, as Exhibit 4-N, Twelfth, May 15, 1959
	File number 2-18976, as Exhibit 4-O, Thirteenth, November 15, 1960
	File number 2-18977, as Exhibit 4-Q, Fourteenth, November 1, 1961
	File number 2-22988, as Exhibit 4-B-16, Fifteenth, September 15, 1964
	File number 2-24578, as Exhibit 4-B-17, Sixteenth, April 1, 1966
	File number 2-25479, as Exhibit 4-B-18, Seventeenth, October 1, 1966
	File number 2-45260, as Exhibit 2(c), Eighteenth, September 1, 1972
	File number 2-49854, as Exhibit 2(c), Nineteenth, January 15, 1974
	File number 2-51722, as Exhibit 2(c)(i), Twentieth, August 1, 1974
	File number 2-51722, as Exhibit 2(c)(ii), Twenty-first, October 15, 1974
	File number 2-57374, as Exhibit 2(c), Twenty-second, November 15, 1976
	File number 2-62035, as Exhibit 2(c), Twenty-third, August 15, 1978
	File number 33-34222, as Exhibit 4(d)(iii), Twenty-fourth, September 1, 1979
	File number 33-34222, as Exhibit 4(d)(iv), Twenty-fifth, November 1, 1981
	File number 33-34222, as Exhibit 4(d)(v), Twenty-sixth, May 1, 1982
	File number 33-34222, as Exhibit 4(d)(vi), Twenty-seventh, May 1, 1986
	File number 33-00440, as Exhibit 4(c)(iv), Twenty-eighth, June 30, 1989
	File number 33-34222, as Exhibit 4(d)(vii), Twenty-ninth, January 1, 1990
	File number 33-65720, as Exhibit 4(d)(iii), Thirtieth, January 1, 1991
	File number 33-65720, as Exhibit 4(d)(iv), Thirty-first, August 15, 1991
	File number 33-65720, as Exhibit 4(d)(v), Thirty-second, March 15, 1992
	File number 33-65720, as Exhibit 4(d)(vi), Thirty-third, April 1, 1993
	File number 1-3198, Form 8-K, filed on 12/20/93, as Exhibit 4, Thirty-fourth, December 1, 1993
	File number 1-3198, Form 8-K, filed on 11/21/00, as Exhibit 4, Thirty-fifth, November 1, 2000
	File number 1-3198, Form 8-K, filed on 10/1/01, as Exhibit 4, Thirty-sixth, October 1, 2001
	File number 1-3198, Form 8-K, filed on 4/16/03, as Exhibit 4, Thirty-seventh, April 1, 2003
	File number 1-3198, Form 10-Q for the quarter ended June 30, 2003, filed on 8/7/03, as Exhibit 4(a)(iii), Thirty-eighth, May 15, 2003
	File number 1-3198, Form 10-Q for the quarter ended September 30, 2003, filed on 11/6/03, as Exhibit 4(a)(iii), Thirty-ninth, October 1, 2003
	File number 1-3198, Form 8-K filed on 5/10/05, as Exhibit 4, Fortieth, May 1, 2005
	File number 1-3198, Form 8-K filed on 10/10/06, as Exhibit 4, Forty-first, October 1, 2006
	File number 1-3198, Form 8-K filed on 6/4/07, as Exhibit 4, Forty-second, May 1, 2007
	File number 1-3198, Form 8-K filed on 9/26/07, as Exhibit 4, Forty-third, September 1, 2007
	File number 1-3198, Form 8-K filed on 4/3/08, as Exhibit 4, Forty-fourth, April 1, 2008

*4.3	Instruments relating to Idaho Power American Falls bond guarantee (see Exhibit 10.4). File number 1-3198, Form 10-Q for the quarter ended June 30, 2000, filed on 8/4/00, as Exhibit 4(b).

*4.4	Agreement of Idaho Power to furnish certain debt instruments. File number 33-65720, Form S-3, filed on 7/7/93, as Exhibit 4(f).

*4.5	Agreement of IDACORP, Inc. to furnish certain debt instruments. File number 1-14465, Form 10-Q for the quarter ended September 30, 2003, filed on 11/6/03, as Exhibit 4(c)(ii).

*4.6	Agreement and Plan of Merger dated March 10, 1989, between Idaho Power Company, a Maine Corporation, and Idaho Power Migrating Corporation. File number 33-00440, Post-Effective Amendment No. 2 to Form S-3, filed on 6/30/89, as Exhibit 2(a)(iii).

*4.7	Indenture for Senior Debt Securities dated as of February 1, 2001, between IDACORP, Inc. and Deutsche Bank Trust Company Americas (formerly known as Bankers Trust Company), as trustee. File number 1-14465, Form 8-K, filed on 2/28/01, as Exhibit 4.1.

