Edgar Filing: IDAHO POWER CO

Number of Contracts

Nameplate Capacity (MW)

On-line at the end of 2011

Contracted and projected to come on-line by year-end 2014

IDA 12.31.11 10k

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, 2011



	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 )	No	( )	Idaho Power Company	Yes	( )	No	( 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	( )	No	( X )	Idaho Power Company	Yes	( )	No	( 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	( X )	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	( )	No	( X )	Idaho Power Company	Yes	( )	No	( X )

Aggregate market value of voting and non-voting common stock held by non-affiliates (June 30, 2011):



IDACORP, Inc.:	$	1,941,836,645	Idaho Power Company:	None



Number of shares of common stock outstanding as of February 17, 2012:
IDACORP, Inc.:	49,947,098
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 2012 annual meeting of shareholders.

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

The following select abbreviations, terms, or acronyms are found in multiple locations within this report:

ADITC	-	Accumulated Deferred Investment Tax Credits
AFUDC	-	Allowance for Funds Used During Construction
AMI	-	Advanced Metering Infrastructure
aMW	-	Average Megawatts
APCU	-	Annual Power Cost Update
BCC	-	Bridger Coal Company, a joint venture of IERCo
BLM	-	U.S. Bureau of Land Management
BPA	-	Bonneville Power Administration
CAA	-	Clean Air Act
CAMP	-	Comprehensive Aquifer Management Plan
CO₂	-	Carbon Dioxide
CWA	-	Clean Water Act
DEIS	-	Draft Environmental Impact Statement
DSM	-	Demand-Side Management
DSR	-	Demand-Side Resources
EGUs	-	Electric Utility Steam Generating Units
EIS	-	Environmental Impact Statement
EPA	-	U.S. 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.
Idaho ROE	-	Idaho-jurisdiction return on year-end equity
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	-	U.S. Internal Revenue Service
kW	-	Kilowatt
LCAR	-	Load Change Adjustment Rate
MD&A	-	Management’s Discussion and Analysis of Financial Condition and Results of Operations
MW	-	Megawatt
MWh	-	Megawatt-hour
NOx	-	Nitrous Oxide
NSPS	-	New Source Performance Standards
O&M	-	Operations and Maintenance
OATT	-	Open Access Transmission Tariff
OPUC	-	Oregon Public Utility Commission
PCA	-	Power Cost Adjustment
PCAM	-	Power Cost Adjustment Mechanism
PURPA	-	Public Utility Regulatory Policies Act of 1978
REC	-	Renewable Energy Certificate
RES	-	Renewable Energy Standard
RPS	-	Renewable Portfolio Standard
SEC	-	U.S. Securities and Exchange Commission
SO₂	-	Sulfur Dioxide
USBR	-	U.S. Bureau of Reclamation
Valmy	-	North Valmy Steam Electric Generating Plant
VIEs	-	Variable Interest Entities



TABLE OF CONTENTS
		Page
Part I

Item 1	Business	5
Executive Officers of the Registrants		16
Item 1A	Risk Factors	18
Item 1B	Unresolved Staff Comments	26
Item 2	Properties	27
Item 3	Legal Proceedings	28
Item 4	Mine Safety Disclosures	28

Part II


Item 5	Market for Registrant's Common Equity, Related Stockholder Matters, and Issuer Purchases of Equity Securities	28
Item 6	Selected Financial Data	30
Item 7	Management's Discussion and Analysis of Financial Condition and Results of Operations	31
Item 7A	Quantitative and Qualitative Disclosures About Market Risk	72
Item 8	Financial Statements and Supplementary Data	75
Item 9	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	133
Item 9A	Controls and Procedures	133
Item 9B	Other Information	137

Part III

Item 10	Directors, Executive Officers and Corporate Governance*	137
Item 11	Executive Compensation*	137
Item 12	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters*	137
Item 13	Certain Relationships and Related Transactions, and Director Independence*	138
Item 14	Principal Accountant Fees and Services*	138

Part IV

Item 15	Exhibits and Financial Statement Schedules	139

Signatures		151


*Except as indicated in Items 12 and 14, IDACORP, Inc. information is incorporated by reference to
IDACORP, Inc.'s definitive proxy statement for the 2012 annual meeting of shareholders.

SAFE HARBOR STATEMENT

This Annual Report on Form 10-K contains "forward-looking statements" intended to qualify for the safe harbor from liability established by the Private Securities Litigation Reform Act of 1995. Forward-looking statements should be read with the cautionary statements and important factors included in this Form 10-K at Part I, Item 1A - "Risk Factors" and in Part II, Item 7 - "Management's Discussion and Analysis of Financial Condition and Results of Operations" (including under the heading "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," "targets," "predicts," "projects," "may result," "may continue," or similar expressions.

PART I

ITEM 1. BUSINESS

OVERVIEW

IDACORP, Inc. (IDACORP) is a holding company incorporated in 1998 under the laws of the state of Idaho, and its 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 access to books and records to the Federal Energy Regulatory Commission (FERC) and state utility regulatory commissions and imposes record retention and reporting requirements on IDACORP.

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 99 percent of IDACORP’s net income in 2011. Segment data is presented in Note 17 – "Segment Information" to the consolidated financial statements included in this report. As of December 31, 2011, IDACORP had 2,058 full-time employees, 2,046 of whom were employed by Idaho Power, and 23 part-time employees, 22 of whom were employed by Idaho Power.

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 U.S. Securities Exchange Act of 1934 as soon as reasonably practicable after the reports are electronically filed with or furnished to the U.S. 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, 2011, Idaho Power supplied electric energy to approximately 496,000 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. Idaho Power's service territory is illustrated on the following page.

Weather, customer demand, and economic conditions impact electricity sales and costs and, therefore, utility revenues are not earned 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 demand for electric power for heating purposes.

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. Further, the FERC has jurisdiction over, among other items, Idaho Power's transmission and wholesale sales of electricity, hydroelectric relicensing, and system reliability.

General 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 continuously evaluates and refines its business strategy to ensure coordination among and integration of all functional areas of the company. Idaho Power’s business strategy seeks to balance the interests of owners, customers, employees, and other stakeholders while maintaining the company’s financial stability and flexibility. The strategy includes:


•	Responsible Planning: Idaho Power’s planning process is intended to ensure adequate generation and transmission resources to meet 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.


•	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.

Rates and Revenues

Retail: Idaho Power periodically evaluates the need to seek changes to its retail electricity price structure to 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, a pension balancing account, 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 these proceedings, which are conducted under established procedural schedules, include Idaho Power, the IPUC or OPUC, and other interested parties. The IPUC and OPUC are required to ensure that the prices and terms of service are fair, non-discriminatory, and provide Idaho Power an opportunity to recover its costs and 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. Deferred amounts are generally collected from, or refunded to, retail customers through the use of supplemental tariffs.

For additional information on regulatory matters, including 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 in 2011 with Special Customer Electric Service Agreements: Idaho Power is authorized to enter into special electric service arrangements with customers that have an aggregate power requirement that exceeds 20 megawatts (MW). Notable recent developments with respect to one of those arrangements are described below.

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 is four years beginning 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 31, 2011. In December 2011, Idaho Power sent to Hoku a notice of termination of service pursuant to IPUC rules to terminate service as a result of an overdue invoice for electric service. On January 9, 2012, Hoku filed a petition with the IPUC alleging that its contract with Idaho Power was contrary to the public interest and requested that the IPUC reform the contract and sought reparations for previously paid amounts under the electric service agreement. On January 13, 2012, the IPUC ordered Idaho Power and Hoku to enter into negotiations to seek settlement of Hoku's petition. On February 17, 2012, Idaho Power, Hoku, and the IPUC Staff filed with the IPUC a settlement stipulation that would amend the electric service agreement. The stipulation provides for a minimum monthly charge of $0.8 million (compared to the existing minimum monthly charge of approximately $2 million) from January 2012 to July 2013 and the establishment of a balancing mechanism that will track and accrue (up to a maximum balance of approximately $16.5 million) on a monthly basis the difference between (a) the first block minimum energy charges (excluding demand charges) under the existing agreement and (b) the modified minimum billed energy charge (excluding demand charges) under the settlement stipulation. In January 2014, Idaho Power will begin invoicing Hoku for, in addition to applicable demand and energy charges, recovery of the deferred amount over a 12 month period, one-twelfth per month. Further, the stipulation provides that Hoku will pay to Idaho Power $2.0 million upon IPUC approval of the stipulation out of existing funds on deposit with Idaho Power, and $0.1 million per month in cash for 18 months commencing with its January 2012 invoice. The stipulation also extends the term of the electric service agreement through December 1, 2014. During the final year of the agreement, Hoku will pay embedded-cost based rates for service. Hoku agrees in the stipulation to cap its monthly power demand during the January 2012 to July 2013 deferral period to 20 MW, with the option to increase usage to 82 MW following a notice period and payment of applicable deposits. In the event Hoku uses more than 20 MW of energy in any given month, Hoku will be required to pay the minimum billed energy charge amounts set forth in the existing electric service agreement.

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 network reliability standards, as well as enhanced oversight of power and transmission markets,

including protection against market manipulation. These mandatory transmission and reliability standards, which are applicable to Idaho Power, were developed by the North American Electric Reliability Corporation (NERC) and the Western Electricity Coordinating Council (WECC), which has responsibility for compliance and enforcement of transmission and reliability standards.

Idaho Power has one low-volume 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 had one firm wholesale power sales contract with Raft River Electric Cooperative for up to 15 MW, which expired in September 2011.

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, which 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 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.”



	Year Ended December 31,
	2011			2010			2009
Revenues (thousands of dollars)
Residential	$	405,982		$	400,607		$	409,479
Commercial	220,962			231,440			232,816
Industrial	140,701			138,394			141,530
Irrigation	104,635			110,555			109,655
Provision for sharing	(27,099		)	—			—
Deferred revenue related to Hells Canyon Complex relicensing AFUDC	(10,636		)	(10,625		)	(9,715		)
Total general business	834,545			870,371			883,765
Off-system sales	101,602			78,133			94,373
Other	86,581			84,548			67,858
Total	$	1,022,728		$	1,033,052		$	1,045,996
Energy use (thousands of MWh)
Residential	5,146			4,967			5,300
Commercial	3,815			3,763			3,858
Industrial	3,100			3,076			3,140
Irrigation	1,673			1,707			1,650
Total general business	13,734			13,513			13,948
Off-system sales	3,635			1,982			2,836
Total	17,369			15,495			16,784

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. 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, load demand, and economic conditions impact power supply costs. Drought conditions and increased peak load demand cause a greater reliance on potentially more expensive energy sources to meet load requirements. Conversely, favorable hydroelectric generation conditions increase production at Idaho Power’s hydroelectric generating facilities and reduce the need for thermal generation and 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. During 2011, the largest peak demand was 2,973 MW, set on July 6, 2011. The following table presents Idaho Power’s total power supply for the last three years:



	MWh			Percent of Total Generation
	2011	2010	2009	2011		2010		2009
	(thousands of MWh)
Hydroelectric plants	10,937	7,344	8,096	69	%	51	%	53	%
Coal-fired plants	4,820	6,864	6,941	30	%	48	%	45	%
Natural gas fired plants	138	160	242	1	%	1	%	2	%
Total system generation	15,895	14,368	15,279	100	%	100	%	100	%
Purchased power - cogeneration and
small power production	1,495	910	970
Purchased power - other	1,256	1,491	1,942
Total purchased power	2,751	2,401	2,912
Total power supply	18,646	16,769	18,191

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 optimized operation of its hydroelectric facilities in the past has been impacted by intermittent wind generation and may continue to be impacted 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.

Significantly greater snow accumulation during the winter and the resulting effect on stream flow conditions resulted in above average stream flow in 2011, which resulted in a 3.6 million MWh increase in generation from Idaho Power’s hydroelectric facilities compared to 2010. The observed stream flow data released in August 2011 by the U.S. Army Corps of Engineers, Northwest Division indicated that Brownlee Reservoir inflow for April through July 2011 was 10.5 million acre-feet (maf), compared to 4.6 maf in April through July 2010 and 5.6 maf in April through July 2009. Annual Brownlee Reservoir inflow for 2011 was 19.3 maf compared to 10.7 maf in 2010 and 11.3 maf 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 Note 10 - "Contingencies" to the consolidated financial statements included in this report.

