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, 2010

	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


		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
		Stock Exchange

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

Indicate by check mark 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 non-affiliates (June 30, 2010):

IDACORP, Inc.:

$1,588,107,885

Idaho Power Company:

None

Number of shares of common stock outstanding at January 31, 2011:

IDACORP, Inc.:	49,425,384
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 19, 2011.

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
AMI	-	Advanced Metering Infrastructure
ADITC	-	Accumulated Deferred Investment Tax Credits
AFUDC	-	Allowance for Funds Used During Construction
APCU	-	Annual Power Cost Update
ARRA	-	American Recovery and Reinvestment Act of 2009
BCC	-	Bridger Coal Company, a joint venture of IERCo
BLM	-	United States Bureau of Land Management
CAA	-	Clean Air Act
Cal ISO	-	California Independent System Operator
CalPX	-	California Power Exchange
CO₂	-	Carbon Dioxide
CSPP	-	Cogeneration and small power production
EIS	-	Environmental impact statement
EPA	-	United States Environmental Protection Agency
EPS	-	Earnings per share
ESA	-	Endangered Species Act
FASB	-	Financial Accounting Standards Board
FCA	-	Fixed Cost Adjustment mechanism
FERC	-	Federal Energy Regulatory Commission
FPA	-	Federal Power Act
GAAP	-	Generally Accepted Accounting Principles
GHG	-	Greenhouse gas
HCC	-	Hells Canyon Complex
Ida-West	-	Ida-West Energy, a subsidiary of IDACORP, Inc.
IDD	-	Industry Director Directive #5
IE	-	IDACORP Energy, a subsidiary of IDACORP, Inc.
IERCo	-	Idaho Energy Resources Co., a subsidiary of Idaho Power Company
IFS	-	IDACORP Financial Services, a subsidiary of IDACORP, Inc.
IPUC	-	Idaho Public Utilities Commission
IRP	-	Integrated Resource Plan
IRS	-	Internal Revenue Service
kW	-	Kilowatt
LGAR	-	Load Growth Adjustment Rate
LTICP	-	2000 Long-term Incentive and Compensation Plan
maf	-	Million acre-feet
MD&A	-	Management’s Discussion and Analysis of Financial Condition and Results of Operations
MW	-	Megawatt
MWh	-	Megawatt-hour
NOx	-	Nitrogen Oxide
NSPS	-	New Source Performance Standards under Section III of the Clean Air Act
NYSE	-	New York Stock Exchange
NWRFC	-	National Weather Service Northwest River Forecast Center
O&M	-	Operations and Maintenance
OATT	-	Open Access Transmission Tariff
OPUC	-	Oregon Public Utility Commission
PCA	-	Power Cost Adjustment
PCAM	-	Power Cost Adjustment Mechanism
PURPA	-	Public Utility Regulatory Policies Act of 1978
REC	-	Renewable Energy Certificate
RES	-	Renewable Energy Standards
RH BART	-	Regional Haze - Best Available Retrofit Technology
RPS	-	Renewable Portfolio Standards
SEC	-	Securities and Exchange Commission
SO₂	-	Sulfur Dioxide
SRBA	-	Snake River Basin Adjudication
USBR	-	United States Bureau of Reclamation
VIEs	-	Variable Interest Entities
WECC	-	Western Electricity Coordinating Council

TABLE OF CONTENTS
				Page
Part I

	Item 1.	Business		5-15
	Executive Officers of the Registrants			16-17
	Item 1A.	Risk Factors		18-25
	Item 1B.	Unresolved Staff Comments		25
	Item 2.	Properties		26-27
	Item 3.	Legal Proceedings		27
	Item 4.	(Reserved)		27


Part II

	Item 5.	Market for Registrant’s Common Equity, Related Stockholder
			Matters and Issuer Purchases of Equity Securities	27-29
	Item 6.	Selected Financial Data		29-30
	Item 7.	Management’s Discussion and Analysis of Financial Condition and
			Results of Operations	30-78
	Item 7A.	Quantitative and Qualitative Disclosures About Market Risk		78-80
	Item 8.	Financial Statements and Supplementary Data		80-142
	Item 9.	Changes in and Disagreements with Accountants on Accounting and
			Financial Disclosure	142
	Item 9A.	Controls and Procedures		142-147
	Item 9B.	Other Information		147-148

Part III

	Item 10.	Directors, Executive Officers and Corporate Governance*		148
	Item 11.	Executive Compensation*		149
	Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related
			Stockholder Matters*	149
	Item 13.	Certain Relationships and Related Transactions, and Director Independence*		149
	Item 14.	Principal Accountant Fees and Services*		150-151

Part IV

	Item 15.	Exhibits and Financial Statement Schedules		151-159

	Signatures			165-166



	* Except as indicated in Items 12 and 14, IDACORP, Inc. information is incorporated by reference to IDACORP, Inc.’s definitive proxy statement for the 2011 Annual Meeting of Shareholders.

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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 included in this Form 10-K at Part I, Item 1A – “Risk Factors” and in Part II, Item 7- “Management’s Discussion and Analysis of Financial Condition and Results of Operations - Forward-Looking Statements.” 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,” “targets,” 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 (BCC), which mines and supplies coal to the Jim Bridger generating plant owned in part by Idaho Power.

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

Idaho Power is IDACORP’s only reportable business segment, contributing 98.5 percent of IDACORP’s net income in 2010. Segment data is presented in Note 17 – “Segment Information” to the consolidated financial statements included in this report. At December 31, 2010, IDACORP had 2,032 full-time employees, 2,016 of whom were employed by Idaho Power, and 19 part-time employees, all of whom were employed by Idaho Power.

RESPONSIBLE PLANNING: Idaho Power’s planning process is intended to ensure adequate generation and transmission resources to meet anticipated population growth and increasing electricity demand. This planning process integrates Idaho Power’s regulatory strategy and financial planning, including the consideration of regional economic development in the communities Idaho Power serves.
RESPONSIBLE DEVELOPMENT AND PROTECTION OF RESOURCES: Idaho Power’s business strategy includes the development and protection of generation, transmission, distribution, and associated infrastructure, and stewardship of the natural resources Idaho Power and the communities it serves depend upon. Additionally, the strategy considers workforce planning and employee development and retention related to these strategic elements.

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RESPONSIBLE ENERGY USE: Idaho Power's business strategy includes energy efficiency and demand response programs and preparation for potential carbon and renewable portfolio standards (RPS) legislation. The strategy also includes targeted reductions relating to carbon emission intensity and public reporting of these reductions.

IDACORP and Idaho Power make available free of charge on their websites 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 (SEC). 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. The contents of the above-referenced website addresses are not part of this Annual Report on Form 10-K. Reports, proxy and information statements, and other information regarding IDACORP and Idaho Power may also be obtained directly from the SEC’s website, www.sec.gov, or from the SEC’s Public Reference Room at 100 F Street, NE, Washington, D.C. 20549.

IDACORP’s and Idaho Power’s principal executive offices are located at 1221 W. Idaho Street, Boise, Idaho 83702, and the telephone number is (208) 388-2200.

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, typically in the form of right-of-way arrangements, 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, 2010, Idaho Power supplied electric energy to approximately 492,000 general business customers. Idaho Power’s principal commercial and industrial customers are involved in food processing, electronics and general manufacturing, agriculture, forest products, beet sugar refining, and winter recreation.

Weather, customer demand, and economic conditions impact electricity sales and, therefore, utility revenues are not generated, and associated expenses are not incurred, evenly during the year. 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. Idaho Power’s retail energy sales typically peak during the summer irrigation and cooling season, with a lower peak in the winter that generally results from heating demand.

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. Idaho Power is also under the jurisdiction of the IPUC, the OPUC, and the Public Service Commission of Wyoming as to the issuance of debt and equity securities.

Rates and Revenues

Retail:

Idaho Power periodically evaluates the need to seek changes to its retail electricity price structure to sufficiently cover its operating costs and provide a reasonable rate of return. Idaho Power uses general rate cases, power cost adjustment (PCA) 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.

Retail prices are determined through formal ratemaking proceedings that generally include testimony by participating parties, data requests, public hearings, and the issuance of a final order. Participants in such proceedings, which are conducted under established procedural schedules, include Idaho Power, the IPUC or

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OPUC, and intervenors. The IPUC and OPUC are required to ensure that the prices and terms of service are fair, non-discriminatory, and provide the company an opportunity to earn a fair return on investment.

In addition to general rate case filings, ratemaking proceedings can involve charges or credits related to specific costs, programs, or activities, as well as the recovery or refund of deferred amounts recorded pursuant to specific authorization from the IPUC or OPUC. Such amounts are generally collected from, or refunded to, retail customers through the use of supplemental tariffs.

For additional information, including information on significant rate cases and proceedings, see the “Regulatory Matters” section of Part II, Item 7 – “Management’s Discussion and Analysis of Financial Condition and Results of Operations” (MD&A) and Note 3 – “Regulatory Matters” to the consolidated financial statements included in this report.

Developments with Special Customer Electric Service Agreements

Idaho Power is authorized to enter into special electric service arrangements with customers who have an aggregate power requirement that exceeds 20 MW. Notable recent developments with respect to two of those arrangements are described below.

Micron: On February 12, 2010, the IPUC approved a replacement electric service agreement between Idaho Power and Micron Technology, Inc. (Micron) that provided operating and planning benefits to Idaho Power while allowing Micron to reduce its contract demand to 60 MW. The prior agreement provided for a contract demand of 85 MW.

Hoku: In March 2009, the IPUC approved a September 2008 electric service agreement between Idaho Power and Hoku Materials, Inc. (Hoku), to provide electric service to Hoku’s polysilicon production facility being constructed in Pocatello, Idaho. The initial term of the agreement was four years beginning June 1, 2009, subsequently changed to December 1, 2009, with a maximum demand obligation during the initial term of 82 MW. Hoku was still not taking significant service as of 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, which was approved by the IPUC, remains 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. While the substantial delay in the starting date for Hoku’s energy purchases under the electric service agreement reduces Idaho Power’s expected 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 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. Such standards, which are applicable to Idaho Power, were developed by the North American Electric Reliability Corporation and the Western Electricity Coordinating Council (WECC), which has responsibility for compliance and enforcement of these standards.

Idaho Power has one firm wholesale power sales contract, with Raft River Electric Cooperative, for up to 15 MW. This contract expires in September 2011. Idaho Power has one wholesale reserve sales contract, with United Materials of Great Falls, Inc. The agreement requires Idaho Power to carry energy 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.

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 are influenced by customer load, market prices, generating costs, 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 hydroelectric 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

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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.

Energy Sales:

The table below presents Idaho Power’s revenues and energy use by customer type for the last three years. Approximately 95 percent of Idaho Power’s general business revenue comes from customers located in Idaho, with the remainder coming from customers located in Oregon. Idaho Power’s operations are discussed further in Part II, Item 7 - “MD&A – Results of Operations - Utility Operations.”

				Years Ended December 31,
				2010		2009		2008
Revenues (thousands of dollars)
	Residential			$	400,607	$	409,479	$	353,262
	Commercial				231,440		232,816		203,035
	Industrial				138,394		141,530		122,302
	Irrigation				110,555		109,655		105,712
	Deferred revenue related to Hells Canyon
		relicensing AFUDC			(10,625)		(9,715)		-
		Total general business			870,371		883,765		784,311
	Off-system sales				78,133		94,373		121,429
	Other				84,548		67,858		50,336
			Total	$	1,033,052	$	1,045,996	$	956,076

Energy use (thousands of MWh)
	Residential				4,967		5,300		5,297
	Commercial				3,763		3,858		3,970
	Industrial				3,076		3,140		3,355
	Irrigation				1,707		1,650		1,922
			Total general business		13,513		13,948		14,544
	Off-system sales				1,982		2,836		2,048
			Total		15,495		16,784		16,592

Power Supply

Idaho Power primarily relies on company-owned hydroelectric, coal, and gas-fired generation facilities and long-term power purchase agreements 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 generating plants and their capacities are listed in Part I, 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 the 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 similarly heavy load periods Idaho Power’s system is fully committed to serve load and meet required operating reserves.

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

				MWh			Percent of Total Generation
				2010	2009	2008	2010	2009	2008
				(thousands of MWh)
Hydroelectric plants				7,344	8,096	6,908	51%	53%	48%
Coal-fired plants				6,864	6,941	7,279	48%	45%	50%
Natural gas fired plants				160	242	217	1%	2%	2%
		Total system generation		14,368	15,279	14,404	100%	100%	100%
Purchased power - cogeneration and
	small power production			910	970	756
Purchased power - other				1,491	1,942	2,960
		Total purchased power		2,401	2,912	3,716
			Total power supply	16,769	18,191	18,120

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 megawatt-hours (MWh) under median 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.

The manner in which Idaho Power has historically optimized operation of its hydroelectric facilities may change in the future as the company is faced with integrating an increasing amount of intermittent wind generation. As additional intermittent wind generation resources are developed in the region and contracted to Idaho Power, the operational impacts will likely increase. For related information on intermittent wind generation see “Purchased Power Agreements” below.

Stream flow conditions were below average in 2010, resulting in a decrease of 0.8 million MWh generated from Idaho Power’s hydroelectric facilities compared to 2009. The observed stream flow data released in August 2010 by the U.S. Army Corps of Engineers indicated that Brownlee Reservoir inflow for April through July 2010 was 4.6 million acre-feet (maf), or 73 percent of the National Weather Service Northwest River Forecast Center (NWRFC) average, compared to 5.6 maf, or 89 percent, of the NWRFC average in 2009.

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 more information on water management issues see Part II, Item 7 – “MD&A – Legal Matters – Snake River Basin Water Rights.”

Idaho Power is subject to the provisions of the FPA as a “public utility” and as a “licensee” 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 described 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.

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Idaho Power obtains licenses for its hydroelectric projects from the FERC, similar to other utilities that operate nonfederal hydroelectric projects on qualified waterways. The licensing process includes an extensive public review process and involves numerous natural resource and environmental issues. The licenses last 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. 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.

Coal and Natural Gas-Fired Generation:

Idaho Power co-owns three coal-fired power plants and owns two natural gas-fired 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. The Langley Gulch natural gas-fired combined cycle power plant located in Idaho is currently under construction and is contracted to achieve commercial operation by November 1, 2012. Based on contract incentives and the current project status, Idaho Power estimates that the plant will be in service by June 2012.

Fuel supply-coal

Idaho Power, through its subsidiary IERCo, owns a one-third interest in BCC, 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. Idaho Power believes that 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 provide the opportunity to access other fuel supplies for tonnage requirements above established contract minimums.