*4.8	First Supplemental Indenture dated as of February 1, 2001 to Indenture for Senior Debt Securities dated as of February 1, 2001 between IDACORP, Inc. and Deutsche Bank Trust Company Americas (formerly known as Bankers Trust Company), as trustee. File number 1-14465, Form 8-K, filed on 2/28/01, as Exhibit 4.2.

*4.9	Indenture for Debt Securities dated as of August 1, 2001 between Idaho Power Company and Deutsche Bank Trust Company Americas (formerly known as Bankers Trust Company), as trustee. File number 333-67748, Form S-3, filed on 8/16/01, as Exhibit 4.13.

4.10	Forty-fifth Supplemental Indenture to Mortgage and Deed of Trust, dated as of February 1, 2010.

*10.1	Agreements, dated September 22, 1969, between Idaho Power and Pacific Power & Light Company relating to the operation, construction and ownership of the Jim Bridger Project. File number 2-49584, as Exhibit 5(b).

*10.2	Amendment, dated February 1, 1974, relating to operation agreement filed as Exhibit 10.1. File number 2-51762, as Exhibit 5(c).

*10.3	Agreement, dated as of October 11, 1973, between Idaho Power and Pacific Power & Light Company. File number 2-49584, as Exhibit 5(c).

*10.4	Guaranty Agreement, dated April 11, 2000, between Idaho Power and Bank One Trust Company, N.A., as Trustee, relating to $19,885,000 American Falls Replacement Dam Refinancing Bonds of the American Falls Reservoir District, Idaho. File number 1-3198, Form 10-Q for the quarter ended June 30, 2000, filed on 8/4/00, as Exhibit 10(c).

*10.5	Guaranty Agreement, dated as of August 30, 1974, between Idaho Power and Pacific Power & Light Company. File number 2-62034, Form S-7, filed on 6/30/78, as Exhibit 5(r).

*10.6	Letter Agreement, dated January 23, 1976, between Idaho Power and Portland General Electric Company. File number 2-56513, as Exhibit 5(i).

*10.7	Agreement for Construction, Ownership and Operation of the Number One Boardman Station on Carty Reservoir, dated as of October 15, 1976, between Portland General Electric Company and Idaho Power. File number 2-62034, Form S-7, filed on 6/30/78, as Exhibit 5(s).

*10.8	Amendment, dated September 30, 1977, relating to agreement filed as Exhibit 10.6. File number 2-62034, Form S-7, filed on 6/30/78, as Exhibit 5(t).

*10.9	Amendment, dated October 31, 1977, relating to agreement filed as Exhibit 10.6. File number 2-62034, Form S-7, filed on 6/30/78, as Exhibit 5(u).

*10.10	Amendment, dated January 23, 1978, relating to agreement filed as Exhibit 10.6. File number 2-62034, Form S-7, filed on 6/30/78, as Exhibit 5(v).

*10.11	Amendment, dated February 15, 1978, relating to agreement filed as Exhibit 10.6. File number 2-62034, Form S-7, filed on 6/30/78, as Exhibit 5(w).

*10.12	Amendment, dated September 1, 1979, relating to agreement filed as Exhibit 10.6. File number 2-68574, Form S-7, filed on 7/23/80, as Exhibit 5(x).

*10.13	Participation Agreement, dated September 1, 1979, relating to the sale and leaseback of coal handling facilities at the Number One Boardman Station on Carty Reservoir. File number 2-68574, Form S-7, filed on 7/23/80, as Exhibit 5(z).

*10.14	Agreements for the Operation, Construction and Ownership of the North Valmy Power Plant Project, dated December 12, 1978, between Sierra Pacific Power Company and Idaho Power. File number 2-64910, Form S-7, filed on 6/29/79, as Exhibit 5(y).

*10.15¹	Idaho Power Company Security Plan for Senior Management Employees I, amended and restated effective December 31, 2004, and as further amended November 20, 2008. File number 1-14465, 1-3198, Form 10-K for the year ended December 31, 2008, filed on 2/26/09, as Exhibit 10.15.

10.16¹	Idaho Power Company Security Plan for Senior Management Employees II, effective January 1, 2005, as amended and restated November 19, 2009.

*10.17¹	IDACORP, Inc. Restricted Stock Plan, as amended and restated September 20, 2007. File number 1-14465, 1-3198, Form 10-Q for the quarter ended September 30, 2007, filed on 10/31/07, as Exhibit 10(h)(iii).

*10.18¹	IDACORP, Inc. Restricted Stock Plan – Form of Restricted Stock Agreement (time-vesting) (July 20, 2006). File number 1-14465, 1-3198, Form 10-Q for the quarter ended September 30, 2006, filed on 11/2/06, as Exhibit 10(h)(vi).

*10.19¹	IDACORP, Inc. Restricted Stock Plan – Form of Performance Stock Agreement (performance vesting) (July 20, 2006). File number 1-14465, 1-3198, Form 10-Q for the quarter ended September 30, 2006, filed on 11/2/06, as Exhibit 10(h)(vii).