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

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 from 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. Idaho Power also has three Oregon licenses under the Oregon Hydroelectric Act, which applies to Idaho Power’s Brownlee, Oxbow, and Hells Canyon facilities. For further information on relicensing activities see Part II, Item 7 – “MD&A – Regulatory Matters – Relicensing of Hydroelectric Projects.”

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, in which Idaho Power has a one-third interest;


•	Boardman located in Oregon, in which Idaho Power has a 10 percent interest; and


•	Valmy located in Nevada, in which Idaho Power has a 50 percent interest.

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 no later than November 1, 2012. Based on the current project status, Idaho Power estimates that the plant will be in service by July 1, 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, which is operated by PacifiCorp. 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 mine 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.

The Boardman generating plant receives coal through annual contracts with suppliers from the Powder River Basin in northeast Wyoming. Portland General Electric Company, as the operator of the Boardman plant, has two agreements to supply coal beginning in 2012. All of the Boardman plant’s coal requirements in 2012, approximately 50 percent in 2013, and 33 percent in 2014, are under contract. A portion of the 2013 and 2014 coal used will be low sulfur content as Boardman prepares for the 2015 transition to a lower sulfur fuel content. As a ten percent owner of the plant, Idaho Power is obligated to purchase ten percent of the coal purchased under these agreements. In December 2010, the Oregon Environmental Quality Commission approved a plan to cease coal-fired operations at the Boardman power plant not later than December 31, 2020. For additional information, see Part II, Item 7 – "MD&A – Environmental Matters – Environmental Regulation."

NV Energy, Inc., as the operator of the Valmy generating plant, has agreements with coal suppliers through 2015. Idaho Power's share of these agreements along with existing coal inventory at the plant cover Idaho Power's projected coal supply needs for 2012, 2013, and 2014 and approximately 50 percent in 2015. As a 50 percent owner of the plant, Idaho Power is obligated for one-half of the coal purchased under these contracts.

Fuel Supply - Natural Gas: Idaho Power owns and operates the Danskin and Bennett Mountain combustion turbines, and is constructing its Langley Gulch natural gas-fired combined-cycle power plant. Natural gas for all facilities is purchased based on system requirements and dispatch efficiency. The natural gas is supplied through Williams-Northwest Pipeline under Idaho Power's 55,584 million British thermal units (MMBtu) per day long-term gas transportation service agreements. The agreements vary in contract length, with the latest termination date of May 2042, but with extensions at Idaho Power’s discretion. In addition to the long-term gas transportation service agreements, Idaho Power has entered into a long-term storage service agreement with Northwest Pipeline 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 89 percent of its eventual total, with its full allotment expected to be reached by July 2012. This firm storage contract expires in 2043. Natural gas will be purchased and stored with the intent of fulfilling needs as identified for seasonal peaks or to meet system requirements.

Idaho Power estimates that its Langley Gulch plant will be in service by July 1, 2012, in time to contribute to meeting summer loads. Approximately 1.2 million MMBtu's of natural gas has been hedged using financial instruments for future purchases for start-up testing of the plant expected to take place between March 2012 and May 2012. Along with this, approximately 2.9 million MMBtu's of natural gas has been financially hedged for future purchases for the operational dispatch of Langley Gulch from July 2012 to January 2013. Idaho Power plans to manage the procurement of additional natural gas as necessary to meet system requirements and fueling strategies.

Purchased Power Agreements: Idaho Power purchases power in the wholesale market and pursuant to long-term power purchase contracts, as described below:

Wholesale Market Purchases: Idaho Power purchases power in the wholesale 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 wholesale market. Idaho Power has the following notable firm wholesale power purchase 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 2012;


•	Raft River Energy I, LLC - for up to 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. USG Oregon LLC has stated that it expects commercial operation by late 2012; and


•	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.

CSPP and PURPA Power Purchase Contracts: Pursuant to the requirements of Section 210 of PURPA, the state regulatory commissions having jurisdiction over Idaho Power 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. 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, and the OPUC jurisdictional portion is recovered through general rate case filings and the PCAM;

•

IPUC jurisdictional regulations allow IPUC published avoided costs for up to a 20-year contract term. Effective December 14, 2010, wind and solar resource projects with a nameplate rating of 100 kW or less are eligible for the IPUC published avoided costs. For all other resource types, a project that generates up to ten average MW of energy monthly is eligible for the IPUC published avoided costs;


•	OPUC jurisdictional regulations allow OPUC published avoided costs for up to a 20-year contract term for projects with a nameplate rating of up to ten MW of capacity; and


•	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.

Idaho Power believes that published avoided cost rates in effect as of the date of this report provide a favorable climate for PURPA project development. Mandated purchase of intermittent, non-dispatchable energy at published avoided cost rates may result in Idaho Power acquiring energy at above wholesale market prices when a surplus already exists (at times resulting in sale of the surplus energy in the wholesale markets at a loss) and result in additional integration costs, thus increasing costs to its customers. Following a dramatic increase in anticipated PURPA projects, 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 obtaining published avoided cost rates, effective retroactively to December 14, 2010, to 100 kW for wind and solar PURPA projects only. On June 8, 2011, the IPUC disapproved 13 contracts for pending wind projects with a combined nameplate capacity of 294 MW. If these 13 contracts had all been approved, the amount of wind generation that Idaho Power had under contract would have exceeded 1,000 MW. The IPUC has opened a docket to further investigate PURPA contract terms and conditions and pricing models. This matter is scheduled for hearings in August 2012. For further information on those proceedings, refer to "MD&A - Regulatory Matters - PURPA Power Purchase Contracts."

As of December 31, 2011, Idaho Power had 40 MW of solar power generation under contract for purchase. In December 2011, Idaho Power entered into a PURPA purchase power agreement for a 20-MW waste biomass generation project. Idaho Power has also entered into a number of other PURPA agreements for smaller renewable energy projects.

As of December 31, 2011, Idaho Power had the following signed CSPP-related agreements with terms ranging from one to 35 years:

The majority of new facilities will be wind resources that will generate on an intermittent basis. During 2011, Idaho Power purchased 1.5 million MWh of power from CSPP facilities at a cost of $90 million, resulting in a blended price of $60.36 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 entities in 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

Integrated Resource Plan: Idaho Power filed its 2011 Integrated Resource Plan (IRP) with the IPUC and OPUC in June 2011. 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 2011 IRP was accepted by the IPUC in December 2011. As of the date of this report the 2011 IRP has not been acknowledged by the OPUC. 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;


•	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 2013 IRP will begin in the summer of 2012. Idaho Power expects that the updated plan will be completed and filed in June 2013. During the time between resource plan filings, the public and regulatory oversight of the activities identified in the 2011 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 2011 IRP included the 300-MW Langley Gulch project currently under construction and a 50-MW expansion of the Shoshone Falls hydroelectric facility. The 2011 IRP also identified the Boardman-to-Hemingway transmission line in the preferred resource portfolio. Idaho Power believes the Boardman-to-Hemingway transmission line and the Hemingway substation, together with the Gateway West transmission line, will improve reliability, relieve congestion, and provide system flexibility. Additional information about Idaho Power’s significant infrastructure development projects are discussed in Part II, Item 7 – “MD&A – Liquidity and Capital Resources – Capital Requirements – Major Infrastructure Projects.”

The expected-case load forecast in the 2011 IRP projects peak-hour load will grow 69 MW annually and average-system load will increase annually 29 average MW (aMW) over the 20-year planning period, with an expected-case, median, average annual system load of 2,362 aMW by 2030. Idaho Power intends to meet the anticipated increase in demand through energy efficiency and demand response programs, the development of transmission capacity and additional generation resources, such as the Langley Gulch and Shoshone Falls projects, and from the purchase of power from third parties, including from renewable energy projects and market power purchases. Idaho Power stated in the 2011 IRP that it expects energy efficiency programs to result in 233 aMW of load reduction by 2030, and that demand response programs are targeted to reduce peak summer load by 351 MW by summer 2016.

The 2011 IRP also included discussion related to geothermal, combined heat and power (CHP), and solar resources, each of which is described below.

Geothermal Resources: Idaho Power has continued to work with geothermal 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. This project is currently under construction and the developer expects it to be operational in late 2012. Idaho Power has contracted to receive the RECs from the project during the term of the agreement. The additional 2016 increment of geothermal energy was evaluated in the 2011 IRP and was found unnecessary with the addition of the Boardman-to-Hemingway transmission line project. The preferred portfolio in the 2011 IRP did include 52 MW of geothermal energy in 2021 and Idaho Power plans to follow the development of geothermal resources in and around Idaho Power's service area in the event a project materializes that could fill this need in 2021.

CHP Resources: CHP, also commonly referred to as "cogeneration," facilities utilize by-product heat (often through steam) to generate electricity. CHP resources were not included in the 2011 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 generate as much as 100 MW of electricity. The IOER and Idaho Power jointly funded the study, which confirmed initial estimates of the project’s potential benefits. In September 2010, Idaho Power, IOER, and TASCO agreed to complete a more detailed feasibility study to refine performance and financial modeling of the proposed project. The second feasibility study indicated that the CHP project is technically feasible; however, given the increase in the amount of PURPA power generation Idaho Power now has under contract, current economic and electric power market conditions, the current treatment of CHP projects under federal incentive programs, and TASCO's and IPC's individual needs, proceeding with developing this CHP project does not appear to be the most economic choice for either party.

Solar Resources: On or before January 1, 2020, Idaho Power is required to own or contract to purchase the capacity and output from a qualifying solar photovoltaic (PV) system with a minimum capacity of 500 kW pursuant to the state of Oregon's solar PV capacity standard. The timing of development of this required project in Oregon and the solar demonstration project referenced in Idaho Power's 2011 IRP will depend in large part on Idaho Power's ability to resolve integration, reliability, and cost issues associated with the recent influx of PURPA resources from which Idaho Power is currently mandated to purchase power. However, with the cost of solar PV technology continuing to decrease, Idaho Power believes this technology will

become more prevalent in its service area. Idaho Power continues to evaluate the timing for proceeding with solar resource projects.

Energy Efficiency and Demand Response Programs: Idaho Power has 16 energy efficiency and demand response programs targeting energy 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 acquiring energy efficient equipment, and using energy efficiency techniques for 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.

In 2011, Idaho Power’s energy efficiency programs reduced energy usage by approximately 160,000 MWh. Idaho Power's demand response programs had available capacity of approximately 410 MW; however, because of a relatively mild summer and the restructuring of Idaho Power's irrigation peak rewards program, Idaho Power realized approximately 83 MW in summer peak demand reduction through combined performance.

In 2011, Idaho Power spent approximately $46.3 million on energy efficiency and targeted demand reduction response programs. Approximately $37.7 million of funding for these programs is provided by Idaho and Oregon energy efficiency tariff riders, while the balance of the funding comes from Idaho Power base rates. Beginning in 2011, as approved by the IPUC, Idaho Power capitalized approximately $7 million of custom efficiency program incentives as a regulatory asset.

Approximately $4 million of Idaho Power’s 2011 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.

Environmental Regulation and Costs

Idaho Power's activities are subject to a broad range of federal, state, regional, and local laws and regulations designed to protect, restore, and enhance the quality of the environment. 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 environmental regulations, and the modification of system operations to accommodate environmental regulations. In addition to generally applicable regulations, the FERC licenses issued for Idaho Power’s hydroelectric generating plants have environmental requirements such as aeration of turbine water to meet dissolved gas and temperature standards in the tail waters downstream from the plants. Idaho Power monitors these issues and reports the results to the appropriate regulatory agencies. Idaho Power co-owns three coal-fired power plants and owns two natural gas combustion turbine power plants that are subject to a broad range of environmental requirements, including air quality regulation. For a more detailed discussion of these and other environmental issues, refer to Part II, Item 7 – “MD&A – Environmental Matters.”