NV Energy, Inc., as the operator of the Valmy generating plant, has an agreement with Arch Coal Sales Company, Inc. to supply coal to the plant through 2011; however, due to force majeure provisions of the contract, approximately 131,000 tons (Idaho Power portion) will be delivered to the Valmy plant in 2012 instead of 2011. As a 50 percent owner of the plant, Idaho Power is obligated to purchase one-half of the coal, ranging from 515,000 tons to 762,500 tons annually. NV Energy, Inc. 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 high as 500,000 tons annually.

The Boardman generating plant receives coal from the Powder River Basin through annual contracts. Portland General Electric Company, as the operator of the Boardman plant, has two agreements with Alpha Natural Resources, Inc., to supply all of the Boardman plant’s coal requirements in 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 is 243,600 tons in 2011 (including approximately 60,300 tons provided by force majeure contract provisions from 2009). A request for proposal (RFP) for the 2012 coal supply is planned in 2011.

Fuel supply-natural gas

Idaho Power owns and operates the Danskin and Bennett Mountain combustion turbines. Natural gas is purchased based on system requirements. The natural gas is supplied through Northwest Pipeline GP’s (Northwest) pipeline under a 24,523 million British thermal units (MMBtu) per day long-term gas transportation service agreement. The agreement runs into 2022, with extensions at Idaho Power’s discretion. In addition to the long-term gas transportation service agreement, Idaho Power has entered into a long-term storage service agreement with Northwest for 131,453 MMBtu of total storage capacity at the Jackson Prairie Storage Project. 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 74 percent of its total, and its full allotment is expected to be reached by March 2012. The firm storage

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contract expires in 2043. Natural gas will be purchased and stored with the intent of fulfilling needs as identified for summer peaks or to meet system requirements.

Procurement of gas for the Langley Gulch combined-cycle natural gas-fired power plant will be managed to meet system requirements and fueling strategies. Natural gas for Langley Gulch will be supplied through multiple Northwest long-term gas transportation service agreements totaling 31,061 MMBtu per day with a range of start dates beginning March 2011 and a range of end dates through May 2042. Idaho Power has sole discretion regarding extensions to the multiple long-term service agreements.

Purchased Power Agreements:

Idaho Power purchases power in the market, based on economics, operating reserve margins, risk limits, and unit availability, and from PURPA projects as mandated. Idaho Power seeks to manage its loads efficiently by utilizing its generation resources and long-term purchase power contracts in conjunction with buying and selling opportunities in the market.

Idaho Power has the following firm wholesale purchased power contracts and energy exchange agreements:

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;
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;
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;
USG Oregon LLC - for 22 MW (estimated average annual output) from the 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;
Clatskanie People’s Utility - for the exchange of up to 18 MW 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; and
NV Energy, Inc. - for the exchange of up to 45 MW of energy hourly. The agreement expires March 31, 2012.

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 PURPA contracts.

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

Idaho Power is required to purchase all of the output from the facilities located inside its service territory, subject to some exceptions such as adverse impacts on system reliability;
Idaho Power is required to purchase the output of projects located outside its service territory if it has the ability to receive power 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 PCA 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. The IPUC has granted a temporary reduction in the upper eligibility limit to 100 kilowatts (kW) for wind and solar projects, as discussed below;
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; and

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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.

Published Avoided Cost rates remain relatively high, providing a favorable climate for PURPA project development, which may result in Idaho Power acquiring energy at above wholesale market prices when a surplus already exists and may also require additional integration costs, thus increasing costs to its customers. In response to a November 5, 2010 application filed by Idaho Power and two other electric utilities with Idaho service territories, on February 7, 2011, the IPUC issued an order temporarily reducing the eligibility cap, effective retroactively to December 14, 2010, to 100 kW for wind and solar PURPA projects only, while the IPUC further investigates the implications of large projects disaggregating into smaller projects to qualify for higher Published Avoided Cost rates, tax incentives, and other benefits.

As of December 31, 2010, Idaho Power had the following signed CSPP-related agreements originally ranging from one to 35 years. The majority of the new facilities will be wind resources which will generate on an intermittent basis.

		# of	Nameplate
Status		Contracts	Capacity (MW)
On-line at the end of 2010		91	491
Projected to come on-line by year-end 2014		35	697
	Total	126	1,188

During 2010, Idaho Power purchased 910,429 MWh of power from CSPP facilities at a cost of $55 million, resulting in a blended price of $60.38 per MWh.

Transmission Services

Electric transmission systems deliver energy from electric generation facilities to distribution systems for final delivery to customers. Transmission systems are designed to move electricity over long distances because generation facilities can be located anywhere from a few miles to hundreds of miles from customers. 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, Inc. These 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 WECC, 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 and Renewable Energy Projects

Idaho Power filed its 2009 Integrated Resource Plan (IRP) with the IPUC and OPUC in December 2009. 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 2009 IRP was accepted by the IPUC in August 2010 and acknowledged by the OPUC in October 2010. The four primary goals of the IRP are to:

identify sufficient resources to reliably serve the growing demand for energy within Idaho Power’s service area throughout the 20-year planning period;
ensure the selected resource portfolio balances cost, risk, and environmental concerns;

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give equal and balanced treatment to both supply-side resources and demand-side measures; and
involve the public in the planning process in a meaningful way.

Idaho Power updates the IRP every two years and work on the 2011 IRP began in the summer of 2010. The updated plan is expected to be completed and filed in June 2011. During the time between resource plan filings, the public and regulatory oversight of the activities identified in the 2009 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.

The 2009 IRP identified the 300 MW Langley Gulch project currently under construction and a 50 MW expansion of the Shoshone Falls hydroelectric facility that is currently being evaluated for economic viability. Idaho Power is also planning the Boardman to Hemingway and the Gateway West transmission lines and has constructed the Hemingway substation, all of which are intended to improve reliability, relieve congestion, and provide system flexibility. Refer to Part II, Item 7 – “MD&A – Liquidity and Capital Resources – Capital Requirements – Major Projects” for additional information about Idaho Power’s significant infrastructure development projects and plan. The 2009 IRP also included discussion related to the following resources:

Geothermal RFPs:

Although the results of previously conducted geothermal RFP processes have been disappointing, Idaho Power continues to work with project developers capable of delivering energy to the company’s service area. The 2009 IRP included two 20-MW increments of geothermal energy in the preferred portfolio; one in 2012 and one in 2016. The 20-MW increment in 2012 was addressed by a long-term power purchase agreement for the output from the Neal Hot Springs Geothermal Project located in eastern Oregon. The need for the additional 2016 increment of geothermal energy is being assessed in the 2011 IRP.

Wind RFP:

In May 2009, Idaho Power issued an RFP seeking to purchase up to 150 MW of wind generation by 2012. The RFP generated considerable interest from wind developers, and throughout the first half of 2010, Idaho Power negotiated with the front-runner. During this time, other project developers began expressing an interest in developing wind projects under PURPA and it became evident the additional wind generation under PURPA would exceed the 150 MW identified in the RFP. Due to the acquisition of this additional PURPA wind generation and due to stalled contract negotiations in the RFP process, Idaho Power did not award a contract under the RFP process and concluded the RFP process in August 2010.

Combined Heat and Power (CHP) RFP:

CHP resources were not included in the 2009 IRP preferred portfolio because of the 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 2009, Idaho Power signed an agreement to jointly investigate a CHP project with the Idaho Office of Energy Resources (IOER) and The Amalgamated Sugar Company (TASCO), one of Idaho Power’s large industrial customers. The agreement established the framework for a high-level feasibility study to investigate installing a CHP project at TASCO’s Nampa, Idaho facility that could be as large as 100 MW. The IOER and Idaho Power jointly funded the study. The high-level feasibility study confirmed initial estimates of the project’s potential benefits, and in September 2010, Idaho Power, IOER, and TASCO entered into a second agreement to complete a more detailed feasibility study to refine performance and financial modeling of the proposed project. An RFP was issued and a consulting firm was selected to perform the more detailed feasibility study. The study is expected to be completed by the second quarter of 2011.

Energy Efficiency and Demand-Side Management Programs:

In 2010, Idaho Power’s energy efficiency programs reduced energy usage by approximately 170,000 MWh, and the demand response programs resulted in a summer peak demand reduction of about 300 MW through combined program performance.

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In 2010, Idaho Power spent approximately $45.6 million on energy efficiency and targeted demand reduction response programs. Approximately $44.2 million of funding for these programs is funded by Idaho and Oregon energy efficiency tariff riders while the balance of the funding comes from Idaho Power base rates.

Idaho Power has 15 energy efficiency and demand response programs in place, targeting savings across the entire year and summer system demand reduction. These programs are offered to all customer segments and emphasize the wise use of energy, especially during periods of high demand. This energy and demand reduction can minimize or delay the need for new infrastructure. Idaho Power’s programs include:

financial incentives for irrigation customers for either improving the energy efficiency of an irrigation system or installing new energy efficient systems;
energy efficiency for new and existing homes, including efficient appliances and HVAC equipment, energy efficient building techniques, insulation improvement, air duct sealing, and energy efficient lighting;
incentives to industrial and commercial customers for using energy efficient equipment, and using energy efficiency techniques and operational and management processes; and
demand response programs to reduce peak summer demand through the voluntary interruption of central air conditioners for residential customers, interruption of irrigation pumps, and reduction of commercial and industrial demand through a third-party demand response aggregator.

Approximately $3 million of Idaho Power’s 2010 energy efficiency spending was related to research and analysis, education, technology evaluation, and market transformation. Most of this activity was done in conjunction with the Northwest Energy Efficiency Alliance (NEEA).

Environmental Regulation

Idaho Power is 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. Current and pending legislation relates to, among other items, climate change, greenhouse gas emissions and air quality, renewable energy standards (RES), mercury and other emissions, hazardous wastes, and polychlorinated biphenyls (PCBs). Environmental laws and regulations may, among other things, increase the cost of operating power generation plants and constructing new facilities, require that Idaho Power install additional pollution control devices at existing generating plants, or require that Idaho Power discontinue operating certain power generation plants. 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. Further, 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. For a more detailed discussion of these and other environmental issues, refer to Part II, Item 7 – “MD&A – Environmental Issues.”

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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. Idaho Power estimates its environmental expenditures, based upon present environmental laws and regulations, will be as follows for the periods indicated, excluding allowance for funds used during construction (AFUDC) (in millions of dollars):

Environmental expenditures		2011		2012 - 2013
Studies and measures at hydroelectric facilities		$	6	$	57
Investments in equipment and facilities at thermal plants			10		52
	Total capital expenditures	$	16	$	109

Operating costs for environmental facilities - Hydroelectric		$	19	$	46
Operating costs for environmental facilities - Thermal			7		15
	Total operations and maintenance	$	26	$	61

Idaho Power anticipates that a number of impending EPA rulemakings and proceedings addressing, among other things, ozone and fine particulate matter pollution, emissions, and disposal of coal combustion residuals could result in substantially increased operating and compliance costs.

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 $7 million, $8 million, and $11 million in 2010, 2009, and 2008, respectively. IFS’s portfolio also includes historic rehabilitation projects such as the Empire Building in Boise, Idaho. IFS had $7 million, $14 million, and $8 million of new investments during 2010, 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, 2010, the gross amount of IFS’s portfolio equaled $204 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 six 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 $8 million, $9 million, and $8 million in 2010, 2009, and 2008, respectively.

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EXECUTIVE OFFICERS OF THE REGISTRANTS

The names, ages, and positions of the executive officers of IDACORP and Idaho Power are listed below, along with their business experience during at least 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, 58

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

DARREL T. ANDERSON, 52

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 - October 1, 2009.

DANIEL B. MINOR, 53

• Executive Vice President of IDACORP, Inc., May 20, 2010 – present.

• 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.

REX BLACKBURN, 55

• 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.

• Partner at Blackburn and Jones, LLP, a law firm, January 2003 – December 31, 2007.

LISA A. GROW, 45

• 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.

STEVEN R. KEEN, 50

• Vice President, Finance and Treasurer of IDACORP, Inc. and Idaho Power Company, June 1, 2010 – present.

• Vice President and Treasurer of IDACORP, Inc. and Idaho Power Company, June 1, 2006 – May 31, 2010.

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

PATRICK A. HARRINGTON, 50

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

• Senior Attorney, IDACORP, Inc. and Idaho Power Company, June 2003 – March 15, 2007.

DENNIS C. GRIBBLE, 58

• 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, 50

Vice President, Chief Risk Officer of IDACORP, Inc. and Idaho Power Company, May 20, 2010 - present.
Vice President - Corporate Planning and Chief Risk Officer of IDACORP, Inc. and Idaho Power Company, January 1, 2008 - May 20, 2010.
Vice President - Finance and Chief Risk Officer of IDACORP, Inc. and Idaho Power Company, July 2004 - January 1, 2008.

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•

LUCI K. MCDONALD, 53

• Vice President, Human Resources and Corporate Services of IDACORP, Inc. and Idaho Power Company, May 20, 2010 – present.

• Vice President – Human Resources of IDACORP, Inc. and Idaho Power Company, December 2004 – May 20, 2010.

NAOMI SHANKEL, 39

• Vice President, Supply Chain of IDACORP, Inc. and Idaho Power Company, May 20, 2010 – present.

• Vice President, Audit and Compliance of IDACORP, Inc. and Idaho Power Company, September 21, 2006 – May 20, 2010.

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

JEFFREY MALMEN, 43

• 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 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, 60

• Sr. Vice President, Corporate Responsibility of IDACORP, Inc. and Idaho Power Company, May 20, 2010 – present.

• Vice President – Regulatory Affairs of Idaho Power Company, March 2001 – May 20, 2010.

WARREN KLINE, 55

• Vice President, Customer Operations of Idaho Power Company, May 20, 2010 – present.

• Vice President – Customer Service and Regional Operations of Idaho Power Company, July 20, 2005 – May 20, 2010.

N. VERN PORTER, 51

• 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 – October 1, 2009.

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

KEN W. PETERSEN, 47

• Corporate Controller and Chief Accounting Officer of IDACORP, Inc. and Idaho Power Company, May 20, 2010 – present.

• Corporate Controller of IDACORP and Idaho Power Company, December 29, 2007 – May 20, 2010.

• General Manager Delivery Services and Delivery Business Unit Controller of Idaho Power Company, January 2004 – December 28, 2007.

GREGORY W. SAID, 56

• Vice President, Regulatory Affairs, Idaho Power Company, January 20, 2011 – present.

• General Manager of Regulatory Affairs, Idaho Power Company, April 3, 2010 – January 20, 2011.

• Director, State Regulation, Idaho Power Company, August 23, 2008 – April 3, 2010.

• Manager, Revenue Requirement, Idaho Power Company, November 14, 1998 – August 23, 2008.