*10.20¹	Idaho Power Company Security Plan for Board of Directors – a non-qualified deferred compensation plan, as amended and restated effective July 20, 2006. File number 1-14465, 1-3198, Form 10-Q for the quarter ended September 30, 2006, filed on 11/2/06, as Exhibit 10(h)(viii).

*10.21¹	IDACORP, Inc. Non-Employee Directors Stock Compensation Plan, as amended November 20, 2008. File number 1-14465, 1-3198, Form 10-K for the year ended December 31, 2008, filed on 2/26/09, as Exhibit 10.21.

*10.22¹	Form of Officer Indemnification Agreement between IDACORP, Inc. and Officers of IDACORP, Inc. and Idaho Power, as amended July 20, 2006. File number 1-14465, 1-3198, Form 10-Q for the quarter ended September 30, 2006, filed on 11/2/06, as Exhibit 10(h)(xix).

*10.23¹	Form of Director Indemnification Agreement between IDACORP, Inc. and Directors of IDACORP, Inc., as amended July 20, 2006. File number 1-14465, 1-3198, Form 10-Q for the quarter ended September 30, 2006, filed on 11/2/06, as Exhibit 10(h)(xx).

*10.24¹	Form of Amended and Restated Change in Control Agreement between IDACORP, Inc. and Officers of IDACORP and Idaho Power (senior vice president and higher), approved November 20, 2008. File number 1-14465, 1-3198, Form 10-K for the year ended December 31, 2008, filed on 2/26/09, as Exhibit 10.24.

*10.25¹	Form of Amended and Restated Change in Control Agreement between IDACORP, Inc. and Officers of IDACORP and Idaho Power (below senior vice president), approved November 20, 2008. File number 1-14465, 1-3198, Form 10-K for the year ended December 31, 2008, filed on 2/26/09, as Exhibit 10.25.

*10.26¹	IDACORP, Inc. 2000 Long-Term Incentive and Compensation Plan, as amended November 20, 2008. File number 1-14465, 1-3198, Form 10-K for the year ended December 31, 2008, filed on 2/26/09, as Exhibit 10.26.

*10.27¹	IDACORP, Inc. 2000 Long-Term Incentive and Compensation Plan – Form of Stock Option Award Agreement (July 20, 2006). File number 1-14465, 1-3198, Form 10-Q for the quarter ended September 30, 2006, filed on 11/2/06, as Exhibit 10(h)(xvi).

*10.28¹	IDACORP, Inc. 2000 Long-Term Incentive and Compensation Plan – Form of Restricted Stock Award Agreement (time vesting) (July 20, 2006). File number 1-14465, 1-3198, Form 10-Q for the quarter ended September 30, 2006, filed on 11/2/06, as Exhibit 10(h)(xvii).

*10.29¹	IDACORP, Inc. 2000 Long-Term Incentive and Compensation Plan – Form of Restricted Stock Award Agreement (performance vesting) (July 20, 2006). File number 1-14465, 1-3198, Form 10-Q for the quarter ended September 30, 2006, filed on 11/2/06, as Exhibit 10(h)(xviii).

*10.30¹	IDACORP, Inc. 2000 Long-Term Incentive and Compensation Plan – Form of Performance Share Award Agreement (performance with two goals) (November 20, 2008). File number 1-14465, 1-3198, Form 10-K for the year ended December 31, 2008, filed on 2/26/09, as Exhibit 10.30.

*10.31¹	IDACORP, Inc. Executive Incentive Plan, as amended November 20, 2008. File number 1-14465, 1-3198, Form 10-K for the year ended December 31, 2008, filed on 2/26/09, as Exhibit 10.31.

*10.32¹	Idaho Power Company Executive Deferred Compensation Plan, effective November 15, 2000, as amended November 20, 2008. File number 1-14465, 1-3198, Form 10-K for the year ended December 31, 2008, filed on 2/26/09, as Exhibit 10.32.

10.33¹	IDACORP, Inc. and Idaho Power Compensation for Non-Employee Directors of the Board of Directors, as amended January 21, 2010.

*10.34	Framework Agreement, dated October 1, 1984, between the State of Idaho and Idaho Power relating to Idaho Power’s Swan Falls and Snake River water rights. File number 33-65720, Form S-3, filed on 7/7/93, as Exhibit 10(h).

*10.35	Agreement, dated October 25, 1984, between the State of Idaho and Idaho Power relating to the agreement filed as Exhibit 10.34. File number 33-65720, Form S-3, filed on 7/7/93, as Exhibit 10(h)(i).

*10.36	Contract to Implement, dated October 25, 1984, between the State of Idaho and Idaho Power relating to the agreement filed as Exhibit 10.34. File number 33-65720, Form S-3, filed on 7/7/93, as Exhibit 10(h)(ii).