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 levels. 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	2012		2013 - 2014
Capital expenditures:
Studies and measures at hydroelectric facilities	$	12	$	31
Investments in equipment and facilities at thermal plants	15		99
Total capital expenditures	$	27	$	130
Operating expenses:
Operating costs for environmental facilities - hydroelectric	$	21	$	48
Operating costs for environmental facilities - thermal	12		27
Total operations and maintenance	$	33	$	75

Idaho Power anticipates that a number of new and 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 in addition to the amounts set forth above.

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 $6 million, $7 million, and $8 million in 2011, 2010, and 2009, respectively. IFS’s portfolio also includes historic rehabilitation projects such as the Empire Building in Boise, Idaho. IFS made no new investments in 2011, but did have $7 million and $14 million in new investments during 2010 and 2009, respectively, and will continue to evaluate new opportunities for investment 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, 2011, the gross amount of IFS’s portfolio equaled $198 million in tax credit investments. These investments cover 49 states, Puerto Rico, and the U.S. Virgin Islands. The underlying investments include nearly 700 individual properties, of which all but five are administered through syndicated funds.

IDA-WEST

Ida-West operates and has a 50 percent interest in nine hydroelectric plants with a total generating capacity of 45 MW. Four of the projects are located in Idaho and five are in northern California. All nine projects are “qualifying facilities” under PURPA. Idaho Power purchased all of the power generated by Ida-West’s four Idaho hydroelectric projects at a cost of $9 million, $8 million, and $9 million in 2011, 2010, and 2009, respectively.

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.

Senior Executive Officers (in alphabetical order)

DARREL T. ANDERSON, 53


•	President and Chief Financial Officer of Idaho Power Company, January 1, 2012 - present.


•	Executive Vice President, Administrative Services and Chief Financial Officer of IDACORP, Inc., October 1, 2009 - present.


•	Executive Vice President, Administrative Services and Chief Financial Officer of Idaho Power Company, October 1, 2009 - December 31, 2011.


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

REX BLACKBURN, 56


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

•Senior Attorney, 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, 46


•	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.

J. LAMONT KEEN, 59


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


•	Chief Executive Officer of Idaho Power Company, November 17, 2005 - present.


•	President of Idaho Power Company, March 1, 2002 - December 31, 2011.


•	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.

STEVEN R. KEEN, 51


•	Senior Vice President, Finance and Treasurer of Idaho Power Company, January 1, 2012 - present.


•	Vice President, Finance and Treasurer of IDACORP, Inc., June 1, 2010 - present.


•	Vice President, Finance and Treasurer of Idaho Power Company, June 1, 2010 - December 31, 2011.


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


•	President of IDACORP Financial Services, January 15, 1999 - May 31, 2007.

DANIEL B. MINOR, 54

•Executive Vice President and Chief Operating Officer of Idaho Power Company, January 1, 2012 - present.

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

•Executive Vice President, Operations of Idaho Power Company, October 1, 2009 - December 31, 2011.

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

Other Executive Officers (in alphabetical order)

DENNIS C. GRIBBLE, 59

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

•Vice President and Chief Information Officer of IDACORP, Inc., June 1, 2006 - December 31, 2011.

•Vice President and Treasurer of IDACORP, Inc. and Idaho Power Company, July 15, 2004 - June 1, 2006.

PATRICK A. HARRINGTON, 51


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

•Senior Attorney, IDACORP, Inc. and Idaho Power Company, June 7, 2003 - March 15, 2007.

WARREN KLINE, 56


•	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.

JEFFREY MALMEN, 44


•	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 10, 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.

LUCI K. MCDONALD, 54


•	Vice President, Human Resources and Corporate Services of Idaho Power Company, May 20, 2010 - present


•	Vice President, Human Resources and Corporate Services of IDACORP, Inc., May 20, 2010 - December 31, 2011.


•	Vice President – Human Resources of IDACORP, Inc. and Idaho Power Company, December 6, 2004 - May 20, 2010.

KEN W. PETERSEN, 48


•	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 3, 2004 - December 28, 2007.

N. VERN PORTER, 52


•	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 30, 2003 - April 22, 2006.

GREGORY W. SAID, 57


•	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.

NAOMI SHANKEL, 40


•	Vice President, Supply Chain of Idaho Power Company, May 20, 2010 - present.


•	Vice President, Supply Chain of IDACORP, Inc., May 20, 2010 - December 31, 2011.


•	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 19, 2003 - September 21, 2006.

LORI D. SMITH, 51


•	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 1, 2004 - January 1, 2008.

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 and Idaho Power 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 needs to cover existing and future costs and earn a rate of return, earnings and cash flows may be reduced. The prices that the Idaho Public Utilities Commission and Oregon Public Utility Commission authorize Idaho Power to charge for its retail services, and the tariff rate that the Federal Energy Regulatory Commission permits Idaho Power to charge for transmission, are generally the most significant factors influencing IDACORP’s and Idaho Power’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. Also, the rates allowed by the Federal Energy Regulatory Commission for transmission service may be insufficient for recovery of costs incurred. While the Idaho Public Utilities Commission and Oregon Public Utility Commission have established 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 of return. 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 considerable discretion in applying this standard. The ratemaking process typically involves multiple parties, including governmental bodies, consumer advocacy groups, and customers. While each party has differing concerns, they often have the common objective of limiting rate increases or even reducing rates. Idaho Power cannot predict the outcome of ratemaking proceedings, including the extent to which costs, including the costs of significant capital projects, will be recovered or what rates of return will be authorized. The failure of Idaho Power to recover those costs, or recover them in a timely manner, may decrease IDACORP's and Idaho Power's earnings and adversely impact cash flows.

For additional information relating to Idaho Power's regulatory framework, see Note 3 - "Regulatory Matters" to the consolidated financial statements included in this report and "Regulatory Matters" in Part II, Item 7 - "Management's Discussion and Analysis of Financial Condition and Results of Operations" in this report.

Idaho Power's cost recovery deferral mechanisms may not function as intended, which may adversely affect cash flows and liquidity. Idaho Power 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’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 mechanisms only partially offset the potentially adverse financial impacts of forced generating plant outages, severe weather, reduced hydroelectric generation, and volatile wholesale energy prices. Because of the power cost adjustment mechanisms, 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 base 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, which began as a pilot program for Idaho Power’s Idaho residential and small general service customers, running from 2007 through 2011. The fixed cost adjustment 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. In October 2011, Idaho Power filed an application with the Idaho Public Utilities Commission requesting that the fixed cost adjustment pilot program become permanent. As of the date of this report, the Idaho Public Utilities Commission has not issued a determination. If the fixed cost adjustment is not approved as permanent, or if the Idaho Public Utilities Commission modifies the fixed cost adjustment in some manner, Idaho Power may incur fixed costs that may not be recoverable in rates in times of declining usage per residential and small general service customer, or may recover more than the fixed costs incurred in times of increasing usage per residential and small general service customer. This over- or under-collection of fixed costs would likely continue until Idaho Power's next Idaho general rate case when the recovery of fixed costs through base rates can be realigned, which could adversely affect Idaho Power's cash flows and liquidity.

For additional information relating to Idaho Power's regulatory framework and cost recovery mechanisms, see Note 3 - "Regulatory Matters" to the consolidated financial statements included in this report and "Regulatory Matters" in Part II, Item 7 - "Management's Discussion and Analysis of Financial Condition and Results of Operations" in this report.

Reduced hydroelectric generation can reduce revenues and increase costs, and reduce earnings and cash flows. Idaho Power derives a significant portion of its power supply from its hydroelectric facilities. Because of Idaho Power’s heavy reliance on hydroelectric generation, the availability of water can significantly affect its operations. When hydroelectric generation is reduced, Idaho Power must increase its use of generally more expensive thermal generating resources and purchased power; therefore, opportunities for off-system sales are reduced, which reduces revenues. The further integration of wind and other intermittent power sources into Idaho Power's system may also displace lower cost hydroelectric resources. Integration of intermittent power sources may also increase costs at thermal plants due to wear and tear associated with frequent start-up and shut-down of those facilities to balance loads. While Idaho Power expects to recover, as a result of its power cost adjustment mechanisms, the majority of its net power supply costs above current rates (including the power cost adjustment forecast), recovery of the excess amounts may not occur until the subsequent power cost adjustment year, impacting cash flows and liquidity.

Declines in stream flows and over-appropriation of water in Idaho may reduce hydroelectric generation and revenues and increase costs, and reduce earnings and cash flows. The combination of declining Snake River base flows, over-appropriation of water, and periods of drought have led to water rights disputes and proceedings among surface water and ground water irrigators and the State of Idaho. Recharging the Eastern Snake Plain aquifer by diverting surface water to porous locations and permitting it to sink into the aquifer is one proposed solution to the over-appropriation dispute. Diversions from the Snake River for aquifer recharge or the loss of water rights may further reduce Snake River flows available for hydroelectric generation. Idaho Power’s January 2010 settlement agreement with the State of Idaho resolves litigation regarding certain Idaho Power 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’s hydroelectric projects. The comprehensive aquifer management plan process and the resolution of pending proceedings relating to the Snake River may affect Snake River flows available for hydroelectric generation and thereby reduce Idaho Power’s revenues and increase costs, and may reduce earnings and cash flows.

Idaho Power’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 relies on coal and natural gas to fuel its generation facilities. As part of its normal business operations, Idaho Power purchases power and natural gas in the open market or under short-term, long-term, or variable-priced contracts. Market prices for coal and natural gas are influenced by factors impacting supply and demand, such as weather conditions, fuel transmission or transportation availability, economic conditions, and changes in technology. Increases in demand for coal or natural gas may result in market price increases, short-term price volatility, and supply availability issues. Any disruption in Idaho Power’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. Idaho Power may not be able to fully recover these increased costs through ratemaking, which may reduce earnings. Further, Idaho Power's power cost adjustment mechanisms contain a cost-sharing feature that does not in all circumstances provide for full recovery of incurred costs in customer rates.

Idaho Power’s power generating facilities are subject to numerous operational risks unique to it and its industry. Operating risks associated with Idaho Power's generation facilities include equipment failures, volatility in fuel and transportation pricing, interruptions in fuel supplies, increased regulatory compliance costs, labor disputes, workforce safety matters, the loss of cost-effective disposal options for solid waste, operator error, and the occurrence of catastrophic events at the facilities. Diminished availability or performance of Idaho Power's transmission and distribution facilities could result in reduced customer satisfaction and regulatory inquiries and fines. Operation of Idaho Power's owned and co-owned generating stations below expected capacity levels, or unplanned outages at these stations, could cause reduced energy output and lower efficiency levels and result in lost revenues and increased expenses. These operational risks may result in plant outages, as well as increased operation and maintenance expenses, power generation costs, and power purchase costs, which could have an adverse impact on earnings and cash flows.

Load changes in Idaho Power’s service territory expose Idaho Power to greater market and operational risk and could increase costs and reduce earnings and cash flows. While Idaho Power’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 peak system demand. While Idaho Power is exploring targeted opportunities for managed load growth, load growth can create planning and operating difficulties for Idaho Power that can negatively impact its ability to reliably serve customers. Through current regulatory mechanisms, Idaho Power can expect to recover the majority of the net power supply costs above the amounts included in its rates, though recovery of the excess amounts does not occur until the subsequent power cost adjustment year, and the remaining amount is absorbed by Idaho Power, which could increase costs and reduce earnings and cash flows. Load growth can also result in the need for additional investments in Idaho Power’s infrastructure to serve the new load. For instance, to meet customer demand Idaho Power is currently constructing its Langley

Gulch natural gas-fired generating plant, and has in development a number of transmission projects. If Idaho Power is 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 investments are made and costs are recovered would have a negative effect on earnings and cash flows. Further, while Idaho Power has experienced a general trend of load growth in its service territory in recent years, increased emphasis on energy efficiency and weak economic conditions could result in a decline in loads, which may decrease Idaho Power's revenues from energy sales. Also, Idaho Power's regulatory mechanisms, including its load change adjustment rate included in its power cost adjustment, may not result in Idaho Power recovering all of its costs associated with load decreases, which would have a negative impact on earnings and cash flows.