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ITEM 1A. RISK FACTORS

In addition to the factors discussed elsewhere in this report, the risk factors set forth below may have a significant impact on the business, financial condition, or results of operations 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.

If the Idaho Public Utilities Commission, the Oregon Public Utility Commission, or the Federal Energy Regulatory Commission grant less rate recovery in regulatory proceedings than Idaho Power Company needs to cover existing and future increased costs of providing services, earnings and cash flows may be reduced. The prices that the Idaho Public Utilities Commission and Oregon Public Utility Commission authorize Idaho Power Company to charge for its retail services, and the tariff rate that the Federal Energy Regulatory Commission permits Idaho Power Company to charge for transmission, are the most significant factors influencing IDACORP, Inc.’s and Idaho Power Company’s financial position, results of operations, and liquidity. The Idaho Public Utilities Commission and Oregon Public Utility Commission have the authority to disallow recovery of any costs that they consider unreasonable or imprudently incurred, and the formula rates allowed by the Federal Energy Regulatory Commission may be insufficient for recovery of costs incurred. While the Idaho Public Utilities Commission and Oregon Public Utility Commission have established through the ratemaking process an authorized rate of return for Idaho Power Company, the regulatory process does not provide assurance that Idaho Power Company will be able to achieve the earnings level authorized. Further, while the Idaho Public Utilities Commission and Oregon Public Utility Commission are required to establish rates that are fair, just, and reasonable, they have significant discretion in applying this standard. The ratemaking process typically involves multiple parties, including governmental bodies, consumer advocacy groups, and various consumers of energy, each party has differing concerns but have the common objective of limiting rate increases or even reducing rates. Idaho Power Company cannot predict the ultimate outcomes of any ratemaking proceedings, including the extent to which certain costs—such as significant capital projects—will be recovered or what rates of return will be allowed.

In January 2010, the Idaho Public Utilities Commission approved a settlement agreement that imposed a general rate moratorium in effect in the Idaho jurisdiction until January 1, 2012. While the moratorium does not apply to other specified revenue requirement proceedings, such as the power cost adjustment, the fixed cost adjustment, pension funding, advanced metering infrastructure, energy efficiency rider, and government imposed fees, Idaho Power Company attempts to manage its costs consistent with the moratorium. However, if Idaho Power Company is unable to do so, or if such cost management results in increased operational risk, the moratorium could adversely affect Idaho Power Company’s operations or results of operations.

Idaho Power Company has power cost adjustment mechanisms that provide for periodic adjustments to the rates charged to its Idaho and Oregon retail customers. The power cost adjustment tracks Idaho Power Company’s actual net power supply costs (primarily fuel and purchased power less off-system sales) and compares these amounts to net power supply costs currently being recovered in retail rates. A majority, but not all, of the variance between these two amounts is deferred for future recovery from or refund to customers. Accordingly, the power cost adjustment mechanism only partially offsets the potentially adverse financial impacts of forced generating plant outages, severe weather, reduced hydroelectric generating availability, and volatile wholesale energy prices. Because of the power cost adjustment mechanism, the primary financial impact of power supply cost variations is on the timing of cash flows. When costs rise above the level recovered in retail rates it adversely affects Idaho Power Company’s operating cash flow and liquidity until those costs are recovered from customers.

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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, the availability of 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, as a result of its power cost adjustment mechanisms, the majority of its 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 January 2010 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 a 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’s 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. Increases in market prices for coal and natural gas can result in reduced earnings. Increases in demand for natural gas may result in market price increases, short-term price volatility, and supply availability issues. Operation of the Langley Gulch power plant that Idaho Power Company is currently constructing will increase Idaho Power Company’s demand for natural gas, and thus its exposure to volatility in natural gas prices. 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, which may adversely impact earnings.

Idaho Power Company’s power generating facilities are subject to numerous operational risks unique to it and its industry. Operating risks associated with hydroelectric, natural gas, coal, and other generation facilities include equipment failures, volatility in fuel and transportation pricing, interruptions in fuel supplies, regulatory compliance obligations and costs, labor disputes, workforce safety matters, and catastrophic events at the facilities. These operational risks may result in plant outages, as well as increased operation and maintenance expenses, power generation costs, and power purchase 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. While Idaho Power Company’s customer growth rate has slowed in recent years, 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 that demand. 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. Load growth can result in the need for additional investments in Idaho Power Company’s infrastructure to serve the new load. For instance, to meet customer demand Idaho Power Company is currently constructing its Langley Gulch natural gas-fired generating plant, and has in development a number of transmission projects. If Idaho Power Company was 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 disconnect between the time expenditures are made and costs are recovered would have a negative effect on earnings and cash flows. Load growth can create planning and operating difficulties for Idaho Power Company that can negatively impact its ability to reliably serve customers.

Weather and climate change could affect customer demand and hydroelectric generation and disrupt transmission and distribution systems, reducing 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

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events can disrupt transmission and distribution systems and cause service interruptions and extended outages, increase supply chain costs, and potentially interrupt use of generation resources and limit the ability to meet customer demand. Disruption in transmission and distribution systems increases operations and maintenance expenses and reduces earnings and cash flows.

In addition, long-term climate change could affect Idaho Power Company’s business in a variety of ways, including:

• changes in temperature and precipitation could affect customer demand;

• extreme weather events could increase service interruptions, outages, and maintenance costs;

• changes in the amount and timing of snowpack and stream flows could adversely affect hydroelectric generation;

• legislative and/or regulatory developments related to climate change could affect plans and operations, including placing restrictions on the construction of new generation resources and the expansion of existing resources, result in closure of generation resources or installation of costly pollution control equipment, or require changes to the operation of generation resources in general; and

• consumer preference for, and resource planning decisions requiring, renewable or low greenhouse gas-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 decrease revenues, increase operating costs, and reduce IDACORP, Inc.’s and Idaho Power Company’s 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 as a result Idaho Power Company may suffer economic losses. Idaho Power Company is exposed to the risk that counterparties that owe it money will default on their obligations. A similar risk of non-performance by third parties arises where those parties are obligated to purchase energy from, or sell energy to, Idaho Power Company, or are parties to commodity price risk management arrangements. 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 its 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 Idaho Power Company enters into its hedging transactions 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 IDACORP, Inc.’s and Idaho Power Company’s financial condition, results of operations, or cash flows.

Increased capital expenditures for power generation and delivery infrastructure development and replacement can significantly affect liquidity. Idaho Power Company’s business is capital intensive and requires significant investments in energy generation and in other infrastructure projects. Increases in both the number of customers and the demand for energy require expansion and reinforcement of transmission and distribution systems, generating facilities, and other infrastructure. The cost of maintaining existing, aging equipment and infrastructure and developing new infrastructure is substantial, and involves risks relating to, among other things, cost overruns, unscheduled outages, price increases in commodities (such as steel and copper) and other materials necessary for developing infrastructure, and denial of regulatory recovery. If Idaho Power Company does not receive timely regulatory recovery of costs associated with those expansion and reinforcement activities or other capital projects, Idaho Power Company will have to rely more heavily 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, which could affect reliability and increase maintenance costs. 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.

The performance of pension and postretirement benefit plan investments and other factors impacting plan costs could adversely impact cash flow and liquidity. Idaho Power Company provides a noncontributory defined benefit pension plan covering most employees, as well as a defined benefit postretirement benefit plan (consisting of health care and death benefits) that covers eligible retirees. Costs of providing these benefits are based in part on the value of the plan’s assets and, therefore, adverse investment performance for these assets could increase Idaho Power Company’s funding requirements related to the plans. The key actuarial assumptions that affect expense are the expected long-term return on plan assets and the discount rate used in determining future benefit obligations. Management evaluates the actuarial assumptions on an annual basis, taking into account changes in market conditions, trends, and future expectations. Estimates of future stock market performance, changes in interest rates, and other factors used to develop the actuarial assumptions are uncertain, and actual results could vary significantly from the estimates. Changes in demographics, including increased numbers of retirements or changes in life expectancy assumptions, may also increase the funding requirements of the obligations related to the pension and other postretirement benefit plans. Depending on the timing of contributions to the plans and the availability of recovery of costs through rates, cash contributions to the plans could impact IDACORP, Inc.’s and Idaho Power Company’s cash flow and liquidity.

Complying with existing and future 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. Members of Congress have proposed 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 or state programs 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 other states could adopt renewable energy portfolio standards that are applicable to Idaho Power in the future. 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 the Langley Gulch power plant 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

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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, and future transmission projects. Similarly, the presence of sage grouse in the vicinity of Idaho Power’s Boardman to Hemingway and Gateway West 500-kV transmission line projects has required more extensive, costly, and time consuming evaluation and engineering. The impact of the Endangered Species Act, including the potential listing of additional fish, wildlife, or plant species, and similar laws may require mitigation, cause a delay in relicensing or construction of projects, affect the location or ability to construct a project, increase the costs of construction and operations, and reduce earnings and cash flows.

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 some of its hydroelectric projects, including its largest hydroelectric generation source, the Hells Canyon Complex. Relicensing includes an extensive public review process that involves numerous natural resource issues and environmental conditions. The listing of various species of marine life, wildlife, and plants as threatened or endangered has resulted in significant changes to federally-authorized activities, including those of hydroelectric projects. Salmon and other marine life recovery plans could include further major operational changes to the region’s hydroelectric projects. In addition, new interpretations of existing laws and regulations could be adopted or become applicable to such facilities, which could further increase required expenditures for marine life recovery and endangered species protection and reduce the amount of hydroelectric generation available to meet Idaho Power Company’s energy requirements.

In 2007, the Federal Energy Regulatory Commission Staff issued a final environmental impact statement for the Hells Canyon Complex, which the Federal Energy Regulatory Commission will use in part to determine whether, and under what conditions, to issue a new license for the Hells Canyon Complex. Certain portions of the final environmental impact statement involve issues that may be influenced by water quality certifications for the project under Section 401 of the Clean Water Act and formal consultations under the Endangered Species Act, which remain unresolved. One significant issue involves water temperature gradients, and certain parties in the Hells Canyon Complex relicensing proceedings have advocated for the installation of water temperature management apparatus which, if required to be installed, would require substantial capital expenditures to construct and maintain. There can be no assurance that recovery through rates would be authorized, particularly given the magnitude of any potential impact on customer rates, which at this time cannot be accurately predicted. Idaho Power Company also cannot predict the requirements that might be imposed during the relicensing process, the economic impact of those requirements, or whether a new multi-year license will ultimately be issued. Imposition of onerous conditions in the relicensing process could result in Idaho Power incurring significant capital expenditures, increase operating costs, and reduce hydroelectric generation, which could 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 self-reported compliance issues to the Federal Energy Regulatory Commission and to the Western Electricity Coordinating Council. Several of the matters self-reported to the Federal Energy Regulatory Commission and the Western Electricity Coordinating Council remain outstanding. Compliance with these requirements directly influences Idaho Power Company’s operating environment and may significantly increase Idaho Power Company’s operating costs. Further, potential monetary and non-monetary penalties for a violation of Federal Energy Regulatory Commission regulations may be substantial, and in some circumstances monetary penalties may be as high as $1 million per day per violation. The imposition of penalties on Idaho Power Company could have an adverse impact on its and IDACORP, Inc.’s results of operations, financial condition, and cash flows.

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IDACORP, Inc., its subsidiary 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. For instance, in September 2010, the Environmental Protection Agency issued a Notice of Violation to Portland General Electric Company, the majority owner of the Boardman plant, alleging that Portland General Electric Company had violated the New Source Performance Standards and operating permit requirements under the Clean Air Act, as a result of modifications made to the plant in 1998 and 2004. 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 with no significant operations of its own, and 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 each subsidiaries’ 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 or equity 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 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, or result in losses on investments. IDACORP, Inc. and Idaho Power Company require liquidity to pay operating expenses and principal of and interest on debt and to finance capital expenditures not satisfied by cash flows from operations. Financial markets have in recent years experienced extreme volatility and disruption, generally resulting in a decrease in the availability of liquidity and credit for borrowers. In a volatile credit environment, one or more of the participating banks in IDACORP, Inc.’s and Idaho Power Company’s credit facilities may default on their obligations to make loans under, or withdraw from, the credit facilities, or IDACORP, Inc.’s and Idaho Power Company’s access to capital may otherwise be inhibited. In addition, at times Idaho Power Company has a relatively large balance of short-term investments, particularly during times when it has issued debt or equity securities to fund future debt maturities not yet due and capital expenditure requirements payable over time. Volatility in the financial markets may result in a lack of liquidity for short-term investments and declines in value of some investments. The occurrence of any of these events could adversely affect IDACORP, Inc.’s and Idaho Power Company’s earnings, liquidity, and financial condition.

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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 high rates of unemployment contributed to a recent recession. These factors have resulted, and may continue to result, in an increase in late payments and uncollectible accounts, which 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. Beginning in 2008, economic conditions in Idaho Power Company’s service area have been relatively weak. Unemployment rates are high relative to historic unemployment levels and customer growth has been slow relative to prior years. The recent recession and increased rates may reduce the amount of energy Idaho Power Company’s customers consume, result in a loss of customers, and reduce the customer growth rate. A decrease in overall customer usage may reduce revenues, earnings, and future growth.

Changes in tax laws and regulations, or differing interpretation or enforcement of applicable laws by the Internal Revenue Service or other taxing jurisdictions, could have a material adverse impact on IDACORP, Inc.’s or Idaho Power Company’s financial condition. IDACORP, Inc. and Idaho Power Company must make judgments and interpretations about the application of the law when determining the provision for taxes. The companies’ tax obligations include income, real estate, public utility, municipal, sales and use, business and occupation, and employment-related taxes and ongoing issues related to these taxes. These judgments may include reserves for potential adverse outcomes regarding tax positions that may be subject to challenge by taxing authorities. For instance, in September 2010, Idaho Power Company adopted a tax accounting method change for repair-related expenditures on utility assets concurrent with the filing of IDACORP, Inc.’s 2009 consolidated federal income tax return. Also in the third quarter of 2010, Idaho Power Company reached an agreement with the Internal Revenue Service, subject to subsequent review by the U.S. Congress Joint Committee on Taxation, regarding the allocation of mixed service costs in its method of uniform capitalization. The outcome of ongoing and future income tax proceedings such as these could differ materially from the amounts currently recorded, and the difference could reduce IDACORP, Inc.’s and Idaho Power Company’s earnings and cash flows. Further, in some instances the treatment from a ratemaking perspective of any benefits from tax-related projects, or the reversal of reserves recorded by IDACORP, Inc. or Idaho Power Company for tax-related matters such as those described above, could be different than IDACORP, Inc. or Idaho Power Company currently anticipate or in the future request from the regulatory bodies. The Idaho Public Utilities Commission or Oregon Public Utility Commission could, for instance, determine that all or a portion of any benefits resulting from tax-related projects be shared with customers in the form of reduced rates or otherwise, which may reduce revenue, 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. Idaho Power Company’s operations require a skilled workforce to perform specialized, complex utility functions. Idaho Power Company expects that a significant portion of its skilled workforce will be retiring within the coming decade, which places demand on Idaho Power Company to attract and retain skilled workers. Without a skilled workforce, Idaho Power Company’s ability to provide quality service to its customers and meet regulatory requirements will be challenged and could affect earnings. Also, the costs associated with 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. Idaho Power Company’s generation and transmission facilities are potential targets for terrorist threats and activities. The possibility that infrastructure facilities, such as fossil and hydroelectric generation facilities and electric transmission and distribution facilities, would be direct targets of, or indirect casualties of, an act of terror may affect Idaho Power Company’s operations. Instability in the financial markets as a result of terrorism, war, and similar actions may also affect Idaho Power Company’s results of operations and its ability to raise capital. Further, the implementation of security guidelines and measures has resulted in and is expected to continue to result in increased compliance costs.