*10.37	Agreement Regarding the Ownership, Construction, Operation and Maintenance of the Milner Hydroelectric Project (FERC No. 2899), dated January 22, 1990, between Idaho Power and the Twin Falls Canal Company and the Northside Canal Company Limited. File number 33-65720, Form S-3, filed on 7/7/93, as Exhibit 10(m).

*10.38	Guaranty Agreement, dated February 10, 1992, between Idaho Power and New York Life Insurance Company, as Note Purchaser, relating to $11,700,000 Guaranteed Notes due 2017 of Milner Dam Inc. File number 33-65720, Form S-3, filed on 7/7/93, as Exhibit 10(m)(i).

*10.39	Power Purchase Agreement between Idaho Power and PPL Montana, LLC, dated March 1, 2003 and Revised Confirmation Agreement dated May 9, 2003. File number 1-3198, Form 10-Q for the quarter ended June 30, 2003, filed on 8/7/03, as Exhibit 10(k).

10.40	$100 Million Five-Year Amended and Restated Credit Agreement, dated as of April 25, 2007, among IDACORP, Inc., various lenders, Wachovia Bank, National Association, as administrative agent, swingline lender and LC issuer, JPMorgan Chase Bank, N.A., as syndication agent, and KeyBank National Association, Wells Fargo Bank, N.A. and Bank of America, N.A., as documentation agents, and Wachovia Capital Markets, LLC and J. P. Morgan Securities Inc., as joint lead arrangers and joint book runners.

*10.41	First Amendment to Amended and Restated Credit Agreement, dated as of February 2, 2010, by and among IDACORP, Inc., the Lenders party thereto and Wachovia Bank, National Association, as Administrative Agent for the Lenders, File number 1-14465, Form 8-K, filed on 2/8/10, as Exhibit 10.1.

10.42	$300 Million Five-Year Amended and Restated Credit Agreement, dated as of April 25, 2007, among Idaho Power Company, various lenders, Wachovia Bank, National Association, as administrative agent, swingline lender and LC issuer, JPMorgan Chase Bank, N.A., as syndication agent, and KeyBank National Association, US Bank National Association and Bank of America, N.A., as documentation agents, and Wachovia Capital Markets, LLC and J. P. Morgan Securities Inc., as joint lead arrangers and joint book runners.

*10.43	First Amendment to Amended and Restated Credit Agreement, dated as of February 2, 2010, by and among Idaho Power Company, the Lenders party thereto and Wachovia Bank, National Association, as Administrative Agent for the Lenders, File number 1-3198, Form 8-K, filed on 2/8/10, as Exhibit 10.2.

*10.44	Contract for Engineering, Procurement and Construction Services, dated May 7, 2009, between Idaho Power and Boise Power Partners Joint Venture, a joint venture consisting of Kiewit Power Engineers Co. and TIC-The Industrial Company, for Langley Gulch Power Plant (portions of this exhibit have been redacted and filed separately with the Securities and Exchange Commission in connection with a request for confidential treatment pursuant to Rule 24b-2 of the Securities Exchange Act of 1934, as amended). File number 1-14465, 1-3198, Form 10-Q for the quarter ended June 30, 2009, filed on 8/6/09 as Exhibit 10.64.

*10.45	Loan Agreement, dated October 1, 2006, between Sweetwater County, Wyoming and Idaho Power. File number 1-3198, Form 8-K, filed on 10/10/06, as Exhibit 10.1.

*10.46	Power Purchase Agreement between Idaho Power and PPL EnergyPlus, LLC, dated June 2, 2008. File number 1-14465, 1-3198, Form 10-Q for the quarter ended June 30, 2008, filed on 8/7/08, as Exhibit 10.46.

*10.47	Amended and Restated Electric Service Agreement between Idaho Power and Hoku Materials, Inc., dated June 19, 2009. File number 1-14465, 1-3198, Form 10-Q for the quarter ended June 30, 2009 filed on 8/6/09, as Exhibit 10.45.

*10.48¹	Form of IDACORP, Inc. Director Deferred Compensation Agreement, as amended November 20, 2008. File number 1-14465, 1-3198, Form 10-K for the year ended December 31, 2008, filed on 2/26/09, as Exhibit 10.46.

*10.49¹	Form of Letter Agreement to Amend Outstanding IDACORP, Inc. Director Deferred Compensation Agreement (November 20, 2008). File number 1-14465, 1-3198, Form 10-K for the year ended December 31, 2008, filed on 2/26/09, as Exhibit 10.47.

*10.50¹	Form of Amendment to IDACORP, Inc. Director Deferred Compensation Agreement, as amended November 20, 2008. File number 1-14465, 1-3198, Form 10-K for the year ended December 31, 2008, filed on 2/26/09, as Exhibit 10.48.

*10.51¹	Form of Termination of IDACORP, Inc. Director Deferred Compensation Agreement, as amended November 20, 2008. File number 1-14465, 1-3198, Form 10-K for the year ended December 31, 2008, filed on 2/26/09, as Exhibit 10.49.