Federally mandated purchases of power from PURPA power purchase projects, and integration of power generated from those projects into Idaho Power's system, may increase costs and decrease system reliability, and adversely affect cash flows, financial condition, and earnings. An abundance of intermittent, non-dispatchable wind power generation at times when Idaho Power has available lower-cost resources to meet load demands has an impact on the operation of Idaho Power's hydroelectric generation plants, system reliability, power supply costs, and the wholesale power markets in the Pacific Northwest. Wind power generated from PURPA projects, which Idaho Power is generally obligated to purchase regardless of the then-current load demand or wholesale energy market prices, increases the likelihood and frequency that Idaho Power will be required to reduce output from its lower-cost hydroelectric and fossil fuel-fired generation resources, even when weather conditions have resulted in favorable hydroelectric generation conditions or fuel prices are low. Wind generation in the Pacific Northwest during periods when abundant hydroelectric generation is also available reduces wholesale market prices. This may result in Idaho Power's sale of excess wind power at a significant discount to the price Idaho Power paid for the wind power under PURPA wind power purchase contracts. It may also result in the sale of excess lower-cost hydroelectric or fuel-based power at depressed wholesale market prices. When forecasted wind or other intermittent resources do not materialize, Idaho Power must obtain a substitute source of power to meet load demand, and often must purchase power in the wholesale power markets to balance loads. Further, balancing load and generation from Idaho Power's power generation portfolio is challenging, and Idaho Power expects that its costs will increase as a result of its efforts to integrate intermittent, non-dispatchable power from a large number of PURPA power projects. Idaho Power anticipates that those costs will escalate as the volume of wind and other intermittent power on Idaho Power's system increases, which may adversely affect IDACORP's and Idaho Power's cash flows, financial condition, and earnings.

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 reduce retail revenues from power sales and may impact the amount and timing of hydroelectric generation. Changes in the amount and timing of snowpack and stream flows may also adversely affect hydroelectric generation. Extreme weather events and their associated impacts, such as high winds and fires, can disrupt transmission and distribution systems and cause service interruptions and extended outages, increase supply chain costs, potentially interrupt use of generation resources, and limit Idaho Power's ability to meet customer energy demand. Rapid increases in load requirements resulting from unexpected adverse weather changes, particularly if coupled with transmission constraints or system damage, could adversely impact Idaho Power's costs and ability to meet customer energy demand. Conversely, rapid decreases in load requirements due to unexpected weather events could result in Idaho Power's sale of excess energy at depressed wholesale market prices. Disruption in generation, transmission, and distribution systems due to weather-related factors also increases operations and maintenance expenses and reduces earnings and cash flows.

Long-term climate change could increase the likelihood and frequency of these adverse weather events. Further, legislative and/or regulatory developments associated with climate change could affect construction 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 and Idaho Power's power generation portfolio in general. Also, consumer preference for 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 weather and climate change could decrease revenues, increase operating costs, and reduce IDACORP’s and Idaho Power’s earnings and cash flows.

In Idaho Power's service territory, demand for power peaks during the hot summer months, often concurrent with a seasonal increase in wholesale power market prices. As a result, Idaho Power's operating results fluctuate substantially on a seasonal basis. In addition, Idaho Power will generally sell less power, and correspondingly have lower net income, when weather conditions in its service areas are milder. Unusually mild weather in the future could diminish IDACORP's and Idaho Power's results of operations and adversely affect its financial condition.

Idaho Power’s risk management policy and programs relating to economically hedging power and gas exposures, financial and interest rate risk, and counterparty creditworthiness may not always perform as intended, and as a result Idaho Power may suffer economic losses. Idaho Power enters into transactions to hedge its positions in coal, natural gas, power, and other commodities. These hedging transactions are impacted by a range of factors, including variations in power demand, fluctuations in market prices, and market prices for alternative commodities. In connection with these hedging transactions, Idaho Power 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, or are parties to commodity price risk management arrangements. Idaho Power actively manages the market risk inherent in its energy related activities and counterparty credit positions by establishing and enforcing risk limits and risk management policies. Idaho Power 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, power purchase volumes from intermittent sources, transmission availability, and market prices may be significantly different than those originally planned for when Idaho Power enters into its positions in hedging transactions. This 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 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’s hedged positions performing less favorably than unhedged positions. In addition, Idaho Power’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, where the price for the particular commodity may at that time be higher. As a result, risk management decisions may adversely affect IDACORP’s and Idaho Power’s financial condition, results of operations, or cash flows.

Also, as part of IDACORP's and Idaho Power's risk management programs, they may use a variety of non-derivative and derivative financial instruments, such as swaps, futures, and forwards, to manage market risks. They may also use interest rate derivative instruments to hedge against interest rate fluctuations related to debt. In the absence of actively quoted market prices and pricing information from external sources, the valuation of some of the derivative instruments involves management’s judgment or use of estimates. As a result, changes in the underlying assumptions or use of alternative valuation methods could affect the reported fair value of some of the contracts. IDACORP or Idaho Power could also recognize financial losses as a result of volatility in the market values of these contracts or if a counterparty fails to perform, which could adversely affect IDACORP's or Idaho Power's results of operations, financial condition, and cash flows.

Idaho Power’s ability to enter into swaps and derivatives and hedge commodity and interest rate risk may be adversely affected by recent federal legislation. The Dodd-Frank Wall Street Reform and Consumer Protection Act (Dodd-Frank Act) was signed into law in July 2010. The Dodd-Frank Act establishes regulatory jurisdiction by the Commodity Futures Trading Commission and the Securities and Exchange Commission for certain swaps and derivative instruments and the users of those instruments. A number of federal agencies, including the Commodity Futures Trading Commission and the Securities and Exchange Commission, must adopt rules to implement the Dodd-Frank Act. As Idaho Power enters into swap and derivative transactions from time to time in connection with its general business operations, these rules, when implemented, could have a significant impact on Idaho Power and will likely increase the costs Idaho Power incurs in connection with its swap and derivative transactions. Under the rules, Idaho Power may be required to post collateral to meet minimum capital and margin requirements. The Dodd-Frank Act also requires a broad category of swaps to be cleared and traded on registered exchanges or special derivatives exchanges. These clearing requirements would result in a significant change from Idaho Power's current practice of bilateral transactions and negotiated credit terms. The Dodd-Frank Act outlines an elective exemption to the clearing requirements for swaps entered into by end users that are not "major swap participants" or "swap dealers" and that enter into hedges to mitigate their own commercial risk. Although Idaho Power expects that its swaps will qualify under the end user exemption, there can be no assurance they will qualify. Further, even if Idaho Power's swaps were to qualify under the end user exemption, it will not be exempt from all swap-related requirements of the Dodd-Frank Act, and counterparties that are swap dealers or major swap participants may seek to pass along the increased cost and margin requirements through higher prices and reductions in unsecured credit limits. The occurrence of these events could have an adverse effect on IDACORP's and Idaho Power's results of operations, financial condition, and cash flows.

Capital expenditures for power generation and delivery infrastructure and replacement of that infrastructure can significantly affect liquidity. Idaho Power’s business is capital intensive and requires significant investments in energy generation and other infrastructure projects. Long-term 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. For instance, Idaho Power is currently constructing the Langley Gulch power plant and is in the permitting process for two substantial 500-kV transmission line projects. 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, system outages, price increases in commodities (such as steel and copper), and denial by regulatory bodies of recovery through rates of costs incurred. Idaho Power may not be successful in limiting capital expenditures to planned amounts, particularly in the event of escalating costs for materials and labor. If Idaho Power does not receive timely regulatory recovery of costs associated with those expansion and reinforcement activities, Idaho Power will have to rely more heavily on external debt or equity financing for its future capital expenditures. These large capital expenditures may weaken the consolidated financial profile of IDACORP and Idaho Power. Additionally, a significant portion of Idaho Power’s facilities were constructed many years ago, which could affect reliability, increase repair and maintenance expenses, and increase reliance on market purchases of power.

The performance of pension and postretirement benefit plan investments and other factors impacting plan costs could adversely affect cash flows and liquidity. Idaho Power 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 plans' assets and, therefore, adverse investment performance for these assets could increase Idaho Power’s funding requirements related to the plans. The key actuarial assumptions that affect funding obligations are the expected long-term return on plan assets and the discount rate used in determining future benefit obligations. Idaho Power evaluates the actuarial assumptions on an annual basis, taking into account changes in market conditions, trends, and future expectations. Estimates of future equity and debt market performance, changes in interest rates, and other factors Idaho Power and its actuary firms use 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 Idaho Power's funding requirements for the pension and other postretirement benefit plans. Future pension funding requirements, and the timing of funding payments, may also be subject to changes in legislation. Depending on the timing of contributions to the plans and the availability of recovery of costs through rates, cash contributions to the plans could reduce the cash available for operating activities. For additional information regarding Idaho Power's funding obligations under its benefit plans, see Note 11 - "Benefit Plans" to the consolidated financial statements included in this report.

Idaho Power’s business is subject to substantial governmental regulation, including environmental laws and mandatory reliability standards, which could increase costs. Idaho Power is subject to an extensive body of 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.

As an owner and operator of a bulk power transmission system, Idaho Power is subject to mandatory reliability standards issued by the North American Electric Reliability Corporation and enforced by the Federal Energy Regulatory Commission. The standards are based on the functions that need to be performed to ensure the bulk power system operates reliably and are guided by reliability and market interface principles. Compliance with reliability standards subjects Idaho Power to higher operating costs and increased capital expenditures. Further, Idaho Power has received notice of violations from, and self-reported reliability standard compliance issues to, the Federal Energy Regulatory Commission, the North American Electric Reliability Corporation, and the Western Electricity Coordinating Council, and has several matters pending. 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 could have an adverse impact on its and IDACORP’s results of operations, financial condition, and cash flows.

Idaho Power is also 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 and carries with it the risk of penalties and fines. These laws and regulations generally require Idaho Power to obtain and comply with a wide variety of environmental licenses, permits, inspections, and other approvals, and may be enforced by both public officials and private individuals. Idaho Power cannot predict the outcome or effect of any action or litigation that may arise from applicable environmental regulations. In addition, Idaho Power cannot predict with certainty the amount or timing of future expenditures related to environmental matters because of the difficulty of estimating clean up costs or mitigation measures. There is also uncertainty in quantifying liabilities under environmental laws that impose joint and several liability on all potentially responsible parties. Environmental regulations may also require Idaho Power to install pollution control equipment at, or perform environmental remediation on, its or its co-owned facilities, often at a substantial cost.

Emissions of nitrogen and sulfur oxides, mercury, and particulates from fossil fueled generating plants are potentially subject to increased regulations, controls, and mitigation expenses. Certain federal legislators, environmental advocacy groups, and regulatory agencies in the United States have also been focusing considerable attention on CO₂ and other emissions from power generation facilities and their potential role in climate change and/or regional air quality compliance. Existing environmental regulations regarding air emissions (such as NOx, SO₂, or mercury emissions), water quality, and other toxic pollutants may be revised or new climate change laws or regulations may be adopted or become applicable to Idaho Power. Moreover, there are many legislative and rulemaking initiatives pending at the federal and state level that are aimed at the reduction of fossil fuel plant emissions. Idaho Power cannot predict the outcome of pending or future legislative and rulemaking proposals. Future changes in environmental laws or regulations governing emissions reduction could make certain electric generating units (especially coal-fired units) uneconomical and subject to shut-down, could require the adoption of new methodologies or technologies that significantly increase costs or delay in-service dates, and may raise uncertainty about the future viability of fossil fuels as an energy source for new and existing electric generation facilities. Modification of existing environmental regulations or adoption of new environmental regulations may result in increased capital expenditures and could increase the cost of operating Idaho Power's generating plants or make them uneconomical to operate and result in reduced earnings and cash flows.

Furthermore, Idaho Power may not be able to obtain or maintain all environmental regulatory approvals necessary for operation of its facilities and execution of its long-term strategy, including construction of new transmission and distribution infrastructure. If there is a delay in obtaining any required environmental regulatory approval or if Idaho Power fails to obtain, maintain, or comply with any such approval, construction and/or operation of Idaho Power's owned or co-owned generation and/or transmission facilities could be delayed, halted, or subjected to additional costs.