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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, and operates systems that directly impact the availability of electric power and the transmission of electric power in the electric grid. 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.

Idaho Power Company’s ability to enter into over-the-counter derivatives and hedge commodity and interest rate risk may be adversely affected by recent federal legislation. In July 2010, Congress enacted, and President Obama signed, financial reform legislation known as the Dodd-Frank Wall Street Reform and Consumer Protection Act. Title VII of the legislation provides for the regulation of the over-the-counter derivatives market, and requires the posting of cash collateral for uncleared swaps. If the rules enacted under the legislation require that Idaho Power Company post cash collateral on its swap or derivative transactions, its liquidity may be adversely affected, and rules promulgated under the legislation may impair Idaho Power Company’s ability to enter into over-the-counter derivatives to hedge commodity and interest rate risks.

ITEM 1B. UNRESOLVED STAFF COMMENTS

None.

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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. Idaho Power is also constructing a natural gas-fired combined cycle power plant in Idaho with a summer nameplate capacity of 300 MW. As of December 31, 2010, the system also includes approximately 4,817 pole miles of high-voltage transmission lines, 23 step-up transmission substations located at power plants, 24 transmission substations, 10 switching stations, 228 energized distribution substations (excluding mobile substations and dispatch centers), and approximately 26,698 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	⁽¹⁾
			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 the application for a 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.”

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Idaho Power owns all of its interests in 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 BCC 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 – “Contingencies” to IDACORP’s and Idaho Power’s consolidated financial statements included in this report.

ITEM 4. (Reserved)

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 (NYSE). On February 17, 2011, there were 13,132 holders of record of IDACORP common stock and the closing stock price was $38.04 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 Part II, Item 7 - “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 in the respective credit facilities, of no more than 65 percent at the end of each fiscal quarter.

Idaho Power’s Revised Code of Conduct approved by the IPUC on April 21, 2008, states that Idaho Power will not pay any dividends to IDACORP that will reduce Idaho Power’s common equity capital below 35 percent of its total adjusted capital without IPUC approval. Idaho Power’s ability to pay dividends on its common stock held by IDACORP and IDACORP’s ability to pay dividends on its common stock are limited to the extent payment of such dividends would violate the covenants or Idaho Power’s Code of Conduct. At December 31, 2010, the leverage ratios for IDACORP and Idaho Power were 52 percent and 53 percent, respectively. Based on these restrictions, IDACORP’s and Idaho Power’s dividends were limited to $628 million and $538 million, respectively, at December 31, 2010. Idaho Power must obtain approval of the OPUC before it can directly or indirectly loan funds or issue notes or give credit on its books to IDACORP.

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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 $58 million, $57 million, and $54 million in 2010, 2009, and 2008, respectively.

The following table shows the reported high and low sales price of IDACORP’s common stock and dividends paid for 2010 and 2009 as reported in the NYSE’s consolidated transaction reporting system.

		Quarters
Common Stock, without par value:		1^st		2^nd		3^rd		4^th
2010
	High	$	35.69	$	36.93	$	36.98	$	37.76
	Low		29.98		31.22		32.46		35.46
	Dividends paid per share		0.30		0.30		0.30		0.30
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

IDACORP, Inc. did not repurchase any shares of its common stock during the fourth quarter of 2010.

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, 2005, with beginning-of-period weighting of the peer group indices (based on market capitalization) and monthly compounding of returns.

Source: Bloomberg and EEI

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					EEI Electric
	IDACORP		S & P 500		Utilities Index
2005	$	100.00	$	100.00	$	100.00
2006		136.37		115.78		120.76
2007		128.74		122.14		140.75
2008		111.99		76.96		104.29
2009		127.17		97.33		115.46
2010		152.41		112.01		123.58

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)
			2010		2009		2008		2007		2006
Operating revenues		$	1,036,029	$	1,049,800	$	960,414	$	879,394	$	926,291
Operating income			198,670		203,583		190,667		152,078		169,704
Net income attributable to IDACORP, Inc.			142,798		124,350		98,414		82,272		100,075
Diluted earnings per share from
	continuing operations		2.95		2.64		2.17		1.86		2.34
Dividends declared per share			1.20		1.20		1.20		1.20		1.20

Financial Condition:
Total assets		$	4,676,055	$	4,238,727	$	4,022,845	$	3,653,308	$	3,445,130
Long-term debt (including current portion)			1,610,859		1,419,070		1,269,979		1,168,336		1,023,773

Financial Statistics:
Times interest charges earned:
	Before tax ⁽¹⁾		2.65		2.88		2.47		2.35		2.78
	After tax ⁽²⁾		2.66		2.59		2.23		2.16		2.54
Book value per share ⁽³⁾⁽⁷⁾		$	31.01	$	29.17	$	27.76	$	26.79	$	25.65
Market-to-book ratio ⁽⁴⁾⁽⁷⁾			119%		110%		106%		131%		151%
Payout ratio ⁽⁵⁾			41%		45%		55%		65%		48%
Return on year-end common equity ⁽⁶⁾⁽⁷⁾			9.3%		8.9%		7.6%		6.8%		9.6%

The financial statistics listed above are calculated in the following manner:
⁽¹⁾ The sum of interest on long-term debt, other interest expense excluding 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, excluding non-controlling interests, 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 diluted earnings per share for the year.
⁽⁶⁾ Net income divided by total equity, excluding non-controlling interests, at the end of the year.
⁽⁷⁾Prior year amounts have been adjusted to reflect the exclusion of non-controlling interests.

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In the second quarter of 2006, IDACORP management designated the operations of two subsidiaries, IDACORP Technologies, Inc. and IDACOMM, Inc., 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

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

FORWARD-LOOKING STATEMENTS

In addition to the historical information contained in this report, this report contains (and oral communications made by IDACORP, Inc. and Idaho Power Company may contain) statements that relate to future events and expectations and, as such, constitute forward-looking statements within the meaning of the Private Securities Litigation Reform Act of 1995. Any statements that express, or involve discussions as to expectations, beliefs, plans, objectives, assumptions, or future events or performance, often, but not always, through the use of words or phrases such as “anticipates,” “believes,” “estimates,” “expects,” “intends,” “targets,” “plans,” “predicts,” projects,” “may result,” “may continue,” or similar expressions, are not statements of historical facts and may be forward-looking. Forward-looking statements are not guarantees of future performance and involve estimates, assumptions, risks, and uncertainties. Actual results, performance, or outcomes may differ materially from those expressed in or implied by those forward-looking statements. For a discussion of some of the specific factors that may cause IDACORP, Inc.’s and Idaho Power Company’s actual results to differ materially from those projected in any forward-looking statements, see the following sections of this report: Part I, Item 1A - “Risk Factors”; Part II, Item 7 - “Management’s Discussion and Analysis of Financial Condition and Results of Operations,” including the disclosures under “Critical Accounting Policies and Estimates”; and Notes 2, 11, and 15 to the Consolidated Financial Statements in Part II, Item 8 - “Financial Statements and Supplementary Data.”

Any forward-looking statement speaks only as of the date on which such statement is made. New factors emerge from time to time and it is not possible for management to predict all such factors, nor can it assess the impact of any such factor on the business or the extent to which any factor, or combination of factors, may cause results to differ materially from those contained in any forward-looking statement. IDACORP, Inc. and Idaho Power Company disclaim any intention or obligation to update publicly any forward-looking statements, whether in response to new information, future events, or otherwise, except as required by applicable law.

INTRODUCTION

The following Management’s Discussion and Analysis of Financial Condition and Results of Operations (MD&A) presents 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).

IDACORP is a holding company formed in 1998 whose principal operating subsidiary is Idaho Power. IDACORP’s common stock is listed and trades on the New York Stock Exchange under the trading symbol “IDA.”

Idaho Power is an electric utility with a service territory covering approximately 24,000 square miles in southern Idaho and eastern Oregon. Idaho Power provided electric service to approximately 492,000 general business customers as of December 31, 2010. Idaho Power is regulated by the Federal Energy Regulatory Commission (FERC) and the state regulatory commissions of Idaho and Oregon. Idaho Power is the parent of Idaho Energy Resources Co. (IERCo), a joint venturer in Bridger Coal Company (BCC), which mines and supplies coal to the Jim Bridger generating plant owned in part by Idaho Power.

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Idaho Power generates revenues and cash flows primarily from the sale and distribution of electricity to customers in its Idaho and Oregon service territory, as well as from wholesale electricity sales and transmission of electricity for others. Idaho Power’s revenues and income from operations are subject to fluctuations during the year due to the impacts of seasonal weather conditions on demand for electricity, price changes, customer usage patterns (which are affected in large part by the condition of the local economy), and the availability and price of purchased power and fuel. Idaho Power is a dual peaking utility that typically experiences its highest retail energy sales during the summer irrigation and cooling season, with a lower peak in the winter that generally results from heating demand. IDACORP’s and Idaho Power’s financial condition are also affected by regulatory decisions, through which Idaho Power seeks to recover its costs on a timely basis and to earn an authorized return on investment, and by the ability to obtain financing through the issuance of debt and/or equity securities.

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

While reading the MD&A, please refer to the accompanying consolidated financial statements of IDACORP and Idaho Power which present for each company their financial positions at December 31, 2010 and 2009, and their results of operations and cash flows for the years ended December 31, 2010, 2009, and 2008.

EXECUTIVE OVERVIEW

Business Strategy

IDACORP’s business strategy emphasizes Idaho Power as IDACORP’s core business. Idaho Power has a three-part strategy of responsible planning, responsible development and protection of resources, and responsible energy use to ensure adequate energy supplies. Idaho Power’s business strategy seeks to balance the interest of owners, customers, employees, and other stakeholders while maintaining the company’s financial stability and flexibility. Idaho Power’s planning process is intended to ensure adequate generation and transmission resources to meet population and electricity demand growth. Idaho Power’s business strategy includes the development and protection of generation, transmission, distribution, and associated infrastructure, and stewardship of the natural resources Idaho Power and the communities the company serves depend upon. Idaho Power’s business strategy also includes the use of energy efficiency and demand response programs and preparation for potential carbon and renewable portfolio standard (RPS) legislation, and targeted reductions relating to carbon emission intensity and public reporting of these reductions.

Overview of Major Factors Affecting Results of Operations and Financial Condition

IDACORP and Idaho Power’s results of operations and financial condition are affected, and will likely continue to be affected, by important business, regulatory, economic, and other factors, as discussed below.

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

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decisions on Idaho Power’s business and financial condition, the company’s management focuses on timely recovery of its costs through filings with the IPUC and the OPUC.

A January 2010 settlement stipulation approved by the IPUC applied a moratorium on general rate relief until January 2012. As a result, Idaho Power’s first opportunity to file a new general rate case with the IPUC is June 2011. As of the date of this report, Idaho Power is evaluating its general rate case needs and options.

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

Idaho Power’s rate structure includes methods such as tiered rates and time-of-use rates. These methods divide a customer’s energy usage into separate tiers and/or time periods based on how many kilowatt-hours of energy a customer uses and the time during which the energy was consumed, and increases the cost of power consumed depending on the applicable tier and time of consumption. Customers are typically required to pay more for energy during periods of high demand and when the amount of usage is large enough to implicate higher rate tiers. These tiers are established by the IPUC and OPUC and are intended to promote energy efficiency and help customers identify opportunities to manage their energy usage and power bill. However, this rate structure can have a significant impact on Idaho Power’s results of operations compared to a flat rate structure, as revenues are more negatively impacted when customers’ usage does not reach the expected rate tier brackets, and more positively impacted when customers use energy in higher-tier pricing brackets and during peak demand times when power rates to customers are higher.

Economic Conditions: Economic conditions within and outside of Idaho Power’s service area can impact consumer demand for electricity, collectability of accounts, the volume of off-system sales due to power demand, and Idaho Power’s need for purchased power. Since 2008, economic conditions in Idaho Power’s service area have been relatively weak. Unemployment rates remain high relative to historic unemployment levels and the customer growth rate has been slow relative to prior years. Management cannot predict when economic recovery may occur in Idaho Power’s service territory. As such, Idaho Power seeks to manage costs while executing on its three part strategy of responsible planning, responsible development and protection of resources, and responsible energy use. In the current economic environment, management continues to focus on factors such as customer growth, customer load, future capital requirements and the timing of capital expenditures, system reliability and efficiency, liquidity and access to capital markets, accounts receivable balances and collections, employee remuneration and retirement benefits plans, and counterparty risk.

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

The effect of weather on Idaho Power’s hydroelectric power generation projects can also impact Idaho Power’s financial condition and results of operations. Hydroelectric generation depends on stream flows in the Snake River and its tributaries, on which Idaho Power’s hydroelectric facilities are built. 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 in the Snake River, spring flows, rainfall, the amount and timing of water leases, and other weather and stream flow management considerations. During low water years, when stream flows into Idaho Power’s hydroelectric projects are reduced and reservoir storage is low, Idaho Power’s hydroelectric generation is

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reduced. This results in reduced generation from Idaho Power’s resource portfolio available to serve Idaho Power’s customers and for off-system sales and, generally, an increased use of more expensive coal- or gas-fired generation or purchased power to meet load requirements. Both of these situations result in increased power supply costs. Regional energy market prices can also be affected by hydroelectric generating conditions. In times with high hydroelectric generation, the availability of abundant energy tends to reduce wholesale prices, and during low hydroelectric generation, wholesale prices tend to be higher. While the cost of purchased power is typically higher than the cost of hydroelectric generation, the incremental cost is currently included in the PCA mechanisms that allow Idaho Power to recover most of these costs.