*10.52¹	Form of Idaho Power Company Director Deferred Compensation Agreement, as amended November 20, 2008. File number 1-14465, 1-3198, Form 10-K for the year ended December 31, 2008, filed on 2/26/09, as Exhibit 10.50.

*10.53¹	Form of Letter Agreement to Amend Outstanding Idaho Power Company Director Deferred Compensation Agreement (November 20, 2008). File number 1-14465, 1-3198, Form 10-K for the year ended December 31, 2008, filed on 2/26/09, as Exhibit 10.51.

*10.54¹	Form of Amendment to Idaho Power Company Director Deferred Compensation Agreement, as amended November 20, 2008. File number 1-14465, 1-3198, Form 10-K for the year ended December 31, 2008, filed on 2/26/09, as Exhibit 10.52.

*10.55¹	Form of Termination of Idaho Power Company Director Deferred Compensation Agreement, as amended November 20, 2008. File number 1-14465, 1-3198, Form 10-K for the year ended December 31, 2008, filed on 2/26/09, as Exhibit 10.53.

*10.56¹	Form of IDACORP Financial Services, Inc. Director Deferred Compensation Agreement, as amended November 20, 2008. File number 1-14465, 1-3198, Form 10-K for the year ended December 31, 2008, filed on 2/26/09, as Exhibit 10.54.

*10.57¹	Form of Letter Agreement to Amend Outstanding IDACORP Financial Services, Inc. Director Deferred Compensation Agreement (November 20, 2008). File number 1-14465, 1-3198, Form 10-K for the year ended December 31, 2008, filed on 2/26/09, as Exhibit 10.55.

*10.58¹	Form of Amendment to IDACORP Financial Services, Inc. Director Deferred Compensation Agreement, as amended November 20, 2008. File number 1-14465, 1-3198, Form 10-K for the year ended December 31, 2008, filed on 2/26/09, as Exhibit 10.56.

*10.59¹	Form of Termination of IDACORP Financial Services, Inc. Director Deferred Compensation Agreement, as amended November 20, 2008. File number 1-14465, 1-3198, Form 10-K for the year ended December 31, 2008, filed on 2/26/09, as Exhibit 10.57.

*10.60	Settlement Agreement, dated March 25, 2009, between the State of Idaho and Idaho Power relating to the agreement filed as Exhibit 10.34. File number 1-14465, 1-3198, Form 10-Q for the quarter ended March 31, 2009, filed on 5/7/09, as Exhibit 10.58.

*10.61¹	Exhibit A to the IDACORP, Inc. Executive Incentive Plan, as amended February 24, 2009. File number 1-14465, 1-3198, Form 8-K, filed on 3/2/09, as Exhibit 10.1.

*10.62¹	Consulting Agreement, dated as of April 1, 2009, by and between Thomas R. Saldin and Idaho Power Company, including its parent IDACORP, Inc. and all subsidiaries and affiliates. File number 1-14465, 1-3198, Form 8-K, filed on 4/3/09, as Exhibit 10.1.

10.63¹	Idaho Power Company Employee Savings Plan, as amended and restated as of January 1, 2010 (revised).

*10.64¹	Separation Agreement and General Release, dated as of August 31, 2009, by and between James C. Miller and Idaho Power Company, including all of its subsidiaries and affiliates. File number 1-14465, 1-3198, Form 10-Q for the quarter ended September 30, 2009, filed on 10/29/09 as Exhibit 10.66.

*10. 65¹	Consulting Agreement, dated as of August 31, 2009, by and between James C. Miller and Idaho Power Company, including its parent IDACORP, Inc. and all subsidiaries and affiliates. File number 1-14465, 1-3198, Form 10-Q for the quarter ended September 30, 2009, filed on 10/29/09 as Exhibit 10.67.

10.66¹	IDACORP, Inc. and/or Idaho Power Executive Officers with Amended and Restated Change in Control Agreements Chart, as of December 31, 2009.

12.1	Statement Re: Computation of Ratio of Earnings to Fixed Charges. (IDACORP, Inc.)

12.2	Statement Re: Computation of Supplemental Ratio of Earnings to Fixed Charges. (IDACORP, Inc.)

12.3	Statement Re: Computation of Ratio of Earnings to Fixed Charges. (Idaho Power)

12.4	Statement Re: Computation of Supplemental Ratio of Earnings to Fixed Charges. (Idaho Power)

*21	Subsidiaries of IDACORP, Inc. File number 1-14465, 1-3198, Form 10-K for the year ended December 31, 2007, filed on 2/28/08, as Exhibit 21.

