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.

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 daily collateralization on derivative instruments in net liability positions. Credit-contingent features are also discussed in Note 15 to the consolidated financial statements.

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

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. 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 deferred approximately $29 million, $8 million and $3 million of pension expense to a regulatory asset in 2009, 2008, and 2007 respectively. Idaho Power does not receive a carrying charge on the current deferral balance.

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)

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.

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.