Fuel and Power Supply: In addition to hydroelectric generation, Idaho Power relies primarily on coal and natural gas to fuel its generation facilities. Recently, Idaho Power has experienced an increase in coal prices. Fuel expense at the Jim Bridger plant increased $15 million in 2010 compared to 2009, primarily due to continued production cost increases for coal mined at BCC and higher coal contract prices. In order to help ensure the continued supply of coal for the Jim Bridger plant, BCC received approval in July 2010 from the U.S. Bureau of Land Management (BLM) to modify BCC’s existing federal coal lease to include 560 acres of adjacent coal lands for mine development, and BCC plans to increase lease holdings on bordering private lands for a total increase of approximately 2,000 acres.

Increases in demand for natural gas may result in market price increases, short-term price volatility, and/or supply availability issues. Operation of the Langley Gulch power plant that Idaho Power is currently constructing will increase Idaho Power’s demand for natural gas, and thus its exposure to volatility in natural gas prices.

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

Idaho Power uses derivative instruments, such as physical and financial forward contracts, for both electricity and fuel in order to manage the risks relating to fuel and power price exposures. Idaho Power has an energy risk management policy and programs designed to reduce exposure to power supply cost-related uncertainties.

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

Idaho Power is also subject to a substantial body of rapidly changing regulations by federal, state, and local authorities governing the protection of the environment. Environmental laws and regulations may, among other things, increase the cost of operating power generation plants and constructing new facilities; require that Idaho Power install additional pollution control devices at existing generating plants; or require that Idaho Power shut down certain power generation plants. For instance, the Boardman coal-fired power plant, in which Idaho Power owns a 10 percent interest, was recently the subject of proceedings with Oregon regulators relating to the installation of costly emission controls and an anticipated early shut-down of the facility in 2020, and in September 2010 the Environmental Protection Agency (EPA) issued a Notice of Violation to Portland General Electric (PGE), the operator of the Boardman plant, alleging Clean Air Act (CAA) violations. Compliance with environmental laws and regulations will result in increases to capital expenditures and operating expenses. Idaho Power intends to seek recovery of such costs through the ratemaking process.

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Idaho Power is involved in renewing federal licenses for the Hells Canyon Complex (HCC), its largest hydroelectric generation source, and the Swan Falls hydroelectric project. Relicensing involves numerous environmental issues and substantial costs. Idaho Power is working with the states of Idaho and Oregon, regulatory authorities, and interested parties to address concerns and take appropriate measures relating to the relicensing of Idaho Power’s hydroelectric projects. Given the number of parties and issues involved, Idaho Power expects that relicensing costs could be substantial and will be submitted to regulators for recovery through the ratemaking process.

IDACORP and Idaho Power are unable to predict the outcome of these matters or estimate the impact they may have on their consolidated financial position, results of operations, or cash flow.

Other Significant Pending and Completed Matters

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

Load-Growth Adjustment Rate Mechanism: In its May 2010 order approving a decrease in the 2010 PCA mechanism and increase in Idaho base rates, the IPUC identified the use of the load growth adjustment rate (LGAR) in times of load decline as an area of contention. On January 14, 2011, Idaho Power submitted comments in support of a revised methodology that was submitted by another utility to the IPUC for consideration. Under the revised methodology, the LGAR would be calculated based on the company’s embedded production revenue requirement that is classified as energy-related or variable for ratemaking purposes. Approval of the new methodology and rate would result in Idaho Power collecting a greater or lesser amount through the PCA mechanism, depending on whether loads during the applicable period increased or decreased.

Retirement Benefit Plans: In September 2010, Idaho Power contributed $60 million to its defined pension plan. The contribution was in excess of the $6 million minimum contribution required to be made in September 2010 for the 2009 plan year. On October 1, 2010, Idaho Power filed an application with the IPUC requesting acceptance of Idaho Power’s 2011 retirement benefit plans. On January 26, 2011, the IPUC issued an order stating that Idaho Power is not precluded from filing for recovery of 2010 contributions before proceedings relating to the October 2010 application are completed. As of the date of this report, a determination and order on the prudency of the 2011 retirement benefits package is pending.

PURPA Contracts: Pursuant to the requirements of Section 210 of PURPA, the IPUC and OPUC have each issued orders and rules regulating Idaho Power’s purchase of power from cogeneration and small power production (CSPP) facilities. A key component of the PURPA power purchase contracts is the energy price contained within the agreements. Regulatory mandated execution of PURPA agreements may result in Idaho Power acquiring energy 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 Idaho Power’s customers. Substantially all PURPA power purchase costs are recovered through base rates and Idaho Power’s power supply cost mechanisms, and thus the primary impact of the PURPA agreements is on customer rates. In response to a November 5, 2010 application filed by Idaho Power and two other electric utilities with Idaho service territories, on February 7, 2011, the IPUC issued an order temporarily reducing the eligibility cap for projects entitled to published avoided cost rates from 10 average MW to 100kW for wind and solar PURPA projects while the IPUC further investigates the implications of large projects disaggregating into smaller projects to qualify for higher Published Avoided Cost rates, tax incentives, and other benefits.

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Integrated Resource Plan (IRP): Idaho Power’s 2009 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. The IPUC accepted for filing the 2009 IRP in August 2010. In October 2010, the OPUC issued an order acknowledging Idaho Power’s 2009 IRP. As of the date of this report, Idaho Power is evaluating its resource portfolio and needs and is working to develop its 2011 IRP.

Water Management Issues: Power generation at the Idaho Power hydroelectric power plants on the Snake River and its tributaries 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.

Summary of 2010 Financial Results

IDACORP’s net income and earnings per diluted share for the years ended 2010, 2009, and 2008 were as follows:

	2010		2009		2008
Net Income Attributable to IDACORP, Inc.	$	142,798	$	124,350	$	98,414
Average outstanding shares - diluted (000s)		48,340		47,182		45,379
Earnings per diluted share	$	2.95	$	2.64	$	2.17

The following table presents a reconciliation of IDACORP net income for 2009 to 2010 (in millions):

Net Income Attributable to IDACORP, Inc. - 2009					$	124.4
Change in Idaho Power net income before taxes:
	Rate and other regulatory changes, including power cost and fixed cost
		adjustment mechanisms	$	23.9
	Reduced sales volumes			(18.4)
	Oregon 2007 excess power cost deferral in 2009			(6.4)
	Increased transmission and property rental revenues			4.3
	Increased depreciation expense			(5.3)
	Increased property tax			(3.0)
	Other decreases			(1.0)
		Change in Idaho Power income from operations		(5.9)
	Change in life insurance benefits			(4.3)
	Change in earnings at BCC			3.0
	Other net increases			0.5
Capitalized repairs method change net income tax benefit				41.5
Other income tax expense				(16.7)
	Total increase in Idaho Power net income					18.1
Change in subsidiary earnings and holding company expenses (net of tax)						0.3
	Net Income Attributable to IDACORP, Inc. - 2010				$	142.8

Idaho Power’s 2010 operating income decreased $5.9 million as compared to 2009. Regulatory changes, which include the Idaho rate settlement benefits and the impacts of the PCA and FCA mechanisms, increased operating income by $23.9 million and were partially offset by reductions in sales volumes of $18.4 million. Idaho Power’s operating income also decreased due to a $6.4 million Oregon excess power cost recovery recorded in 2009 that did not recur in 2010.

Sales volumes decreased four percent for the year as compared to 2009 in all customer classes, except irrigation. Mild weather contributed to the reduced electricity demand for customers who rely on electric power for cooling and heating. Other contributing factors included increased energy conservation and continued weak economic conditions evidenced by relatively high unemployment levels and nominal

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customer growth. Relatively low precipitation in Idaho Power’s service territory during the third quarter of 2010 contributed to increased sales to irrigation customers, who rely on electric power to operate irrigation systems. Volume decreases were partially offset by the FCA mechanism and lower power supply costs.

Other items influencing the change in Idaho Power’s 2010 operating income from 2009 included:

transmission revenues, a component of other revenues, increased $4.3 million, resulting primarily from new transmission facilities and increases in the FERC formula rate for transmission services;
depreciation expense increased $5.3 million, due to the acceleration of depreciation expense for non-AMI meters related to Idaho Power’s conversion to Advanced Metering Infrastructure (AMI). Idaho Power has regulatory orders to collect an offsetting amount through rates; and
property tax for Idaho increased $3.0 million, primarily due to lower residential and commercial values in other property classes shifting tax costs to centrally assessed property.

A tax accounting method change for repair-related expenditures on utility assets for the 2009 tax year significantly impacted IDACORP’s and Idaho Power’s 2010 results. In 2010, Idaho Power recorded a tax benefit of $44.5 million related to the cumulative effect of the method change (tax years 1999 through 2009) and included an annual deduction estimate in its 2010 income tax provision, which resulted in an $11.7 million tax benefit. Idaho Power has recorded a current liability for uncertain tax positions of $14.7 million relating to the tax accounting method change for repair-related expenditures.

Also during 2010, Idaho Power recorded a tax method change relating to uniform capitalization with the tax benefits fully offset by a current uncertain tax position liability equal to the 2010 net tax benefit, resulting in no impact on IDACORP's or Idaho Power's net income for 2010. Initially, an uncertain tax position liability of $65.3 million was established for this method change. For the 2010 year, reversing impacts of this temporary difference reduced the uncertain tax position liability by $5.6 million bringing the year-end balance to $59.7 million. While Idaho Power has an agreement with the IRS for examination and tax return filing purposes, it is awaiting U.S. Congress Joint Committee on Taxation approval of its method or approval of methods filed by other similarly-situated companies before concluding that the new method is effectively settled for financial reporting purposes.

Summary of Liquidity and Capital Requirements

IDACORP and Idaho Power expect to continue financing capital requirements with a combination of internally generated funds and externally financed capital. In August 2010, Idaho Power issued $200 million of first mortgage bonds. During 2010, IDACORP issued 973,585 shares of its common stock at an average price of $35.47 for aggregate net proceeds of $34 million, pursuant to its continuous equity program. IDACORP contributed $50 million of additional equity to Idaho Power in 2010.

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

• Langley Gulch Power Plant: Langley Gulch is a natural gas-fired combined cycle combustion turbine (CCCT) generating plant with a summer nameplate capacity of approximately 300 MW and a winter capacity of approximately 330 MW. Construction of the plant is underway and is contracted to achieve commercial operation in November 2012. The contract contains incentives intended to advance the in-service date, and Idaho Power estimates that the plant will be in service by June 2012. The total cost estimate for the project including allowance for funds used during construction (AFUDC) is $427 million, $206 million of which Idaho Power has incurred from the inception of the project through December 31, 2010;

• Transmission Projects: Idaho Power is pursuing the development of the Boardman-Hemingway line, a proposed 500-kV line between a station near Boardman, Oregon, and the Hemingway station near Boise, Idaho. Idaho Power estimates total construction costs of $820 million and expects its share of the project to be between 30 and 50 percent. Idaho Power is discussing joint development of the project with other parties. Idaho Power and PacifiCorp are also pursuing the joint development of Gateway West, a project to build transmission lines between Windstar, a station located near Douglas, Wyoming, and the Hemingway station. The current estimated cost for Idaho Power’s share of the Gateway West project is between $300 million and $500 million;

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

• AMI / Smart Grid (American Recovery and Reinvestment Act of 2009 (ARRA)): Under the ARRA, in April 2010 Idaho Power finalized the award of a grant of $47 million from the U.S. Department of Energy (DOE). This grant will match a $47 million investment by Idaho Power in smart grid technology, including AMI. Idaho Power has received approximately $18 million from the DOE as of December 31, 2010, and expects to bill and collect monthly over the estimated three-year term of the grant.

In addition to infrastructure development projects, Idaho Power has significant retirement benefit plan funding obligations and capital requirements for relicensing of hydroelectric facilities and planned and anticipated future environmental-related expenditures discussed elsewhere in this MD&A.

Key Operating and Financial Metrics

	2011	2010
	Estimate	Actual
Idaho Power Operation & Maintenance Expense (millions)	$300 - $310	$294
Idaho Power Capital Expenditures (millions)	$320 - $330	$341
Idaho Power Hydroelectric Generation (million MWh)	7.5 - 9.5	7.3
Non-regulated subsidiary earnings and holding company expenses (millions)	$0 - $3	$2

The 2011 range for capital expenditures includes amounts for the Langley Gulch power plant and expenditures for the siting and permitting of major transmission expansions for the Boardman to Hemingway and Gateway West transmission projects, excluding AFUDC.

The estimated hydroelectric generation range is based in part on National Weather Service reports stating that La Nina conditions, including an enhanced chance of above-average precipitation in Idaho and the Snake River Basin, are expected to continue into spring 2011. On February 16, 2011, reservoir storage levels in selected federal reservoirs upstream of Brownlee were approximately 110 percent of average.

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 2010 are compared to 2009 and the results of 2009 are compared to 2008.

Results for the Years Ended December 31, 2010, 2009, and 2008

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

		2010		2009		2008
Idaho Power		$	140,634	$	122,559	$	94,115
IDACORP Financial Services			212		521		3,426
Ida-West Energy			2,572		2,727		2,353
Holding company and other expenses			(620)		(1,457)		(1,480)
	Net Income Attributable to IDACORP, Inc.	$	142,798	$	124,350	$	98,414
Average outstanding shares - diluted (000s)		$	48,340	$	47,182	$	45,379
Earnings Attributable to IDACORP, Inc. - diluted			2.95		2.64		2.17

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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, including the integration of intermittent wind generation.

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

		2010		2009		2008
General business sales			13,513		13,948		14,544
Off-system sales			1,982		2,836		2,048
	Total energy sales		15,495		16,784		16,592
Hydroelectric generation			7,344		8,096		6,908
Coal generation			6,864		6,941		7,279
Natural gas and other generation			160		242		217
	Total system generation		14,368		15,279		14,404
Purchased power			2,401		2,912		3,716
Line losses and other			(1,274)		(1,407)		(1,528)
	Total energy supply		15,495		16,784		16,592

The 0.8 million MWh reduction in hydroelectric generation in 2010 compared to 2009 is primarily due to a decrease in precipitation during the snow accumulation period. Hydroelectric generation in 2010 was 86 percent of the annual median generation of 8.6 million MWh. The observed stream flow data released in August 2010 by the U.S. Corps of Engineers, Northwest Division indicated that Brownlee reservoir inflow for April through July 2010 was 4.6 million acre-feet (maf), compared to 5.6 maf in April through July 2009. Annual Brownlee reservoir inflow for 2010 was 10.7 maf compared to 11.3 maf in 2009 and 10.1 maf in 2008.