23	Consent of Independent Registered Public Accounting Firm

31.1	IDACORP, Inc. Rule 13a-14(a) CEO certification.

31.2	IDACORP, Inc. Rule 13a-14(a) CFO certification.

31.3	Idaho Power Rule 13a-14(a) CEO certification.

31.4	Idaho Power Rule 13a-14(a) CFO certification.

32.1	IDACORP, Inc. Section 1350 CEO certification.

32.2	IDACORP, Inc. Section 1350 CFO certification.

32.3	Idaho Power Section 1350 CEO certification.

32.4	Idaho Power Section 1350 CFO certification.

99	Earnings press release for the fourth quarter 2009.

¹ Management contract or compensatory plan or arrangement.

133

IDACORP, Inc.

SCHEDULE I - CONDENSED FINANCIAL INFORMATION OF REGISTRANT

CONDENSED STATEMENTS OF INCOME

		Year Ended December 31,
		2009		2008			2007
		(thousands of dollars)
Income:
Equity in income from continuing operations of subsidiaries		$	125,567		$	100,303	$	85,742
Investment income (losses)			404			(131)		1,363
	Total income		125,971			100,172		87,105

Expenses:
Operating expenses			2,629			1,088		3,253
Interest expense			919			3,250		4,143
Other expense			66			126		70
	Total expenses		3,614			4,464		7,466

Income from Continuing Operations Before Income Taxes			122,357			95,708		79,639

Income Tax Benefit			(1,993)			(2,706)		(2,633)

Income from Continuing Operations			124,350			98,414		82,272

Income from Discontinued Operations, net of tax			-			-		67

	Net Income Attributable to IDACORP, Inc.	$	124,350		$	98,414	$	82,339

The accompanying note is an integral part of these statements.

134

IDACORP, Inc.

CONDENSED BALANCE SHEETS

		December 31,
		2009		2008
Assets		(thousands of dollars)
Current Assets:
Cash and cash equivalents		$	26,770	$	3,541
Receivables			3,004		3,211
Deferred income taxes			23,876		33,693
Other			687		755
	Total current assets		54,337		41,200

Investment in subsidiaries			1,391,974		1,305,873

Other Assets
Deferred income taxes			42,571		44,500
Other			1,099		1,094
Total other assets			43,670		45,594
	Total	$	1,489,981	$	1,392,667

Liabilities and Shareholders’ Equity
Current Liabilities:
Notes payable		$	53,750	$	38,400
Accounts payable			5,869		5,701
Taxes accrued			13,127		22,485
Other			498		541
	Total current liabilities		73,244		67,127

Other Liabilities:
Intercompany notes payable			16,220		19,855
Other			3,182		3,247
	Total other liabilities		19,402		23,102

IDACORP, Inc. Shareholders’ Equity			1,397,335		1,302,438
	Total	$	1,489,981	$	1,392,667

The accompanying note is an integral part of these statements.

135

IDACORP, Inc.

SCHEDULE I - CONDENSED FINANCIAL INFORMATION OF REGISTRANT

CONDENSED STATEMENTS OF CASH FLOWS

	Year Ended December 31,
	2009		2008		2007
	(thousands of dollars)
Operating Activities:
Net cash provided by operating activities	$	65,406	$	56,912	$	39,332

Investing Activities:
Contributions to subsidiaries		(20,000)		(37,000)		(51,000)
Change in intercompany notes receivable		-		-		880
Purchase of investments		-		(364)		-
Sale of investments		48		287		-
Sale of IDACOMM		-		-		7,858
Reimbursement by subsidiary of refundable tax deposit		-		-		43,927
Net cash (used in) provided by investing activities		(19,952)		(37,077)		1,665

Financing Activities:
Issuance of common stock		24,328		50,863		37,181
Dividends on common stock		(56,819)		(54,240)		(53,012)
Increase (decrease) in short-term borrowings		15,350		(11,460)		(26,940)
Change in intercompany notes payable		(3,425)		(2,092)		(626)
Other		(1,659)		(665)		(1,024)
Net cash used in financing activities		(22,225)		(17,594)		(44,421)
Net increase (decrease) in cash and cash equivalents		23,229		2,241		(3,424)
Cash and cash equivalents at beginning of year		3,541		1,300		4,724
Cash and cash equivalents at end of year	$	26,770	$	3,541	$	1,300

The accompanying note is an integral part of these statements.

IDACORP, Inc.

SCHEDULE I - CONDENSED FINANCIAL INFORMATION OF REGISTRANT

NOTES TO CONDENSED FINANCIAL STATEMENTS

1. BASIS OF PRESENTATION

Pursuant to rules and regulations of the Securities and Exchange Commission, the unconsolidated condensed financial statements of IDACORP, Inc. do not reflect all of the information and notes normally included with financial statements prepared in accordance with accounting principles generally accepted in the United States of America. Therefore, these financial statements should be read in conjunction with the consolidated financial statements and related notes included in the 2009 Form 10-K, Part II, Item 8.

Accounting for subsidiaries

IDACORP has accounted for the earnings of its subsidiaries under the equity method in the unconsolidated condensed financial statements. Included in net cash provided by operating activities in the condensed statements of cash flows are dividends of $59,911; $56,868; and $58,990 that IDACORP subsidiaries paid to IDACORP in 2009, 2008 and 2007, respectively.