Complying with state or federal renewable portfolio standards could increase capital expenditures and operating costs and reduce earnings and cash flows. A number of states have adopted renewable portfolio standards, which require that electricity providers obtain a minimum percentage of their power from renewable energy sources by a specified date. Idaho Power’s operations in Oregon will be required to comply with a ten percent renewable portfolio standard beginning in 2025, and it is possible that other states, including Idaho, could adopt renewable portfolio standards that are applicable to Idaho Power in the future. The cost of purchasing or generating power from renewable energy sources is often greater than fossil fuel and hydroelectric generation sources, and construction of renewable energy facilities involves significant capital expenditures. As a result, new state or federal renewable 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’s generation facilities or transmission lines may require mitigation, affect the location of a project or the ability to construct a project, and increase capital expenditures and operating costs. Relicensing of the Hells Canyon and Swan Falls hydroelectric projects and construction of the Gateway West and Boardman-to-Hemingway transmission lines requires consultation under the Endangered Species Act to determine the effects of these projects on any listed species within the project areas. The listing of species as threatened or endangered, including the relatively recent listing of slickspot peppergrass as a threatened species, will result in an Endangered Species Act consultation for the Gateway West and Boardman-to-Hemingway transmission lines and future transmission projects. Similarly, the presence of sage grouse in the vicinity of the Gateway West and Boardman-to-Hemingway transmission projects has required more extensive, costly, and time consuming evaluation and engineering. These and other requirements of the Endangered Species Act and similar laws may increase costs and reduce earnings and cash flows.

Conditions imposed in connection with hydroelectric license renewals may require large capital expenditures, increase operating costs, reduce hydroelectric generation, and reduce earnings and cash flows. Idaho Power 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. In particular, fish and other marine life recovery plans may require 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 hydroelectric 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’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 predicted with certainty. Idaho Power 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.

IDACORP, Idaho Power, and their subsidiaries are subject to costs and other effects of legal and regulatory proceedings, settlements, investigations, and claims. From time to time in the normal course of business, IDACORP, Idaho Power, and their subsidiaries are subject to various regulatory proceedings, lawsuits, and claims that could result in adverse judgments, settlements, fines, penalties, injunctions, or other relief. These matters are subject to a number of uncertainties, and as a result management is often unable to predict the outcome of a matter. The final resolution of matters in which IDACORP, Idaho Power, or their subsidiaries are involved could require that they incur costs in a range of amounts that could have an adverse effect on their cash flows and results of operations. Similarly, the terms of resolution could require the companies to change their business practices and procedures, which could also have an adverse effect on their cash flows, financial positions, or results of operations.

IDACORP, IDACORP Energy, and Idaho Power are involved in a number of proceedings, including proceedings arising from the California energy crisis and the energy shortages, high prices, and blackouts in the western United States during 2000 and 2001, and a refund proceeding affecting sellers of wholesale power in the spot market in the Pacific Northwest. Idaho Power 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 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 violations of the New Source Performance Standards and operating permit requirements under the Clean Air Act as a result of prior modifications made to the plant. Private parties have also brought tort actions against companies relating to their alleged contribution to climate change, including claims relating to the Jim Bridger and Boardman power plants. If IDACORP, Idaho Power, or their subsidiaries 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 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 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. Consequently, IDACORP’s ability to pay dividends and to service its debt is dependent upon dividends and other payments received from its subsidiaries. IDACORP’s subsidiaries are separate and distinct legal entities and have no obligation to pay any amounts to IDACORP, whether through dividends, loans, or other payments. The ability of IDACORP’s subsidiaries to pay dividends or make distributions to IDACORP depends on several factors, including each subsidiaries’ actual and projected earnings and cash flow, capital requirements and general financial condition, regulatory restrictions, covenants contained in credit facilities to which they are parties, and the prior rights of holders of their existing and future first mortgage bonds and other debt or equity securities. Further, the amount and payment of dividends is at the discretion of the board of directors, which reviews the appropriateness of dividends in light of current and long-term financial position and results of operations, capital requirements, rating agency requirements, contractual and regulatory restrictions, 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. Any of these factors may result in a reduction or cessation of dividends. See Part II, Item 5 - "Market for Registrant's Common Equity, Related Stockholder Matters, and Issuer Purchases of Equity Securities" of this report for a description of restrictions on IDACORP's and Idaho Power's payment of dividends.

A downgrade in IDACORP’s and Idaho Power’s credit ratings could affect the companies’ ability to access capital, increase their cost of borrowing, and require the companies to post collateral with transaction counterparties. Access to capital markets is important to Idaho Power's ability to operate and to complete its capital projects, including its current and planned generation and transmission projects. Credit rating agencies periodically review the corporate credit ratings and long-term ratings of IDACORP and Idaho Power, and these ratings impact access to, and the cost of, borrowing. IDACORP and Idaho Power also have borrowing arrangements that rely on the ability of the banks to fund loans or support commercial paper, a principal source of short-term financing. Downgrades of IDACORP’s or Idaho Power’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 additional performance assurance collateral with transaction counterparties.

Volatility in the financial markets, or denial of regulatory authority to issue debt or equity securities, may negatively affect IDACORP’s and Idaho Power’s ability to access capital and/or increase their cost of borrowing, or result in losses on investments. IDACORP and Idaho Power 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’s and Idaho Power’s credit facilities may default on their obligations to make loans under, or withdraw from, the credit facilities, or IDACORP’s and Idaho Power’s access to capital may otherwise be inhibited. In addition, at times Idaho Power has a relatively large balance of short-term investments. 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 affect Idaho Power's ability to execute its business plan and adversely affect IDACORP’s and Idaho Power’s earnings, liquidity, and financial condition. Further, Idaho Power is required to obtain regulatory approval in Idaho, Oregon, and Wyoming in order to borrow money or to issue securities and is therefore dependent on the public utility commissions of those states to issue favorable orders in a timely manner to permit them to finance their operations. Notably, without additional approval from those commissions, the aggregate amount of short-term borrowings by Idaho Power at any one time outstanding may not exceed $450 million.

National and regional economic conditions, in conjunction with increased electric rates, may cause increased late payments and uncollectible customer accounts, or reduce energy consumption, which would reduce earnings and cash flows. Beginning in 2008, economic conditions in Idaho Power’s service area have been relatively weak. Unemployment rates are high relative to historic unemployment levels and customer growth has been slow relative to prior years. These factors may reduce the amount of energy Idaho Power’s customers consume; result in a loss of customers; increase the likelihood and prevalence of late payments and uncollectible accounts, and reduce the customer growth rate. A resulting decrease in overall customer usage or collections may reduce revenues and earnings.

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’s or Idaho Power’s financial condition. IDACORP and Idaho Power 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, recent income tax method changes had a significant impact on financial results in 2011. The outcome of ongoing and future income tax proceedings could differ materially from the amounts IDACORP and Idaho Power record prior to conclusion of those proceedings, and the difference could reduce IDACORP’s and Idaho Power’s earnings and cash flows. Further, in some instances the treatment from a ratemaking perspective of any tax benefits could be different than IDACORP or Idaho Power anticipate or request from applicable state regulatory commissions. 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 is subject to workforce factors, including 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’s operations require a skilled workforce to perform specialized, complex utility functions. Idaho Power expects that a significant portion of its skilled workforce will be retiring, at a rate higher than Idaho Power's historical rate, within the next ten years, which places demand on Idaho Power to attract and retain skilled workers. Without a skilled workforce, Idaho Power’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 and skilled workforce could reduce earnings and cash flows.

Acts or threats of terrorism, cyber attacks, security breaches, and other acts of individuals or groups seeking to disrupt Idaho Power's operations, or the businesses of third parties, could result in reduced revenues and increased costs. Idaho Power's generation and transmission facilities are potential targets for terrorist acts and threats, as well as cyber attacks and other disruptive activities of individuals or groups. Some of Idaho Power's facilities are deemed critical infrastructure, in that incapacity or destruction of the facilities could have a debilitating impact on security, reliability or operability of the bulk

electric power system, national economic security, national public health or safety, or any combination of those matters. The possibility that infrastructure facilities, such as generation facilities and electric transmission facilities, would be direct targets of, or indirect casualties of, an act of terror or cyber attack (whether originating internally or externally) may affect Idaho Power's operations by limiting the ability to generate, purchase, or transmit power and by delaying the development and construction of new generating and transmission facilities and capital improvements to existing facilities. These events, and governmental actions in response, could result in a material decrease in revenues and significant additional costs to repair and insure Idaho Power's assets, and could further adversely affect Idaho Power's operations by contributing to disruption of supplies and markets for natural gas or coal used to fuel gas-fired or coal-fired power plants. Because generation and transmission are part of an interconnected system, Idaho Power faces the risk of possible loss of business due to a disruption caused by the impact of an event on the interconnected system. The events could also impair IDACORP's and Idaho Power's ability to raise capital by contributing to financial instability and lower economic activity. Further, the implementation of security guidelines and measures has resulted in and is expected to continue to result in increased compliance costs.

In the normal course of business, Idaho Power 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. Idaho Power operates in a highly regulated industry that requires the continued operation of sophisticated information technology systems and network infrastructure. Despite the security measures in place, Idaho Power's facilities and systems, and those of third-party service providers, could be vulnerable to security breaches, data leakage, or other similar events that could interrupt operations, resulting in a shutdown of service and exposing Idaho Power to liability. Those breaches and events may result from acts of Idaho Power employees, contractors, or third parties. If Idaho Power's technology systems were to fail or be breached and Idaho Power were unable to recover the systems and/or data in a timely manner, Idaho Power may be unable to fulfill critical business functions. Also, confidential and proprietary business, employee, or customer information could be compromised, exposing Idaho Power to liability and causing business disruptions, which could have a material adverse effect on Idaho Power's operations and IDACORP's and Idaho Power's financial results. The implementation of security guidelines and measures and maintenance of insurance, to the extent available, addressing such activities could increase costs and impact financial results. In addition, these types of events could require significant management attention and resources, and could adversely affect IDACORP's and Idaho Power's reputation among customers and the public.

ITEM 1B. UNRESOLVED STAFF COMMENTS

None.

ITEM 2. PROPERTIES

Idaho Power’s system is comprised of 17 hydroelectric generating plants located in southern Idaho and eastern Oregon, two natural gas-fired plants located in southern Idaho, and interests in three coal-fired steam electric generating plants located in Wyoming, Nevada, and Oregon. Idaho Power is also constructing a natural gas-fired combined cycle power plant in Idaho with a summer nameplate capacity of 300 MW, expected to be ready for commercial operation by July 1, 2012. As of December 31, 2011, the system also includes approximately 4,828 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 26,714 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.



Project	Nameplate Capacity (kW)	License 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⁾⁽³⁾	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.
⁽³⁾ Pursuant to an Oregon Environmental Quality Commission plan and associated rules, the Boardman power plant is scheduled for cessation of coal-fired operations on December 31, 2020.

Relicensing of Idaho Power’s hydroelectric projects is discussed in Part II, Item 7 - “MD&A – Regulatory Matters – Relicensing of Hydroelectric Projects.”

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

Refer to Note 10 – “Contingencies” to IDACORP’s and Idaho Power’s consolidated financial statements included in this report.

ITEM 4. MINE SAFETY DISCLOSURES

Information concerning mine safety violations or other regulatory matters required by Section 1503(a) of the Dodd-Frank Wall Street Reform and Consumer Protection Act and Item 104 of Regulation S-K (17 CFR 229.104) is included in Exhibit 95.1 of this report.

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, 2012, there were 12,508 holders of record of IDACORP common stock and the closing stock price was $41.85 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, contractual and regulatory restrictions, 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. At its November 2011 meeting, the IDACORP board of directors adopted a dividend policy for IDACORP that provides for a target long-term dividend payout ratio of between 50 and 60 percent of sustainable IDACORP earnings, with the flexibility to achieve that payout ratio over time and to adjust the payout ratio or to deviate from the target payout ratio from time to time based on the various factors that drive the board of director's dividend decisions. Notwithstanding the dividend policy adopted by the IDACORP board of directors, the dividends IDACORP pays remain in the discretion of the board of directors who, when evaluating the dividend amount, will take into account the foregoing factors, among others.