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

			2010		2009		2008
Revenue
	Residential		$	400,607	$	409,479	$	353,262
	Commercial			231,440		232,816		203,035
	Industrial			138,394		141,530		122,302
	Irrigation			110,555		109,655		105,712
	Deferred revenue related to Hells Canyon relicensing AFUDC			(10,625)		(9,715)		-
		Total	$	870,371	$	883,765	$	784,311
MWh
	Residential			4,967		5,300		5,297
	Commercial			3,763		3,858		3,970
	Industrial			3,076		3,140		3,355
	Irrigation			1,707		1,650		1,922
		Total		13,513		13,948		14,544
Customers (year-end)
	Residential			408,754		406,631		404,373
	Commercial			64,647		64,349		64,125
	Industrial			125		129		125
	Irrigation			18,547		18,818		18,542
		Total		492,073		489,927		487,165

Changes in customer demand and changes in rates are the primary causes of fluctuations in general business revenue. Several significant rate actions have been implemented in the last three years and are discussed further in “Regulatory Matters – Idaho and Oregon Significant Rate Changes” in this MD&A.

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

	2010	2009	2008	Normal
Heating degree-days ⁽¹⁾	5,078	5,612	5,586	5,727
Cooling degree-days ⁽¹⁾	914	1,188	1,068	807
Precipitation (inches)	15.0	11.3	9.3	12.2
⁽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.

2010 vs. 2009:

Rates: Rate increases positively impacted general business revenue by $16.9 million, due to increases in base retail rates of $73.5 million, partially offset by PCA rate decreases of $56.6 million.
Usage: A decrease in usage reduced general business revenue by $33.4 million. Idaho Power believes the decline in total MWh sales is due primarily to mild temperatures, which decreases power demand for heating and cooling purposes, and partially due to the continued weakness of the economy and energy conservation practices in its service area. A slow economic recovery could result in continued low demand.
Customers: Growth in customer count contributed to a modest increase in general business revenues of $2.9 million. Customer growth from 2009 to 2010 was 0.5 percent.

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2009 vs. 2008:

Rates: Rate changes positively impacted general business revenue by $127.8 million in 2009 as compared to 2008. PCA rate increases accounted for $78.6 million of the increases and base rate changes contributed $49.2 million.
Usage: Reductions in usage decreased general business revenue $37.7 million. Irrigation usage decreased 14 percent primarily due to increased precipitation, which decreases demand for power to operate irrigation pumps. Commercial and industrial usage also declined due to a weaker economy and increased energy efficiency. The LGAR and FCA mechanisms diminished the impact of changes in sales volumes from levels included in base rates.
Customers: Customer growth of one percent increased general business revenues $9.8 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:

	2010		2009		2008
Revenue	$	78,133	$	94,373	$	121,429
MWh sold		1,982		2,836		2,048
Revenue per MWh	$	39.42	$	33.28	$	59.29

2010 vs. 2009: Off-system sales revenue decreased $16.2 million in 2010 as compared to 2009. Hydroelectric generation decreased nine percent, which reduced surplus power available for sale. This decrease was partially offset by an 18 percent increase in revenue per MWh due to lower hydro generation in the region which drove wholesale power prices higher.

2009 vs. 2008: Off-system sales revenue declined $27.1 million in 2009 due to lower market prices, partially offset by increased sales. Prices for wholesale power in the Northwest were much lower in 2009 than in 2008 due to an abundance of energy in the region during the spring and fall and due to lower prices for energy commodities such as natural gas. Improved hydroelectric generating conditions and lower system load increased the amount of electricity available for sale.

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

		2010		2009		2008
Transmission services and property rental		$	40,364	$	36,037	$	31,456
Energy efficiency			44,184		31,821		18,880
	Total	$	84,548	$	67,858	$	50,336

2010 vs. 2009: Other revenues increased $16.7 million, due mainly to the following:

an increase of $4.3 million in transmission revenues. Transmission system revenues increased $2.8 million primarily due to new transmission facilities, as well as rate changes. Wheeling revenue increased $2.1 million primarily due to increases in the FERC formula rate that took effect on October 1, 2009 and October 1, 2010; and
an increase in energy efficiency revenues of $12.4 million, due to increased program activity. Energy efficiency activities are funded through rider mechanisms 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.

2009 vs. 2008: Other revenues increased $17.5 million, due mainly to the following:

an increase of $4.6 million in transmission revenues, due primarily to transmission rate refunds ordered by the FERC reducing 2008 revenues. Idaho Power recorded in 2008 approximately $4 million of refunds related to transmission sales from prior years; and
an increase of $12.9 million in energy efficiency revenues. 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.

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

	2010		2009		2008
Expense	$	143,769	$	167,198	$	238,387
MWh purchased		2,401		2,912		3,716
Cost per MWh purchased	$	59.88	$	57.42	$	64.15

2010 vs. 2009: Purchased power expense decreased $23.4 million in 2010 compared to 2009, due to lower system loads that resulted from mild weather, relatively weak economic conditions, energy conservation practices, and a greater reliance on financial hedges to mitigate potential changes in forecasted hydrologic conditions.

2009 vs. 2008: Purchased power expense decreased $71.2 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.

The purchased power cost per MWh often exceeds the off-system sales revenue per MWh because Idaho Power generally needs to purchase power during heavy load periods, which is higher priced energy, than during light load periods, which is lower priced energy, and conversely has less energy available for off-system sales during heavy load periods than light load periods. Also, in accordance with Idaho Power’s risk management policy, Idaho Power may purchase or sell energy several months in advance of delivery. The regional energy market price is dynamic and additional energy purchase or sale transactions that Idaho Power makes at current market prices may be noticeably different than the advance purchase or sale transactions prices.

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

			2010		2009		2008
Expense
	Coal		$	146,927	$	130,234	$	132,015
	Natural gas and other			12,746		19,332		17,388
		Total fuel expense	$	159,673	$	149,566	$	149,403
MWh generated
	Coal			6,864		6,941		7,279
	Natural gas and other			160		242		217
		Total MWh generated		7,024		7,183		7,496
Cost per MWh
	Coal		$	21.41	$	18.76	$	18.14
	Natural gas		$	79.66	$	79.88	$	80.13
	Weighted average, all sources		$	22.73	$	20.82	$	19.93

2010 vs. 2009: Fuel expense increased $10.1 million, due to new contracts with Black Butte Coal Company for the Valmy and Jim Bridger plants that reflect price increases related to diesel fuel and materials and supplies at the Black Butte mine. BCC, which also supplies coal to the Jim Bridger plant, experienced higher labor-related costs due to a tight labor market in the southwest Wyoming area and higher materials and supplies expense related to the underground mining operation. In 2011, there are no significant contract expirations and prices are expected to be similar to 2010; however, most fuel supply contracts are subject to changes in published indexes that are closely related to materials and supplies, labor, and diesel costs. Fuel expense also increased due to a 31 percent increase in generation at the Boardman plant due to an extended outage in 2009 that did not recur in 2010, increasing fuel expense $1.8 million. These increases were partially offset by a $6.6 million decrease in fuel expense at the natural gas-fired peaking plants.

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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 BCC, which supplies coal to the Jim Bridger plant, as well as higher prices for coal delivered to the Boardman plant.

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 – Idaho and Oregon Deferred Net Power Supply Costs” in this MD&A and in Note 3 – “Regulatory Matters” to the consolidated financial statements included in this report. 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:

		2010		2009		2008
Idaho power supply cost deferral		$	(14,324)	$	(42,533)	$	(108,688)
Oregon power supply cost deferral			-		184		(5,196)
Oregon 2007 excess power cost order			-		(6,358)		-
Amortization of prior year authorized balances			65,550		115,417		66,471
	Total power cost adjustment	$	51,226	$	66,710	$	(47,413)

2010 vs. 2009: A combination of changes in base power supply costs, elements of the PCA mechanism, and a decrease in PCA rates reduced PCA expenses $15.5 million compared to 2009. The $49.9 million decrease in the amortization of the prior year’s deferral balance resulted from lower PCA true-up rates in effect in 2010. The $28.2 million decrease in the Idaho deferral is due to changes in base and actual power supply costs and forecast rates. In addition, in the second quarter of 2009 Idaho Power recorded the effect of an order from the OPUC that allows Idaho Power to defer for future recovery $6.4 million of costs incurred in prior years.

2009 vs. 2008: The $114.1 million change in the PCA is due primarily to lower deferral of power supply costs and higher amortization of previously deferred power supply costs.

Other operations and maintenance (O&M) expenses:

2010 vs. 2009: Other O&M expense increased $1.3 million, an increase of less than one percent.

2009 vs. 2008: Other O&M expenses increased $6.3 million, due primarily to an $8.1 million increase in labor related charges and a $1.6 million increase in charges for uncollectible accounts, partially offset by decreases of $4.0 million in legal, other contracted services, and office supplies due to cost containment measures.

Energy efficiency: The majority of 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 $44.2 million, $31.8 million, and $18.9 million in 2010, 2009, and 2008, respectively. The remaining $1.4 million of energy efficiency expenses for 2010 are in Other O&M and recovered through base rates.

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, 2010, Idaho Power’s rider balance was a regulatory asset of $19.5 million.

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Non-utility Operations

IFS: IFS had an immaterial impact on net income in 2010. IFS contributed $1 million and $3 million to net income in 2009 and 2008, respectively, principally from the generation of federal income tax credits and accelerated tax depreciation benefits related to its investments in affordable housing and other real estate investments.

IFS made $6.7 million in new investments in 2010 and invested $14 million, and $8 million in new investments in 2009 and 2008, respectively. IFS generated tax credits of $7 million, $8 million, and $11 million during 2010, 2009, and 2008, respectively.

Ida-West: Ida-West had net income of $3 million, $3 million, and $2 million in 2010, 2009, and 2008, respectively. Ida-West continues to hold joint venture investments in independent power projects.

Income Taxes

IDACORP’s and Idaho Power’s income tax expense for the year ended December 31, 2010 decreased substantially relative to 2009 and 2008, primarily as a result of Idaho Power’s tax accounting method change for repair-related expenditures and lower pre-tax earnings at IDACORP and Idaho Power. Net regulatory flow-through tax adjustments at Idaho Power and tax credits at IFS for 2010 were comparable to 2009. For additional information relating to IDACORP’s and Idaho Power’s income taxes, see Note 2 – “Income Taxes” to the consolidated financial statements included in this report, and the discussion below.

Tax Accounting Method Change for Repair-Related Expenditures: In June 2010, Idaho Power completed its evaluation of a tax accounting method change for its 2009 tax year that allows a current income tax deduction for repair-related expenditures on its utility assets that are currently capitalized for financial reporting and tax purposes. In September 2010, Idaho Power adopted this method following the automatic consent procedures with the filing of IDACORP’s 2009 consolidated federal income tax return.

For the year ended December 31, 2010, Idaho Power recorded a $44.5 million tax benefit related to the filed deduction for the cumulative method change adjustment and an additional $11.7 million tax benefit for the annual deduction estimate included in its 2010 income tax provision. As of December 31, 2010, Idaho Power had a current uncertain tax position liability of $14.7 million related to this method. The estimated annual tax deduction related to capitalized repairs produces a net tax benefit of $9 million annually, which is approximately $5 million higher than Idaho Power’s prior repair deduction method reported in 2009. In addition, the reversal of this temporary difference will offset a portion of the ongoing annual benefit.

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.

As of the date of this report, the tax method is being audited under IDACORP’s 2009 Compliance Assurance Process (CAP) examination (discussed below) and, on a national level, aspects of the method related to electric utility generation, transmission, and distribution property are the subject of an IRS Industry Issue Resolution program. IDACORP and Idaho Power cannot predict exactly when the audit of the method will conclude or when national guidance related to utility property will be issued, but believe it is reasonably possible during fiscal year 2011.

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

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Specifically within the 2009 CAP examination, the IRS audited Idaho Power’s method of uniform capitalization. In September 2009, the IRS issued Industry Director Directive #5 (IDD), which discusses the IRS’s compliance priorities and audit techniques related to the allocation of mixed service costs in the uniform capitalization methods of electric utilities. Since that time the IRS and Idaho Power worked through the impact the IDD guidance had on Idaho Power’s uniform capitalization method and reached agreement during the third quarter of 2010. The agreement provided that Idaho Power change its uniform capitalization method to the agreed upon method under the IDD with the filing of IDACORP’s 2009 consolidated federal income tax return. Due to the method change agreement with the IRS, Idaho Power reversed the uncertain tax position liability for its 2009 uniform capitalization deduction, resulting in a $1.1 million tax benefit for the year ended December 31, 2010.

The resulting tax deductions available under the agreed upon uniform capitalization method are significantly greater than Idaho Power’s prior method. For the year ended December 31, 2010, Idaho Power recorded a tax benefit of $65.3 million related to the cumulative method change adjustment (tax years 1986 through 2009) for this method and $5.6 million of current year tax expense from the reversal of this temporary difference. The prescribed regulatory accounting treatment for this method is the same as discussed earlier for the capitalized repairs method.

As of December 31, 2010, Idaho Power had a current uncertain tax position liability equal to the $59.7 million net tax benefit recorded for the method change. While Idaho Power has an agreement with the IRS for examination and tax return filing purposes, it is awaiting U.S. Congress Joint Committee on Taxation approval of its method or approval of methods filed by other similarly-situated companies under the IDD before concluding that the new method is effectively settled for financial reporting purposes. IDACORP and Idaho Power cannot predict exactly when Joint Committee review will occur, but believe it is reasonably possible during fiscal year 2011. The estimated annual tax deduction related to the uniform capitalization method, if approved, will produce a tax benefit that approximates the annual net tax benefit reported for the capitalized repairs method.

Cash Impacts of Tax Method Changes: IDACORP and Idaho Power have realized federal and state cash benefits associated with the 2009 capitalized repairs and uniform capitalization method changes of $33 million and $42 million, respectively. The majority of this cash benefit has been realized through reductions to cash payments that would have otherwise been owed to taxing authorities for the 2009 tax year and a federal refund of $24 million received in the fourth quarter of 2010. Additionally, approximately $6 million of state cash benefits were realized through reduced tax payments for the 2010 year.

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

New Tax Legislation: The Small Business Jobs Act (Jobs Act) and the Tax Relief, Unemployment Insurance Reauthorization, and Job Creation Act of 2010 (Tax Relief Act) were both enacted in 2010. While the legislation contained many income tax related provisions for individuals and businesses, one item of significance for capital intensive industries was the extension and increase of bonus depreciation. Bonus depreciation provides for the accelerated deduction of current capital expenditures. The Jobs Act extended 50 percent bonus depreciation to 2010 and the Tax Relief Act extended bonus depreciation to 2011-2012 and increased it to 100 percent for a portion of 2010 and 2011. Additional technical guidance from the Treasury Department on the application of bonus depreciation to self-constructed assets is expected in the first half of 2011, as well as decisions by various states on conformity with the federal law. IDACORP and Idaho Power are currently evaluating the potential impact that the federal extension of bonus depreciation could have on its 2011 and 2012 taxable income, operating results, cash flows, capital expenditure plans, and regulatory objectives.