136

IDACORP, Inc.

SCHEDULE II - CONSOLIDATED VALUATION AND QUALIFYING ACCOUNTS

Years Ended December 31, 2009, 2008 and 2007

Column A		Column B		Column C				Column D		Column E
				Additions
						Charged
		Balance at		Charged		(Credited)				Balance at
		Beginning		to		to Other		Deductions		End
Classification		of Period		Income		Accounts		(1)		of Period
		(thousands of dollars)
2009:
Reserves deducted from applicable assets
	Reserve for uncollectible accounts	$	1,724	$	5,314	$	122	$	5,170	$	1,990
	Reserve for uncollectible notes		1,879		566		600		-		3,045
Other Reserves:
	Rate refunds		13,345		-		-		13,345		-
	Injuries and damages		1,965		4,867		-		3,419		3,413
	Miscellaneous operating reserves		-		2,926		-		-		2,926
2008:
Reserves deducted from applicable assets
	Reserve for uncollectible accounts	$	7,505	$	3,661	$	(5,947)	$	3,495	$	1,724
	Reserve for uncollectible notes		1,879		-		-		-		1,879
Other Reserves:
	Rate refunds		2,397		10,948		-		-		13,345
	Injuries and damages		661		1,437		-		133		1,965
	Miscellaneous operating reserves		4		-		-		4		-
2007:
Reserves deducted from applicable assets
	Reserve for uncollectible accounts	$	7,168	$	2,093	$	-	$	1,756	$	7,505
	Reserve for uncollectible notes		1,879		-		-		-		1,879
	Deferred tax assets		1,565		-		-		1,565		-
Other Reserves:
	Rate refunds		1,227		2,893		-		1,723		2,397
	Injuries and damages reserve		666		2,457		-		2,462		661
	Miscellaneous operating reserves		6		3		-		5		4

Notes: ⁽¹⁾ Represents deductions from the reserves for purposes for which the reserves were created. In the case of uncollectible accounts and notes reserves, includes reversals of amounts previously written off.

137

IDAHO POWER COMPANY

SCHEDULE II - CONSOLIDATED VALUATION AND QUALIFYING ACCOUNTS

Years Ended December 31, 2009, 2008 and 2007

Column A		Column B		Column C					Column D			Column E
				Additions
						Charged
		Balance at		Charged		(Credited)						Balance at
		Beginning		to		to Other			Deductions			End
Classification		of Period		Income		Accounts			(1)			of Period
		(thousands of dollars)
2009:
Reserves deducted from applicable assets:
	Reserve for uncollectible accounts	$	1,724	$	5,314	$	122	$	5,170	$	1,990
Other Reserves:
	Rate refunds		13,345		-		-		13,345		-
	Injuries and damages reserve		1,965		4,867		-		3,419		3,413
	Miscellaneous operating reserves		-		2,926		-		-		2,926
2008:
Reserves deducted from applicable assets:
	Reserve for uncollectible accounts	$	1,305	$	3,661	$	253	$	3,495	$	1,724
Other Reserves:
	Rate refunds		2,397		10,948		-		-		13,345
	Injuries and damages reserve		661		1,437		-		133		1,965
	Miscellaneous operating reserves		4		-		-		4		-
2007:
Reserves deducted from applicable assets:
	Reserve for uncollectible accounts	$	968	$	2,093	$	-	$	1,756	$	1,305
Other Reserves:
	Rate refunds		1,227		2,893		-		1,723		2,397
	Injuries and damages reserve		665		1,210		-		1,214		661
	Miscellaneous operating reserves		6		3		-		5		4

Notes: ⁽¹⁾ Represents deductions from the reserves for purposes for which the reserves were created. In the case of uncollectible accounts includes reversals of amounts previously written off.

138

SIGNATURES

Pursuant to the requirements of Section 13 and 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

February 23, 2010		IDACORP, INC.
Date
	By:	/s/J. LaMont Keen
			J. LaMont Keen
			President and Chief Executive Officer

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.

Signature	Title	Date

/s/Jon H. Miller	Chairman of the Board	February 23, 2010
Jon H. Miller

/s/J. LaMont Keen	(Principal Executive Officer)	February 23, 2010
J. LaMont Keen
President and Chief Executive Officer and Director

/s/Darrel T. Anderson	(Principal Financial Officer)	February 23, 2010
Darrel T. Anderson	(Principal Accounting Officer)
Executive Vice President-Administrative
Services and Chief Financial Officer