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, 2011, the leverage ratios for IDACORP and Idaho Power were 48 percent and 49 percent, respectively. Based on these restrictions, IDACORP’s and Idaho Power’s dividends were limited to $827 million and $723 million, respectively, at December 31, 2011. 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.

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 $60 million, $58 million, and $57 million in 2011, 2010, and 2009, respectively.

On January 19, 2012, IDACORP's board of directors voted to increase the quarterly dividend payable February 29, 2012 to

$0.33 per share of IDACORP common stock, from the prior dividend amount of $0.30 per share of IDACORP common stock. For additional information relating to IDACORP and Idaho Power dividends, including restrictions on IDACORP's and Idaho Power's payment of dividends, see Note 6 - “Common Stock” to the consolidated financial statements included in this report.

The following table shows the reported high and low sales price of IDACORP’s common stock and dividends paid for 2011 and 2010 as reported by the NYSE.



	2011						2010
Quarter	High		Low		Dividends paid per share		High		Low		Dividends paid per share
1st	$	38.72	$	36.14	$	0.30	$	35.69	$	29.98	$	0.30
2nd	40.38		37.65		0.30		36.93		31.22		0.30
3rd	40.71		33.88		0.30		36.98		32.46		0.30
4th	42.66		37.26		0.30		37.76		35.46		0.30

IDACORP, Inc. did not repurchase any shares of its common stock during the fourth quarter of 2011.

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, 2006, with beginning-of-period weighting of the peer group indices (based on market capitalization) and monthly compounding of returns.

Source: Bloomberg and EEI



	2006		2007		2008		2009		2010		2011
IDACORP	$	100.00	$	94.40	$	82.12	$	93.25	$	111.75	$	132.15
S&P 500	100.00		105.49		66.47		84.06		96.75		98.77
EEI Electric Utilities Index	100.00		116.56		86.37		95.62		102.34		122.80

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)
	2011			2010			2009			2008			2007
Operating revenues	$	1,026,756		$	1,036,029		$	1,049,800		$	960,414		$	879,394
Operating income	164,248			198,670			203,583			190,667			152,078
Net income attributable to IDACORP, Inc.	166,693			142,798			124,350			98,414			82,272
Diluted earnings per share from
continuing operations	3.36			2.95			2.64			2.17			1.86
Dividends declared per share	1.20			1.20			1.20			1.20			1.20

Financial Condition:
Total assets	$	4,960,609		$	4,676,055		$	4,238,727		$	4,022,845		$	3,653,308
Long-term debt (including current portion)	1,488,614			1,610,859			1,419,070			1,269,979			1,168,336

Financial Statistics:
Times interest charges earned:
Before tax ⁽¹⁾	2.35			2.65			2.88			2.47			2.35
After tax ⁽²⁾	2.97			2.66			2.59			2.23			2.16
Book value per share ⁽³⁾	$	33.18		$	31.01		$	29.17		$	27.76		$	26.79
Market-to-book ratio ⁽⁴⁾	128		%	119		%	110		%	106		%	131		%
Payout ratio⁽⁵⁾	36		%	41		%	45		%	55		%	65		%
Return on year-end common equity ⁽⁶⁾	10.1		%	9.3		%	8.9		%	7.6		%	6.8		%

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 credits, 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 footnote (3) above.
⁽⁵⁾Dividends paid per common share divided by diluted earnings per share.
⁽⁶⁾Net income attributable to IDACORP, Inc. divided by total equity, excluding non-controlling interests, at the end of the year.

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

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," "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 the results discussed in the statements. In addition to any assumptions and other factors and matters referred to specifically in connection with such forward-looking statements, factors that could cause actual results or outcomes to differ materially from those contained in forward-looking statements include those factors set forth in Item 1A - "Risk Factors" of this report and the following important factors:


•	the effect of regulatory decisions by the Idaho Public Utilities Commission, the Oregon Public Utility Commission, the Federal Energy Regulatory Commission, and other regulators affecting Idaho Power's ability to recover costs and/or earn a reasonable rate of return;


•	variable hydrological conditions and over-appropriation of surface and groundwater in the Snake River basin, which can impact stream flows and the amount of generation from Idaho Power's hydroelectric facilities;


•	the cost and availability of materials, fuel, and commodities, and their impact on Idaho Power's infrastructure costs, power costs, and ability to meet required loads, and their impact on the wholesale energy market in the western United States;

•

costs and delays associated with construction and maintenance of power generation, transmission, and distribution facilities, including the inability to obtain required governmental permits and approvals, hydroelectric plant licenses under reasonable terms (and the costs resulting from conditions in such licenses), rights-of-way, and siting, and risks related to contracting, construction, and start-up;


•	disruptions or outages of Idaho Power's generation or transmission systems or the western interconnected transmission system affecting Idaho Power's ability to deliver power to its customers and requiring the dispatch of more expensive generation resources or purchasing power, which may ultimately increase costs;


•	increased costs associated with the legislatively mandated purchase of intermittent power, such as wind, at above-market rates, and the costs and other challenges of integrating intermittent power sources into Idaho Power's resource portfolio;


•	population growth and changes in residential, commercial, and industrial growth and demographic patterns within Idaho Power's service area, the loss or change in the business of significant customers, and the associated impact on loads and load growth;


•	the continuing effects of the weak economy in Idaho Power's service territory and elsewhere, including decreased demand for electricity, reducing revenue from sales of excess energy during periods of low wholesale market prices, impaired financial soundness of vendors and service providers, and elevated levels of uncollectible customer accounts;


•	changes in and costs of compliance with laws, regulations, and policies relating to the environment, natural resources, and endangered species and the adoption of laws and regulations addressing greenhouse gas emissions, global climate change, and energy policies intended to mitigate carbon dioxide, mercury, and other emissions;


•	global climate change and regional or national weather variations, which affect customer demand and hydroelectric generation and can impact the ability and cost to procure adequate supplies of natural gas, coal, or purchased power to serve customers;

•

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


•	transaction risks, including increases in costs, associated with Idaho Power's energy commodity and other derivative instruments, the failure of Idaho Power's energy risk management policies to work as intended, exposure to counterparty credit risk, and potential higher costs of hedging activities due to new regulations pertaining to swaps and derivatives;


•	wholesale market conditions, including availability of power on the spot market and the ability to enter into commodity financial hedges with creditworthy counterparties, and the cost of those hedges, which may affect the prices Idaho Power must pay for power as well as the prices at which Idaho Power can sell any excess power;

•

deteriorating values in the equity markets, changes in interest rates and credit spreads, reductions in demand for investment-grade commercial paper, inflation, and other financial market conditions, as well as changes in government regulations, which affect, among other things, the cost of capital and the ability to access the capital markets, indebtedness obligations, and the amount and timing of required contributions to benefit plans;

•

failure of Idaho Power to comply with state and federal laws, policies, and regulations, including new interpretations and enforcement initiatives by regulatory and oversight bodies, including, but not limited to, the Federal Energy Regulatory Commission, the North American Electric Reliability Corporation, the Western Electricity Coordinating Council, the U.S. Environmental Protection Agency, and Idaho and Oregon state regulatory commissions, which may result in penalties, increase the cost of compliance, the nature and extent of investigations and audits, and costs of remediation;


•	the cost and outcome of litigation, dispute resolution, and regulatory proceedings, and penalties, settlements, or awards that influence the companies' business and operations;


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


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

•

whether the companies will be able to continue to pay dividends under the terms of their respective financing and credit agreements and regulatory limitations, and whether the companies' boards of directors will continue to declare common stock dividends based on the boards of directors’ periodic consideration of factors ordinarily affecting dividend policy, such as current and prospective financial condition, earnings and liquidity, prospective business conditions, regulatory factors, and restrictions in applicable agreements;


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


•	employee workforce factors, including unionization or the attempt to unionize all or part of the companies' workforce, and the ability to adjust the labor cost structure to changes in growth within Idaho Power's service territory;


•	the failure of information systems or the failure to secure information system data, security breaches, or the direct or indirect effect on the companies' business resulting from the occurrence of cyber attacks, terrorist incidents or the threat of terrorist incidents, and acts of war;


•	adoption of or changes in accounting policies, principles, or estimates, including the potential adoption of all or a portion of International Financial Accounting Standards; and


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

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

INTRODUCTION

In Management’s Discussion and Analysis of Financial Condition and Results of Operations (MD&A), the general financial condition and results of operations for IDACORP, Inc. and its subsidiaries (collectively, IDACORP) and Idaho Power Company and its subsidiary (collectively, Idaho Power) are discussed. While reading the MD&A, please refer to the accompanying consolidated financial statements of IDACORP and 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 496,000 general business customers as of December 31, 2011. As a regulated utility, many of Idaho Power's fundamental business decisions are subject to the approval of governmental agencies. 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), which determine the rates that Idaho Power charges to its general business customers. 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 Federal Energy Regulatory Commission (FERC) tariff and to provide transmission services under its FERC open access transmission tariff (OATT). Idaho Power uses general rate cases, cost adjustment mechanisms, and subject-specific filings to recover its costs of providing service and the costs of its energy efficiency and demand-side resources programs, and to seek to earn a return on investment.

Idaho Power generates revenues and cash flows primarily from the sale and distribution of electricity to customers in its Idaho and Oregon service territories, as well as from the wholesale sale and transmission of electricity. Idaho Power’s revenues and income from operations are subject to fluctuations during the year due to the impacts of seasonal weather conditions on demand for electricity, availability of water for hydroelectric generation, price changes, customer usage patterns (which are affected in large part by the condition of the local economy), and the availability and price of purchased power and fuel. Idaho Power is a dual peaking utility that typically experiences its highest retail energy sales during the summer irrigation and cooling season, with a lower peak in the winter that generally results from heating demand. IDACORP’s and Idaho Power’s financial condition is also affected by regulatory decisions, through which Idaho Power seeks to recover its costs 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 of 1978 (PURPA); and IDACORP Energy, a marketer of energy commodities, which wound down operations in 2003. 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.

EXECUTIVE OVERVIEW

Overview of 2011 Financial Results

IDACORP's earnings were $3.36 per diluted share for the year ended December 31, 2011 compared to $2.95 and $2.64 per diluted share in 2010 and 2009, respectively. IDACORP's earnings in 2011 were impacted by the approval of a tax method change that allowed Idaho Power to recognize during 2011 $56.9 million in tax benefits relating to tax years 2009 and prior. This tax benefit, combined with the results of ongoing operations, triggered sharing mechanisms in Idaho that reduced operating income by $47.4 million, reflecting earnings to be shared with Idaho customers to reduce rates. In addition, 2011 results include the full-year impact of base rate increases implemented in 2010, higher electricity sales volumes, and lower PCA rates.

2011 Accomplishments and 2012 Challenges and Areas of Emphasis


•	execution of Idaho Power's purposeful regulatory strategy, which resulted in settlement of Idaho Power's 2011 Idaho general rate case with the IPUC (including a base rate increase effective January 1, 2012), a June 1, 2011 base rate

increase for recovery of the Idaho-allocated portion of Idaho Power's cash contributions to its defined benefit pension plan, and several other positive regulatory decisions;


•	execution of a settlement agreement with the IPUC extending through 2014 Idaho Power's ability to amortize additional accumulated deferred investment tax credits (ADITC) to help achieve a minimum annual return on year-end equity in the Idaho jurisdiction (Idaho ROE) of 9.5 percent;


•	significant progress toward cost-sharing agreements with other parties for the permitting of the Boardman-to-Hemingway and Gateway West 500-kV transmission projects, which were ultimately executed in January 2012;


•	completion of deployment of smart meters to substantially all customers;


•	continued progress on the construction of the Langley Gulch power plant;


•	approval by the U.S. Congress Joint Committee on Taxation (Joint Committee) of a tax method change for uniform capitalization, resulting in a significant increase in net income relative to 2010; and


•	ranking in the top quartile of the 120 largest utilities in the country for customer satisfaction in the J.D. Power and Associates 2011 Electric Utility Residential Customer Satisfaction Study.