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LIQUIDITY AND CAPITAL RESOURCES

Overview

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

Significant uses of cash flows from Idaho Power’s utility operations include the purchase of electricity, the purchase of fuel for power generation, and payment of other operating expenses, taxes, and interest, with any excess amount being available for other uses such as capital expenditures and the payment of dividends. Idaho Power is experiencing a cycle of heavy infrastructure investment, adding capacity to its baseload generation, transmission system, and distribution facilities in an effort to ensure an adequate supply of electricity, to provide service to new customers, and to maintain system reliability. Idaho Power’s aging hydroelectric and thermal generation facilities require continuing upgrades and component replacement, and the costs related to relicensing hydroelectric facilities and complying with the new licenses are substantial. Due to heavy infrastructure requirements in the near term, Idaho Power has recently focused on critical infrastructure needs that relate to system reliability and resource adequacy, and expects that total capital expenditures will be between $775 million and $805 million from 2011 through 2013. See “Capital Requirements” below for a further discussion of Idaho Power’s current and anticipated infrastructure development requirements and associated capital expenditure estimates. Idaho Power also made a $60 million cash contribution to its defined benefit pension plan in September 2010 and expects significant future cash contribution obligations under that plan.

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

IDACORP’s and Idaho Power’s access to long-term and short-term debt markets, including their respective $100 million and $300 million credit facilities, helps provide necessary liquidity to support operating activities. In addition to access to its credit facility, as of the date of this report IDACORP has approximately $539 million remaining on a shelf registration statement that can be used for the issuance of debt securities and common stock. IDACORP has a sales agency agreement that expires in November 2011 with BNY Mellon Capital Markets, LLC where approximately 1.2 million shares of common stock remain available to be sold from time to time in at-the-market offerings. As of the date of this report, Idaho Power has $300 million remaining on a shelf registration statement that can be used for the issuance of first mortgage bonds and debt securities. In 2010, Idaho Power issued $200 million of first mortgage bonds, of which a significant portion of the net proceeds are intended to fund upcoming debt maturities.

IDACORP and Idaho Power also meet short-term liquidity requirements through the issuance of commercial paper, which under recent commercial paper market conditions has been a relatively low-cost, flexible borrowing option. While short-term borrowing costs have not been significant recently, any future uncertainty in the credit markets may result in increased costs for commercial paper borrowings or limit the ability to issue commercial paper, which may increase IDACORP’s and Idaho Power’s reliance on their respective credit facilities for short-term liquidity purposes.

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

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Operating Cash Flows

IDACORP’s and Idaho Power’s operating cash inflows for the year ended December 31, 2010, were $305 million and $330 million, respectively. These amounts were an increase of $21 million and $58 million, respectively, compared to the year ended December 31, 2009. The following are significant items that affected operating cash flows in 2010:

• IDACORP’s net refunds for income taxes were $27 million in 2010, as compared with $21 million in 2009. Idaho Power’s net refunds from IDACORP for income tax were $57 million in 2010, as compared with $14 million in 2009;

• changes in accounts payable balances increased operating cash flows $32 million. Idaho Power paid less during 2010 for prior-year operating expense than it did in 2009 and carried over more current-year expense to be paid in 2011 than it did in 2009. Changes in amounts owed for purchased power and for coal contributed $14 million and $8 million, respectively, to the change;

• changes in retail customer accounts receivable and unbilled revenue balances increased cash flows as a colder than normal December in 2009 caused these balances to be significantly higher at the end of that year than in either 2008 or 2010. The 2009 increase in accounts receivable and unbilled revenue balances of $19 million reflects a timing difference that results in Idaho Power collecting less from customers during the year than it recorded as revenue. The subsequent decrease in those balances during 2010 of $13 million reflects the reversal of that timing difference and results in collections exceeding accrued revenues. This change in out-of-period collections from 2009 to 2010 increased cash flows by $32 million as compared with 2009;

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

• a $60 million contribution was made to the defined benefit pension plan, decreasing operating cash flows in September 2010. No contribution was made in 2009.

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 improved 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; and

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

Pension Funding: In September 2010, Idaho Power elected to make a $60 million contribution to its defined benefit pension plan. The contribution was $54 million in excess of the $6 million minimum contribution required to be made in 2010 for the 2009 plan year. The higher contribution amount was made for reasons that include bringing the pension plan to a more funded position, reducing future required contributions, and reducing Pension Benefit Guaranty Corporation premiums. Idaho Power expects to make additional significant cash contributions to its pension plan and has significant funding obligations under postretirement benefit plans at least through 2015.

The funded status of the pension and other postretirement benefit obligations refers to the difference between plan assets and the estimated liabilities of the plans. The calculation of funding requirements for pension plans requires election of a methodology to determine the actuarial value of assets and the interest rate used to measure the pension liabilities. The funded status may change over time due to several factors, including contribution levels, assumed discount rates, and actual and assumed rates of return on plan assets.

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IDACORP and Idaho Power continuously monitor available and proposed pension funding guidance and financial market conditions and their impact on the pension plan, and evaluate the potential impact on funding requirements and strategies.

In June 2010, the Preservation of Access to Care for Medicare Beneficiaries and Pension Relief Act (Pension Relief Act) was signed into law, which permits employers to choose between two alternative funding options for defined benefit pension plans for any two plan years between 2008 and 2011. If an alternate funding option is elected, it would reduce near-term required contributions to the plan by spreading them over a longer time period. Idaho Power has determined not to make the election permitted by the Pension Relief Act for the 2008-2010 plan years, but continues to evaluate the legislation’s potential impact on the 2011 plan year. Unless IDACORP and Idaho Power elect an alternative amortization schedule under the new legislation for 2011, minimum required contributions to the defined benefit pension plan are estimated to be approximately $3 million in 2011, $46 million in 2012, $36 million in 2013, $32 million in 2014, and $31 million in 2015. IDACORP and Idaho Power may elect to make contributions earlier than and larger than required. See Note 11 – “Benefit Plans” to the consolidated financial statements included in this report for additional information relating to the Pension Relief Act and Idaho Power’s pension plan funding and postretirement benefit obligations, and Note 3 – “Regulatory Matters” to the consolidated financial statements included in this report for a discussion of Idaho Power’s recovery of pension plan contributions through the ratemaking process.

Investing Cash Flows

Cash flows from investing activities consist primarily of capital expenditures related to new construction and improvements to Idaho Power’s distribution, transmission, and generation facilities. These capital expenditures are for the construction of infrastructure needed to address customer growth, peak demand growth, and aging plant and equipment. Idaho Power’s construction expenditures were $338 million, $252 million, and $244 million in 2010, 2009 and 2008, respectively. In 2010, construction expenditures were partially offset by proceeds from the sale of $19 million of transmission-related assets to PacifiCorp.

In May 2008, IDACORP and Idaho Power withdrew $20 million from a refundable tax deposit previously made with the IRS. In December 2008 the remainder of the deposit, approximately $25 million, was applied to accrued taxes and interest.

IDACORP cash flows relating to investments in affordable housing through IFS were $13 million, $6 million, and $8 million in 2010, 2009, and 2008, respectively.

Financing Cash Flows

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

Debt: On August 30, 2010, Idaho Power issued $100 million of 3.40% First Mortgage Bonds, Secured Medium-Term Notes, Series I due 2020 and $100 million of 4.85% First Mortgage Bonds, Secured Medium-Term Notes, Series I due 2040 under its shelf registration statement. Idaho Power expects to use a portion of the proceeds from this issuance to repay $120 million of first mortgage bonds that mature in the first quarter of 2011.

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

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Agreement. 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. During 2009, 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. 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 received $34 million, net of agent’s fees, in 2010 from the issuance of 973,585 shares at an average price of $35.47. In 2009, IDACORP received $14 million, net of agent’s fees, from the issuance of 489,360 shares at an average price of $28.79. In 2008, IDACORP received $41 million from the issuance of 1,453,967 shares an average price of $28.72. IDACORP’s current sales agency agreement is with BNY Mellon Capital Markets, LLC. As of December 31, 2010, there were 1.2 million shares remaining on the current sales 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 250,030 shares in 2010, 366,673 shares in 2009, and 280,250 shares in 2008, for proceeds of $8.6 million, $9.6 million, and $8.4 million, respectively.

IDACORP issued 194,860 shares in 2010, 25,800 shares in 2009, and 30,700 shares in 2008, in connection with the exercise of stock options, for proceeds of $5.4 million, $0.6 million, and $0.9 million, respectively.

IDACORP and Idaho Power paid dividends of $58 million, $57 million, and $54 million in 2010, 2009, and 2008, respectively. IDACORP made capital contributions of $50 million, $20 million, and $37 million to Idaho Power in 2010, 2009, and 2008, respectively.

Financing Programs

IDACORP’s consolidated capital structure consisted of common equity of 48 percent and debt of 52 percent at December 31, 2010. Idaho Power’s consolidated capital structure consisted of common equity of 47 percent and debt of 53 percent at December 31, 2010.

Shelf Registrations: IDACORP has an effective registration statement that as of the date of this report can be used for the issuance of up to $539 million of debt securities and common stock. Idaho Power has an effective registration statement that as of the date of this report can be used for the issuance of up to $300 million of first mortgage bonds and unsecured debt. Refer to Note 4 – “Long-Term Debt” to IDACORP’s and Idaho Power’s consolidated financial statements included in this report 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, to be used for general corporate purposes and commercial paper back-up, and that provide for the issuance of loans and standby letters of credit. 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. In determining the leverage ratio, “consolidated indebtedness” broadly includes all indebtedness of the respective borrower and its subsidiaries, excluding indebtedness evidenced by certain hybrid securities (as defined in the credit agreement). “Consolidated total capitalization” is calculated as the sum of all consolidated indebtedness, consolidated stockholders’ equity of the borrower and its subsidiaries, and the aggregate value of outstanding hybrid securities. At December 31, 2010, the leverage ratios for IDACORP and Idaho Power

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were 52 percent and 53 percent, respectively. IDACORP’s and Idaho Power’s ability to utilize the credit facilities is subject to continued compliance with the leverage ratio covenants included in the credit facilities, which could limit the ability of the companies to issue first mortgage bonds and debt securities. 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, 2010, 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; any reportable event occurring with any employee pension benefit plan as defined by the Internal Revenue Code or the Employee Retirement Income Security Act of 1974 (ERISA); failure to meet minimum funding standards for any employee pension benefit plan under the Internal Revenue code or ERISA; notice provided by Idaho Power to terminate an employee pension benefit plan if the plan’s unfunded liabilities exceed $75 million; and environmental proceedings, investigations, or violations of law which could reasonably be expected to have a material adverse effect.

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 more than 50 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. However, if Idaho Power’s ratings are downgraded below investment grade, Idaho Power must extend or renew its authority for borrowings under its IPUC and OPUC regulatory orders. The IPUC order provides that Idaho Power’s authority will continue for 364 days from such downgrade, if Idaho Power promptly notifies the IPUC and files to continue its original authority to borrow. The Oregon statutes permit the issuance of short-term debt without approval of the OPUC.

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

The following table outlines available liquidity as of December 31, 2010 and 2009:

	IDACORP ⁽²⁾				Idaho Power
	2010		2009		2010		2009
Revolving credit facility	$	100,000	$	100,000	$	300,000	$	300,000
Commercial paper outstanding		(66,900)		(53,750)		-		-
Floating rate draw		-		-		-		-
Identified for other use ⁽¹⁾		-		-		(24,245)		(24,245)
Net balance available	$	33,100	$	46,250	$	275,755	$	275,755

⁽¹⁾ Port of Morrow and American Falls bonds that holders may put to Idaho Power.
⁽²⁾ Holding company only.

At February 18, 2011, IDACORP had no loans under its credit facility and $75 million of commercial paper outstanding and Idaho Power had no loans under its credit facility and no commercial paper outstanding.

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The following table presents additional information about short-term borrowing during 2010:

		IDACORP ⁽¹⁾		Idaho Power
Commercial paper:
Period end:
	Amount outstanding	$	66,900	$	-
	Weighted average interest rate		0.43%		-
Daily average amount outstanding during the year		$	19,748	$	348
Weighted average interest rate during the year			0.40%		0.43%
Maximum month-end balance		$	66,900	$	5,500

(1) Holding company only.

Impact of Credit Ratings on Liquidity

IDACORP’s and Idaho Power’s access to capital markets, including the commercial paper market, and their respective financing costs in those markets may depend on the credit ratings of the entity that is accessing the capital markets. As discussed above, IDACORP’s and Idaho Power’s credit facilities are also affected by the companies’ credit ratings.

		Standard &Poor’s		Moody’s
		Ratings Services		Investors Service
		Idaho Power	IDACORP	Idaho Power	IDACORP
Corporate Credit Rating/Long-Term
	Issuer Rating	BBB	BBB	Baa1	Baa2
Senior Secured Debt		A-	None	A2	None
Senior Unsecured Debt		BBB	None	Baa1	None
Short-Term Tax-Exempt Debt		BBB/A-2	None	Baa1/ VMIG-2	None
Commercial Paper		A-2	A-2	P-2	P-2
Senior Unsecured Credit Facility		None	None	Baa1	Baa2
Rating Outlook		Stable	Stable	Stable	Stable

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 agency has its own methodology for assigning ratings and, accordingly, each rating should be evaluated independently of any other rating.

Idaho Power maintains margin agreements relating to its wholesale commodity contracts that allow performance assurance collateral to be requested of and/or posted with certain counterparties. As of December 31, 2010, Idaho Power had posted approximately $4.6 million of assurance collateral. Should Idaho Power experience a reduction in its credit rating on its unsecured debt to below investment grade, Idaho Power could be subject to additional requests by its wholesale counterparties to post additional performance assurance collateral. Counterparties to forward contracts and derivative instruments could request immediate payment or demand immediate ongoing full daily collateralization on derivative instruments and contracts in net liability positions. Based upon Idaho Power’s energy and fuel portfolio and market conditions as of December 31, 2010, the amount of additional collateral that could be requested upon a downgrade to below investment grade as of that date was approximately $17 million. Idaho Power actively monitors the portfolio exposure and the potential exposure to additional requests for performance assurance collateral calls, through sensitivity analysis, to minimize capital requirements.