/s/C. Stephen Allred	Director	February 23, 2010
C. Stephen Allred

/s/Richard J. Dahl	Director	February 23, 2010
Richard J. Dahl

/s/Judith A. Johansen	Director	February 23, 2010
Judith A. Johansen

/s/Christine King	Director	February 23, 2010
Christine King

/s/Gary G. Michael	Director	February 23, 2010
Gary G. Michael

/s/Jan B. Packwood	Director	February 23, 2010
Jan B. Packwood

/s/Richard G. Reiten	Director	February 23, 2010
Richard G. Reiten

/s/Joan H. Smith	Director	February 23, 2010
Joan H. Smith

/s/Robert A. Tinstman	Director	February 23, 2010
Robert A. Tinstman

/s/Thomas J. Wilford	Director	February 23, 2010
Thomas J. Wilford

139

SIGNATURES

February 23, 2010		Idaho Power Company
Date
	By:	/s/J. LaMont Keen
			J. LaMont Keen
			President and Chief Executive Officer

Signature	Title	Date

/s/Jon H. Miller	Chairman of the Board	February 23, 2010
Jon H. Miller

/s/J. LaMont Keen	(Principal Executive Officer)	February 23, 2010
J. LaMont Keen
President and Chief Executive Officer and Director

/s/Darrel T. Anderson	(Principal Financial Officer)	February 23, 2010
Darrel T. Anderson	(Principal Accounting Officer)
Executive Vice President-Administrative
Services and Chief Financial Officer

/s/C. Stephen Allred	Director	February 23, 2010
C. Stephen Allred

/s/Richard J. Dahl	Director	February 23, 2010
Richard J. Dahl

/s/Judith A. Johansen	Director	February 23, 2010
Judith A. Johansen

/s/Christine King	Director	February 23, 2010
Christine King

/s/Gary G. Michael	Director	February 23, 2010
Gary G. Michael

/s/Jan B. Packwood	Director	February 23, 2010
Jan B. Packwood

/s/Richard G. Reiten	Director	February 23, 2010
Richard G. Reiten

/s/Joan H. Smith	Director	February 23, 2010
Joan H. Smith

/s/Robert A. Tinstman	Director	February 23, 2010
Robert A. Tinstman

/s/Thomas J. Wilford	Director	February 23, 2010
Thomas J. Wilford

140

EXHIBIT INDEX

Exhibit Number

4.10		Forty-fifth Supplemental Indenture to Mortgage and Deed of Trust dated as of February 1, 2010.

10.16¹		Idaho Power Company Security Plan for Senior Management Employees II, effective January 1, 2005, as amended and restated November 19, 2009.

10.33¹		IDACORP, Inc. and Idaho Power Compensation for Non-Employee Directors of the Board of Directors, as amended January 21, 2010.

10.40		$100 Million Five-Year Amended and Restated Credit Agreement, dated as of April 25, 2007, among IDACORP, Inc., various lenders, Wachovia Bank, National Association, as administrative agent, swingline lender and LC issuer, JPMorgan Chase Bank, N.A., as syndication agent, and KeyBank National Association, Wells Fargo Bank, N.A. and Bank of America, N.A., as documentation agents, and Wachovia Capital Markets, LLC and J. P. Morgan Securities Inc., as joint lead arrangers and joint book runners.

10.42		$300 Million Five-Year Amended and Restated Credit Agreement, dated as of April 25, 2007, among Idaho Power Company, various lenders, Wachovia Bank, National Association, as administrative agent, swingline lender and LC issuer, JPMorgan Chase Bank, N.A., as syndication agent, and KeyBank National Association, US Bank National Association and Bank of America, N.A., as documentation agents, and Wachovia Capital Markets, LLC and J. P. Morgan Securities Inc., as joint lead arrangers and joint book runners.

10.63¹		Idaho Power Company Employee Savings Plan, as amended and restated as of January 1, 2010 (revised).

10.66¹		IDACORP, Inc. and/or Idaho Power Executive Officers with Amended and Restated Change in Control Agreements Chart, as of December 31, 2009.

12.1		Statement Re: Computation of Ratio of Earnings to Fixed Charges. (IDACORP, Inc.)

12.2		Statement Re: Computation of Supplemental Ratio of Earnings to Fixed Charges. (IDACORP, Inc.)

12.3		Statement Re: Computation of Ratio of Earnings to Fixed Charges. (Idaho Power)

12.4		Statement Re: Computation of Supplemental Ratio of Earnings to Fixed Charges. (Idaho Power)

23		Consent of Independent Registered Public Accounting Firm.

31.1		IDACORP, Inc. Rule 13a-14(a) CEO certification.

31.2		IDACORP, Inc. Rule 13a-14(a) CFO certification.

31.3		Idaho Power Rule 13a-14(a) CEO certification.

31.4		Idaho Power Rule 13a-14(a) CFO certification.

32.1		IDACORP, Inc. Section 1350 CEO certification.

32.2		IDACORP, Inc. Section 1350 CFO certification.

32.3		Idaho Power Section 1350 CEO certification.

32.4		Idaho Power Section 1350 CFO certification.

99		Earnings press release for the fourth quarter 2009.

1 Management contract or compensatory plan or arrangement

142