During 2012, IDACORP's and Idaho Power's management will continue to focus on and implement the companies' three-part strategy. Notable matters that the companies expect will require management's focus and attention in 2012 include:


•	completion of construction and commencement of commercial operations of the Langley Gulch power plant, and timely and adequate rate recovery of costs for the plant;


•	continued efforts toward permitting of the Boardman-to-Hemingway and Gateway West transmission projects;


•	seeking a positive outcome in proceedings at the IPUC relating to the pricing models and other terms of PURPA power purchase agreements;


•	seeking methods for the integration of intermittent power sources and anticipated increases in intermittent wind generation, which Idaho Power believes could have an adverse impact on system reliability and functionality and on customer rates;


•	obtaining IPUC authorization to include Idaho Power's FCA as a permanent component of rates;


•	implementation of a new customer and billing system; and


•	continued work toward resolution of issues relating to relicensing of Idaho Power's hydroelectric projects, including the Hells Canyon Complex.

Overview of General Factors and Trends Affecting Results of Operations and Financial Condition

IDACORP's and Idaho Power's results of operations and financial condition are affected by regulatory, economic, and other factors, many of which are described below.

Emphasis on Regulatory Cost Recovery: The prices that Idaho Power is authorized to charge for its electric service is a major factor in determining IDACORP's and Idaho Power's results of operations and financial condition. Because of the significant impact of ratemaking decisions on Idaho Power's business and financial condition, the company continues to focus on timely recovery of its costs through filings with the company's regulators. Effective implementation of Idaho Power's purposeful regulatory strategy is particularly important in an economic climate that puts pressure on regulators to limit rate increases or otherwise take actions to limit the potential adverse impact of rates on customers. Regulatory developments that IDACORP and Idaho Power expect to have an impact on their future results, each of which is discussed in more detail under "Regulatory Matters" in this MD&A or in Note 3 - "Regulatory Matters" to the consolidated financial statements included in this report, include the following:

•

Idaho 2011 General Rate Case and Settlement - On December 30, 2011, the IPUC approved a settlement stipulation resolving most of the issues in the general rate case. The settlement stipulation provides for a 7.86 percent authorized rate of return on an Idaho-jurisdictional rate base of approximately $2.36 billion. The settlement stipulation results in a $34 million, or 4.07 percent average, increase in Idaho Power's annual Idaho-jurisdictional base rate revenues, effective January 1, 2012.

•

Extension of Certain Provisions of the January 2010 Settlement Agreement - On January 13, 2010, the IPUC approved a settlement agreement among Idaho Power, several of Idaho Power’s customers, the IPUC Staff, and others, in connection with a general rate case. The settlement agreement included, among other items: (a) a provision to share with Idaho customers 50 percent of any Idaho-jurisdiction earnings in excess of a 10.5 percent Idaho ROE in any calendar year from 2009 to 2011; and (b) a provision to allow the additional amortization of ADITC if Idaho Power's actual Idaho ROE was below 9.5 percent in any calendar year from 2009 to 2011. The sharing and amortization provisions of the January 2010 settlement agreement expired on December 31, 2011. On December 27, 2011, the

IPUC issued an order approving a settlement stipulation providing for an extension through 2014, with modifications, of those two provisions of the January 2010 settlement agreement. The extension provides for up to $45 million of additional amortization of ADITC through 2014, with certain annual limits, and additional sharing of annual earnings in excess of specified Idaho ROEs. In consideration for the extension, the settlement stipulation provided that Idaho Power would allocate to customers (as a reduction to Idaho Power's pension regulatory asset) 75 percent of Idaho Power's share of 2011 Idaho-jurisdictional earnings over a 10.5 percent Idaho ROE. After the combined effect of the 50 percent sharing mechanism in the January 2010 settlement agreement and the December 2011 settlement order that provided for additional sharing, Idaho Power retained 12.5 percent of Idaho-jurisdiction earnings exceeding a 10.5 percent Idaho ROE.

•

Idaho PCA Orders - In both its Idaho and Oregon jurisdictions, Idaho Power has power cost adjustment (PCA) mechanisms that address the volatility of power supply costs and provide for annual adjustments to the rates charged to retail customers. The Idaho PCA mechanism compares Idaho Power's actual net power supply costs to net power supply costs currently being recovered in retail rates, with most of the variance between these two amounts deferred for future recovery from, or refund to, customers. On May 31, 2011, the IPUC approved a $40.4 million PCA decrease, effective June 1, 2011. This followed a May 28, 2010 IPUC order approving a $146.9 million PCA decrease, effective June 1, 2010. These PCA rate decreases were offset by increases in power supply costs in base rates and deferrals and amortization under the PCA mechanism, resulting in a relatively small impact on earnings.

•

Idaho FCA Mechanism - The FCA 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. The FCA began as a pilot program in 2007 and expired on December 31, 2011. On October 19, 2011, Idaho Power filed an application with the IPUC requesting that the FCA pilot program become permanent. As of the date of this report, a determination and order from the IPUC as to the future of the FCA is pending.

•

Oregon 2011 General Rate Case - On July 29, 2011, Idaho Power filed a general rate case for its Oregon jurisdiction with the OPUC, requesting a $5.8 million increase in annual Oregon jurisdictional revenues. On February 1, 2012, Idaho Power, the OPUC Staff, and other interested parties executed and filed a partial settlement stipulation with the OPUC that provides for a return on equity of 9.9 percent and an overall rate of return of 7.757 percent. If the OPUC approves the stipulation, Idaho Power expects that new rates will become effective on March 1, 2012.

Economic Conditions and Customer Growth: Since 2008, economic conditions in Idaho Power's service territory have been relatively weak. Unemployment rates remain high compared to historical levels. After peaking at 10.0 percent in early 2011, the service area unemployment rate has fallen to 8.4 percent in December 2011, according to the Idaho Department of Labor. From 2001 through September 2008, the highest monthly unemployment rate in the service territory was 5.2 percent. The customer growth rate, while still positive, has been low relative to prior years. During 2011, the customer growth rate in Idaho Power's service territory was 0.7 percent. By comparison, for the 20-year period ending 2010 the average annual customer growth rate in Idaho Power's service territory was 2.7 percent. Economic conditions can impact consumer demand for electricity, collectability of accounts, the volume of off-system sales, and Idaho Power's need for purchased power. Management cannot predict the timing of, and pace at which, economic recovery may occur in Idaho Power's service territory. Idaho Power continues to manage costs while executing its three-part strategy of responsible planning, responsible development and protection of resources, and responsible energy use.

Weather Conditions and Associated Impacts: Weather conditions normally have a significant impact on energy sales and the seasonality of those sales. Relatively low and high temperatures result in greater energy usage for heating and cooling, respectively. During the agricultural growing season, which in large part occurs during the second and third quarters of each calendar year, irrigation customers use electricity to operate irrigation pumps. A 1.6 percent increase in energy usage by Idaho Power customers during 2011 compared to 2010 is largely attributable to below average temperatures in the winter months offset by above average precipitation in the springtime, resulting in increased heating unit load and lower use of irrigation pumps.

Idaho Power's hydroelectric facilities comprise approximately one-half of Idaho Power's nameplate generation capacity. The actual 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, base flows in the Snake River, spring flows, rainfall, water leases and other water rights, and other weather and stream flow considerations. At the date of this report, Idaho Power expects hydroelectric generation during 2012 in the range of 7.5 to 9.5 million MWh, based on reservoir storage levels and forecasted weather conditions as of February 12, 2012, compared to 10.9 million MWh in 2011 and 7.3 million MWh in 2010.

Median annual hydroelectric generation is 8.6 million MWh. Due largely to favorable hydroelectric generation conditions, hydroelectric generation comprised 69 percent of Idaho Power's total system generation during 2011 and 51 percent during 2010. Where favorable hydroelectric generating conditions exist for Idaho Power, they also may be abundant for other Pacific Northwest hydroelectric facility operators, thus increasing the available supply of lower-cost power and depressing regional wholesale market prices, which impacts the revenue Idaho Power receives from off-system sales of its excess power. Average wholesale power prices per MWh for sales for resale were down 29 percent in 2011 relative to 2010.

Fuel and Purchased Power Expense: In addition to hydroelectric generation and power it purchases in the wholesale markets, Idaho Power relies significantly on coal and natural gas to fuel its generation facilities. Fuel costs are impacted by electricity sales volumes, the terms of contracts for fuel, Idaho Power's power generation capacity, the rate of expansion of alternative energy generation sources such as wind energy, the availability of hydroelectric generation resources, transmission capacity, energy market prices, and Idaho Power's hedging program for managing fuel costs.

For the year 2011, Idaho Power's weighted average fuel-related cost per MWh for its fossil fuel generation resources increased 17 percent relative to 2010, mainly due to the effect of lower generation output, which spreads fixed costs over lower output, and coal price increases. Notwithstanding the increase in fuel cost per MWh generated, total fuel expense decreased 18 percent relative to 2010, due to a decrease in output from fuel-fired power generating plants resulting from both the abundant hydroelectric generation and increased wind power obtained through mandated power purchases pursuant to PURPA. Looking ahead, operation of the Langley Gulch power plant that Idaho Power is currently constructing will increase Idaho Power's use of natural gas, and thus its exposure to volatility in natural gas prices.

Purchased power costs are impacted by the terms of contracts for purchased power, the rate of expansion of alternative energy generation sources such as wind energy, and wholesale energy market prices. Idaho Power is generally obligated to purchase power from PURPA generation projects at a specified price regardless of the then-current load demand or wholesale energy market prices. This increases the likelihood that Idaho Power will be required to reduce output from its lower-cost hydroelectric and fossil fuel-fired generation resources and may be required to sell in the wholesale power market the power it purchases from PURPA projects at a significant loss. Integration of intermittent, non-dispatchable resources into Idaho Power's portfolio also creates a number of operational risks, which Idaho Power is working to address.

The Idaho and Oregon PCA mechanisms mitigate in large part the potential adverse impacts of fluctuations in Idaho Power's power supply costs. Idaho Power also uses physical and financial forward contracts for both electricity and fuel in order to manage the risks relating to fuel and power price exposures.

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 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 or regulations may be substantial. Accordingly, Idaho Power has in place numerous compliance policies and initiatives, and frequently evaluates, updates, and supplements those policies and initiatives. In particular, 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 a cessation of coal-fired operations in 2020, and in September 2010 the U.S. Environmental Protection Agency (EPA) issued a Notice of Violation relating to the Boardman plant, alleging Clean Air Act (CAA) violations. As legislation and regulations concerning greenhouse gas emissions develop, Idaho Power will assess the potential impact on the costs to operate its power generation facilities, as well as the willingness or ability of power plant participants to fund any required pollution control equipment upgrades.

Other Notable Matters and Areas of Focus

Pension Plans: In 2010, Idaho Power contributed $60 million to its defined benefit pension plan, and in 2011 Idaho Power contributed an additional $18.5 million to the plan. On May 19, 2011, the IPUC authorized Idaho Power to increase its annual recovery and amortization of deferred pension costs from $5.4 million to $17.1 million. Idaho Power expects to make additional significant cash contributions to its defined benefit pension plan through at least 2016.

Water Management and Relicensing of Hydroelectric Projects: Because of Idaho Power's reliance on streamflow in the Snake River and its tributaries, Idaho Power participates in numerous proceedings and venues that may affect its water rights, seeking to preserve the long-term availability of its rights for use at its hydroelectric projects. Also, 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's relicensing costs have been and will continue to be substantial.

Transmission Projects: Idaho Power continues to focus on expansion of its transmission system in an effort to improve system reliability and resource adequacy through the proposed Boardman-to-Hemingway and Gateway West transmission projects. Construction of these projects cannot commence until all federal, state, and local regulatory requirements are met. In January 2012, Idaho Power entered into cost-sharing arrangements with third parties for the permitting phases of both projects. To further mitigate the risks associated with these projects, at least in part, Idaho Power plans to seek regulatory support for cost recovery from the IPUC and OPUC for the projects prior to construction.

2011 Tax-Related Projects: In September 2011, the U.S. Internal Revenue Service (IRS) notified Idaho Power that Idaho Power's uniform capitalization tax method agreement had been approved, resulting in the recognition of $56.9 million of its previously unrecognized tax benefits in 2011.