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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 an adequate supply of electricity, to provide service to new customers, and to maintain system reliability. Idaho Power’s aging hydroelectric and thermal generation facilities require continuing upgrades and component replacement, and the costs related to relicensing hydroelectric facilities and complying with the new licenses are substantial. Due to the heavy infrastructure requirements from 2011-2013, 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 estimates of the capital expenditure categories. Idaho Power expects that total capital expenditures will be between $775 million and $805 million from 2011-2013. Internal cash generation after dividends is expected to provide less than the full amount of total capital requirements for 2011 through 2013. While circumstances could change, IDACORP and Idaho Power expect minimal need for external financing in 2011, other than issuances under the dividend reinvestment and employee-related plans and potentially issuances of IDACORP common stock pursuant to its continuous equity program. Beyond 2011, IDACORP and Idaho Power expect to continue financing capital requirements with a combination of internally generated funds and externally financed capital. As discussed above, for future external financing needs IDACORP and Idaho Power have shelf registration statements available for the issuance of equity (in the case of IDACORP only) and debt securities, as well as credit facilities.

The following table presents Idaho Power’s estimated cash requirements for construction, excluding AFUDC, for 2011 through 2013 (in millions of dollars):

		2011		2012-2013
Ongoing capital expenditures		$	190-192		$	402-413
Langley Gulch power plant (detailed below)			126-130			33-37
Other major projects			4-8			20-25
	Total	$	320-330		$	455-475

Langley Gulch Power Plant: The Langley Gulch Power Plant is a natural gas-fired CCCT generating plant with a summer nameplate capacity of approximately 300 MWs and a winter capacity of approximately 330 MWs. Construction of the plant, substation, and one of the two required transmission lines is underway. The plant is being constructed near New Plymouth, Idaho and is contracted to achieve commercial operation by November 1, 2012. Based on contract incentives and the current project status, Idaho Power estimates that the plant will be in service by June 2012. The total cost estimate for the project including AFUDC is $427 million, $206 million of which Idaho Power has incurred from inception in 2009 through December 31, 2010. During 2010, Idaho Power received an air quality permit to construct and commenced construction. Construction activities have included earthwork, underground electrical duct bank and piping, foundations, structures, and equipment erection. The combustion turbine and generator were delivered to the site in December 2010. A contract has been issued for the water delivery system and construction has begun. Contracts have been issued for the gas delivery system, and it is currently under design. The plant will connect to Idaho Power’s existing grid through a new substation and two new transmission lines. As of December 31, 2010, construction of the substation and one of the transmission lines is approximately 50 percent complete. The second transmission line is not expected to be complete until May 2012.

Other Major Projects:

Hemingway Station: Idaho Power recently completed construction of the 500-kV Hemingway station, located near Boise, Idaho. This station was constructed to relieve capacity and operating constraints to enhance reliable service to Idaho Power’s network and native load customers and was placed in service in July 2010 at a total cost of approximately $58 million. PacifiCorp acquired an ownership interest in the Hemingway station as discussed below in “Memorandum of Understanding and Related Transactions with PacifiCorp.”

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Hemingway-Bowmont Transmission Line: The Hemingway-Bowmont transmission line consists of 13 miles of new 230-kV transmission line that provides power to the Treasure Valley in southwest Idaho. The project was placed in service in 2010 at a total cost of approximately $15 million.

Boardman-Hemingway Line: The Boardman-Hemingway Line is a proposed 299 mile, 500-kV transmission project between a substation near Boardman, Oregon and the Hemingway station. This line will provide transmission service to meet needs identified in the 2009 IRP and other requests pursuant to Idaho Power’s OATT. The Oregon Energy Facility Siting Council (EFSC) process and the National Environmental Policy Act (NEPA) process are under way. Idaho Power is working with the EFSC to develop a phased approach to their process so it can run concurrently with the NEPA process. The U.S. Bureau of Land Management (BLM) is expected to determine in the first quarter of 2011which additional routes identified in scoping will be analyzed in the NEPA process along with Idaho Power’s proposed and alternate routes. The Oregon Department of Fish and Wildlife (ODFW) is working with Idaho Power to minimize the impact of the conservation plan for the greater sage grouse on the proposed route. The cost of the initial phase of the project, consisting of engineering, environmental review, permitting, and acquisition of rights-of-way, is estimated at $92 million, including AFUDC, $13 million of which Idaho Power has incurred through December 31, 2010. Total cost estimates for the project are approximately $820 million, including AFUDC. This cost estimate excludes the impacts of inflation and price changes of materials and labor resources that may occur following the date of the estimate. Idaho Power expects its share of the project to be between 30 and 50 percent. The 2011 to 2013 cost estimate, excluding AFUDC and assuming Idaho Power’s share of the project is approximately 30 percent, is included in the Capital Requirements table above. Construction costs beyond the initial phase are not included in the table above. While Idaho Power’s forecast of load requirements indicates that immediate system reliability benefits could be realized by accelerating construction of the transmission line for an earlier in-service date, Idaho Power is currently targeting a completion date of mid-2016 for the project, subject to siting, permitting, regulatory approvals, and other conditions. Idaho Power expects to receive a draft environmental impact statement (EIS) from the BLM relating to the project in early 2012. Idaho Power will continue to work with ODFW and other agencies to address environmental issues, including proposed lawmaking relating to sage grouse in Oregon, which could delay the project, alter the proposed siting, and result in significantly higher costs.

Gateway West Project: Idaho Power and PacifiCorp are pursuing the joint development of the Gateway West project to build transmission lines between Windstar, a station located near Douglas, Wyoming, and the Hemingway station. Idaho Power and PacifiCorp have a cost sharing agreement for expenses incurred for analysis work of the initial phases. Idaho Power’s share of the initial phase, consisting of engineering, environmental review, permitting, and acquisition of rights-of-way, is approximately $40 million, including AFUDC, $14 million of which Idaho Power had incurred through December 31, 2010. Initial phases of the project could be completed by 2014; however, timing of the project’s segments may be deferred and constructed as demand requires. Idaho Power’s share will vary by segment across the project and the current estimated total cost for its share is between $300 million and $500 million, including AFUDC. Only initial phase cost estimates for the 2011 to 2013 timeframe, excluding AFUDC, are included in the Capital Requirements table above. Idaho Power anticipates receiving a draft EIS from the BLM in 2011.

AMI/Smart Grid (American Recovery and Reinvestment Act of 2009 (ARRA)): The AMI project provides the means to automatically retrieve energy consumption information, eliminating manual meter reading expense. Idaho Power intends to install this technology for approximately 99 percent of its customers and is on pace to complete the installations by the end of 2011. As of December 31, 2010, Idaho Power had installed approximately 343,000 AMI meters at a cost of $49 million. On May 28, 2010, the IPUC approved Idaho Power’s request to include the 2010 AMI investment in its rate base. The requested increase to rates of approximately $2.4 million was effective June 1, 2010. The total cost estimates for the project are approximately $74 million. The 2011 estimated costs are included in the Capital Requirements table above.

Under the ARRA, Idaho Power was awarded a grant of $47 million from the DOE. This grant matches a $47 million investment by Idaho Power in Smart Grid technology, including AMI. The grant was signed by the DOE on April 2, 2010. Idaho Power received approximately $18 million from the DOE as of December 31, 2010, and expects to bill and collect monthly over the term of the three-year contract. The costs to be reimbursed by the grant are not included in the Capital Requirements table above.

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Memorandum of Understanding and Related Transactions with PacifiCorp:

Memorandum of Understanding: Idaho Power is committed to the development of transmission facilities to fulfill its service obligations and to operate reliable transmission systems. On March 5, 2010, Idaho Power and PacifiCorp entered into a Memorandum of Understanding (MOU) under which Idaho Power and PacifiCorp agreed to negotiate in good faith to reach arrangements pertaining to the sale by the parties to one another of an undivided ownership interest in certain transmission facilities, and joint development and construction of three transmission projects. The parties also agreed to negotiate in good faith to reach arrangements pertaining to interconnection of their respective systems; joint ownership, operation, and maintenance of parts of the systems; cost-sharing; capital improvements; and each party’s rights to a specified transmission capacity on applicable transmission lines. The MOU further provides that Idaho Power and PacifiCorp will negotiate in good faith to attempt to reach an agreement to terminate existing transmission capacity rights agreements over portions of Idaho Power’s existing transmission system and replace them with new agreements, if required. On July 29, 2010, Idaho Power and PacifiCorp mutually agreed to extend the final date to execute and deliver definitive agreements under the MOU from September 1, 2010 to November 5, 2010. On November 4, 2010, the parties agreed to further extend the timeframe to complete the negotiations to December 31, 2011. The MOU may be terminated by either party at any time.

Joint Purchase and Sale Agreement and Joint Operating Agreements: In connection with the MOU, on April 30, 2010, Idaho Power entered into a Joint Purchase and Sale Agreement with PacifiCorp, pursuant to which Idaho Power agreed to sell to PacifiCorp a 59.0 percent interest in certain high-voltage transmission-related and interconnection equipment located at the Hemingway station south of Boise, Idaho, and PacifiCorp agreed to sell to Idaho Power a 20.8 percent interest in certain high-voltage transmission-related and interconnection equipment located at PacifiCorp’s Populus station in southeast Idaho. Closing of the purchase and sale occurred on May 3, 2010. Construction of the Hemingway and Populus stations is substantially complete. Upon final completion, the estimated purchase price PacifiCorp will have paid to Idaho Power for PacifiCorp’s interest in the Hemingway station is $13.4 million, and the estimated purchase price Idaho Power will have paid to PacifiCorp for Idaho Power’s interest in the Populus station is $14.3 million.

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

Environmental Regulation Costs:

Idaho Power anticipates approximately $42 million in annual capital and operating costs for environmental facilities during 2011. Hydroelectric facility expenses, including costs for relicensing the HCC, and thermal plant expenses account for approximately $25 million and $17 million, respectively. From 2012 through 2013, total environmental-related operating and capital costs are estimated to be approximately $151 million. Expenses related to the hydroelectric facilities during that period are expected to be $84 million and include costs associated with the relicensing of the HCC. Thermal plant expenses are expected to total $67 million during this period. The capital portion of these amounts are included in the Capital Requirements table above but do not include costs related to possible changes in environmental laws or regulations and enforcement policies that may be enacted in response to issues such as climate change and emissions from coal-fired and gas-fired generation plants.

Other Capital Requirements: IDACORP’s non-regulated capital expenditures have primarily related to IFS’s tax-structured investments. Currently there are no significant expenditures anticipated for 2011 through 2013.

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Retirement Benefit Plans

Idaho Power has significant future contribution obligations under its retirement benefit plans. Refer to Note 11 – “Benefit Plans” to the consolidated financial statements included in this report for information relating to those obligations.

Off-Balance Sheet Arrangements

Idaho Power has agreed to guarantee the performance of reclamation activities at BCC, of which IERCo owns a one-third interest. This guarantee, which is renewed each December, was $63 million at December 31, 2010. BCC has a reclamation trust fund set aside specifically for the purpose of paying these reclamation costs. At this time BCC is revising its estimate of future reclamation costs. To ensure that the reclamation trust fund maintains adequate reserves, BCC has the ability to add a per ton surcharge 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 not material.

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		2011		2012-2013		2014-2015		Thereafter
Idaho Power:			(millions of dollars)
Long-term debt ⁽¹⁾			$	1,613	$	121	$	172	$	2	$	1,318
Future interest payments ⁽²⁾				1,352		82		153		142		975
Operating leases				28		4		4		4		16
Uncertain tax positions				51		51		-		-		-
Purchase obligations:
	Cogeneration and small power
		production		5,611		114		351		465		4,681
	Large power production ⁽³⁾			134		123		11		-		-
	Fuel supply agreements			406		80		136		90		100
	Purchased power & transmission ⁽⁴⁾			68		36		16		8		8
	Other ⁽⁵⁾			157		62		41		22		32
		Total purchase obligations		6,376		415		555		585		4,821
Pension and postretirement benefit plans ⁽⁶⁾				235		10		97		81		47
Other long-term liabilities - Idaho Power				2		1		1		-		-
	Total Idaho Power			9,657		684		982		814		7,177
Other:
Long-term debt ⁽¹⁾⁽⁷⁾				3		2		-		-		1
	Total IDACORP		$	9,660	$	686	$	982	$	814	$	7,178
⁽¹⁾ For additional information, see Note 4 – “Long-Term Debt” to the consolidated financial statements included in this report.
⁽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, 2010.
⁽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 $17 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 has been included in the table for presentation purposes.
⁽⁵⁾ Approximately $65 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 has been included in the table for presentation purposes.
⁽⁶⁾ Idaho Power estimates pension contributions based on actuarial data. Idaho Power cannot meaningfully estimate pension contributions beyond 2015 at this time. For more information on pension, please refer to Note 11 – “Benefit Plans” to the consolidated financial statements included in this report.
⁽⁷⁾ Amounts include the obligations of IDACORP’s subsidiaries other than Idaho Power, which is shown separately.

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REGULATORY MATTERS:

Overview

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

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

Idaho and Oregon Significant Rate Changes

As a regulated utility, the price that the IPUC and OPUC authorize Idaho Power to charge for its retail services is a major factor in determining IDACORP’s and Idaho Power’s results of operations and financial condition. The table below summarizes notable rate increases and decreases, shown on an annualized basis. Certain of the regulatory actions that resulted in the rate increases and decreases are described in more detail in this section of MD&A.

			Estimated
		Percentage	Annualized
	Effective	Rate Increase	$ Impact
Description	Date	(Decrease)	(millions)
2007 Idaho general rate case	3/01/2008	5.2%	$	32
Idaho Danskin power plant	6/01/2008	1.4%		9
2008 Idaho PCA	6/01/2008	10.7%		73
2008 Oregon APCU	6/01/2008	15.7%		5
2008 Idaho general rate case	2/01/2009	3.1%		21
2008 Idaho general rate case	3/19/2009	0.9%		6
2009 Idaho PCA	6/01/2009	10.2%		84
2009 Idaho AMI	6/01/2009	1.83%		11
2009 Oregon APCU	6/01/2009	11.5%		4
2009 Oregon general rate case settlement	3/01/2010	15.4%		5
2010 Idaho settlement	6/01/2010	9.9%		89
2010 Idaho PCA	6/01/2010	(16.4%)		(147)
2010 Idaho Pension Expense Recovery	6/01/2010	0.8%		5
2010 Oregon APCU	6/01/2010	5.5%		2

Idaho and Oregon Deferred Net Power Supply Costs

As discussed above, Idaho Power’s power supply costs can vary significantly from year to year, primarily because of the impacts of weather, system loads, and commodity markets. To address the volatility of power supply costs, Idaho Power has power cost adjustment, or PCA, 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.