Summary of 2011 Financial Results

The following is a summary Idaho Power's net income, net income attributable to IDACORP, Inc., and IDACORP's earnings per diluted share for the years ended December 31, 2011, 2010, and 2009 (in thousands, except earnings per share amounts):



	Year Ended December 31,
	2011		2010		2009
Idaho Power net income	$	164,750	$	140,634	$	122,559
Net income attributable to IDACORP, Inc.	$	166,693	$	142,798	$	124,350
Average outstanding shares – diluted (000’s)	49,558		48,340		47,182
IDACORP, Inc. earnings per diluted share	$	3.36	$	2.95	$	2.64

The following table presents a reconciliation of net income attributable to IDACORP, Inc. for 2010 to 2011 (items are in millions and are before tax unless otherwise noted):




Net income attributable to IDACORP, Inc. - December 31, 2010						$	142.8
Change in Idaho Power net income before taxes:
Rate and other regulatory changes, including power cost, pension expense
recovery, and fixed cost adjustment mechanisms			$	26.3
Changes in sales volumes			9.8
Increased transmission service revenues			7.4
Increased other operating and maintenance expenses:
Pension and payroll related expenses (excluding pension impact of
settlement stipulation below)			(17.2		)
Thermal plant expenses			(5.0		)
Other			(2.2		)
Increased depreciation expense			(3.9		)
Increased property taxes			(4.8		)
Other changes in operating income, net			1.1
Increase in Idaho Power operating income prior to sharing mechanisms			11.5
Additional pension expense as a result of settlement stipulation	(20.3	)
Decrease in revenues as a result of sharing mechanism	(27.1	)
Decrease in operating income as a result of sharing mechanisms			(47.4		)
Change in Idaho Power operating income			(35.9		)
Increase in AFUDC			11.6
Other net decreases			(3.7		)
Increases due to tax method changes and related examination settlements			27.8
Change in other income tax benefit			24.3
Total increase in Idaho Power net income						24.1
Other net decreases (net of tax)						(0.2		)
Net income attributable to IDACORP, Inc. - December 31, 2011						$	166.7

Idaho Power net income increased by $24.1 million in 2011 compared to 2010, largely as a result of approval by the U.S. Congress Joint Committee on Taxation of the uniform capitalization method agreement with the IRS, which allowed for recognition in 2011 of $56.9 million of previously unrecognized tax benefits for tax years 2009 and prior. This benefit was partially offset by $47.4 million due to Idaho-jurisdictional sharing mechanisms.

The uniform capitalization method approval contributed to triggering of the sharing mechanism under Idaho Power's January 2010 settlement agreement with the IPUC and other parties. Under this sharing mechanism, Idaho Power recorded a $27.1 million reduction in revenues to be refunded to or to otherwise benefit customers, reflecting the equal sharing of Idaho-jurisdiction earnings in excess of a 10.5 percent Idaho ROE.

Additionally, Idaho Power recorded $20.3 million of additional pension expense as a result of an IPUC order approving a 2011 settlement stipulation that had been executed by Idaho Power, the IPUC Staff, and one large industrial customer of Idaho Power. The settlement stipulation provided that Idaho Power would allocate to customers 75 percent of Idaho Power's share of 2011 Idaho-jurisdictional earnings over a 10.5 percent Idaho ROE. As agreed to with the IPUC, this allocation was used to reduce Idaho Power's pension regulatory asset (reducing a portion of Idaho customers' future obligation), resulting in the corresponding recognition of additional pension expense.

Other items influencing the change in Idaho Power's operating income and annual earnings as compared to 2010 include:

•

Several rate orders went into effect in 2010 and 2011 that impacted current year revenues and had a net positive impact on operating income. A June 1, 2010 base rate increase benefited 2011 with an additional five months of increased base rate revenue. A pension expense recovery rate increase occurred on June 1, 2010 and was further increased on June 1, 2011. Also included in the rate orders were PCA-related customer rate decreases on June 1 of both years. However, concurrent with each PCA rate decrease was a corresponding reduction in PCA expense. These rate changes, combined with lower power supply costs net of PCA mechanisms, improved operating income by approximately $26.3 million for the year.

•

Increased sales volumes improved operating income by $9.8 million. Cooler temperatures early in the year contributed to an $8.0 million increase in electricity demand from residential customers, many of whom rely on electric power for heating systems during the winter months. This increase was partially offset by a $3.3 million decrease in irrigation revenues due to a wetter, cooler spring reducing the need to use irrigation pumps. A 17.7 percent increase in cooling degree days when compared with the prior year, particularly an increase in temperature in the late summer months, drove the remaining increase.


•	Transmission system revenues, a component of other revenues, increased $7.4 million, principally resulting from increases in wheeling services attributable to increases in FERC transmission rates that took effect on October 1, 2010 and 2011, and from other facility rental increases.


•	O&M expenses increased, primarily due to an $11.5 million increase in pension expense associated with the pension recovery rate orders, an increase in payroll-related costs of $5.7 million, and increased maintenance expense of $5.0 million at the thermal plants. These increases were partially offset by lower legal expenses of $2.3 million.


•	Depreciation expense increased $3.9 million for the year due to increased plant in service.


•	Property tax increased $4.8 million in 2011, primarily due to lower residential and commercial values in other property classes shifting tax costs to centrally assessed property.

Prior to the effects of the sharing mechanisms described above, Idaho Power operating income increased $11.5 million compared to 2010. After the effects of the sharing mechanism, operating income decreased $35.9 million compared to 2010. Also contributing to increased earnings at Idaho Power were increases of $11.6 million in AFUDC, which represents the cost of financing construction projects with borrowed funds and equity funds.

Key Operating and Financial Metrics

IDACORP’s and Idaho Power’s outlook for 2012 full year metrics is as follows:



	2012 Estimate	2011 Actual
Idaho Power Operating & Maintenance Expense (millions)	$325-$335	$339
Idaho Power Capital Expenditures, excluding AFUDC (millions)	$230-$240	$338
Idaho Power Hydroelectric Generation (million MWh)	7.5-9.5	10.9
Non-regulated subsidiary earnings and holding company expenses (millions)	$0.0-$3.0	$1.9

The 2012 range for capital expenditures includes the completion of 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, net of ongoing payments from third parties participating as joint funders in the permitting project for future expenditures.

The estimated hydroelectric generation range is based on reservoir storage levels and forecasted weather conditions as of February 12, 2012.

RESULTS OF OPERATIONS

This section of the MD&A takes a closer look at the significant factors that affected IDACORP’s and Idaho Power’s earnings during the year ended December 31, 2011. In this analysis, the results for 2011 are compared to 2010 and the results for 2010 are compared to 2009.

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

Utility Operations

The table below presents Idaho Power’s energy sales, in MWh, and supply for the last three years.



	Year Ended December 31,
	2011		2010		2009
General business sales	13,734		13,513		13,948
Off-system sales	3,635		1,982		2,836
Total energy sales	17,369		15,495		16,784
Hydroelectric generation	10,937		7,344		8,096
Coal generation	4,820		6,864		6,941
Natural gas and other generation	138		160		242
Total system generation	15,895		14,368		15,279
Purchased power	2,751		2,401		2,912
Line losses	(1,277	)	(1,274	)	(1,407	)
Total energy supply	17,369		15,495		16,784

For the year 2011, general business sales increased by 0.2 million MWh, mostly related to increased residential customer usage over the prior year. Off-system sales increased by 1.7 million MWh in 2011 as increases in output from hydroelectric and PURPA resources increased surplus power available for sale. Due largely to favorable hydroelectric generating conditions, hydroelectric generation comprised 69 percent of Idaho Power’s total system generation during 2011. Hydroelectric generation in 2011 was 127 percent of the annual median generation of 8.6 million MWh, which is based on hydrologic conditions for the period 1928 through 2010 and adjusted to reflect the current level of water resource development. The 0.8 million MWh reduction in hydroelectric generation in 2010 compared to 2009 was primarily due to reduced precipitation during the snow accumulation period.

The increase in hydroelectric generation during 2011 led to a decreased reliance on coal-fired generation, and also contributed to the availability of additional surplus power available for off-system sales. Most of the decrease in power supply costs that typically results from increased hydroelectric generation is returned to customers through the PCA mechanisms.

Idaho Power’s system is dual peaking, with the larger peak demand occurring in the summer. To reduce the magnitude of peak demands, Idaho Power has implemented a demand response program and a number of energy efficiency programs. The 2011 summer peak demand was 2,973 MW, set on July 6, 2011. The record summer peak demand of 3,214 MW was set on June 30, 2008, and the highest winter peak demand of 2,527 MW was set on December 10, 2009. During these and other similar heavy load periods, Idaho Power’s system is fully committed to serve loads and meet required operating reserves. When loads exceed Idaho Power's generation capacity, Idaho Power must rely on power obtained from purchase contracts (some power from which may not be available when required if the source is intermittent power such as wind) and may be required to purchase power in the wholesale energy spot market.

General Business Revenues: The table below presents Idaho Power’s general business revenues, MWh sales, and number of customers for the past three years.



	Year Ended December 31,
	2011			2010			2009
Revenue
Residential	$	405,982		$	400,607		$	409,479
Commercial	220,962			231,440			232,816
Industrial	140,701			138,394			141,530
Irrigation	104,635			110,555			109,655
Total	872,280			880,996			893,480
Provision for sharing	(27,099		)	—			—
Deferred revenues ⁽¹⁾	(10,636		)	(10,625		)	(9,715		)
Total general business revenues	$	834,545		$	870,371		$	883,765
MWh
Residential	5,146			4,967			5,300
Commercial	3,815			3,763			3,858
Industrial	3,100			3,076			3,140
Irrigation	1,673			1,707			1,650
Total	13,734			13,513			13,948
Customers (year end)
Residential	411,487			408,754			406,631
Commercial	65,226			64,647			64,349
Industrial	121			125			129
Irrigation	18,736			18,547			18,818
Total	495,570			492,073			489,927

⁽¹⁾ As part of its February 1, 2009 general rate case order, the IPUC allowed Idaho Power to recover AFUDC for the Hells Canyon Complex relicensing asset even though the relicensing process is not yet complete and the relicensing asset has not been placed in service. Idaho Power expects to collect approximately $10.7 million annually in the Idaho jurisdiction, but will defer revenue recognition of the amounts collected until the license is issued and the asset is placed in service.

Changes in customer demand and changes in rates are the primary causes of fluctuations in general business revenue. The table below presents the most significant rate increases and decreases, shown on an annualized basis, which impacted revenues over the last three years.



		Percentage Rate Increase (Decrease)		Annualized $ Impact (millions)
	Effective Date
Description	Effective Date
2009 Idaho PCA	6/1/2009	10.2	%	84
2009 Idaho AMI	6/1/2009	1.8	%	11
2009 Oregon general rate case settlement	3/1/2010	15.4	%	5
2010 Idaho settlement agreement	6/1/2010	9.9%		89
2010 Idaho PCA	6/1/2010	(16.4%)		(147	)
2010 Idaho pension expense recovery	6/1/2010	0.8%		5
2011 Idaho PCA	6/1/2011	(4.8%)		(40	)
2011 Idaho pension expense recovery	6/1/2011	1.4	%	12

The Idaho general rate case settlement stipulation approved by the IPUC on December 30, 2011, resulted in a 4.2 percent overall, or $34 million annual, increase in Idaho-jurisdictional base rates, effective January 1, 2012. For more information related to the December 2011 settlement stipulation, see “Regulatory Matters” later 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. Boise, Idaho weather impacts for the last three years are included in the table below.



	Year Ended December 31,
	2011	2010	2009	Normal
Heating degree-days⁽¹⁾	5,554	5,078	5,612	5,727
Cooling degree-days ⁽¹⁾	1,076	914	1,188	807
⁽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.

General Business Revenues - 2011 Compared to 2010: General business revenue decreased $35.8 million in 2011 compared to 2010. Most of the decrease is a result of recording a regulatory liability of $27.1 million to be refunded to, or otherwise be used to benefit, customers, reflecting the equal sharing of Idaho-jurisdiction earnings exceeding the authorized return on year-end equity of 10.5 percent, pursuant to a January 2010 Idaho settlement agreement. The offset to this liability was recorded as a reduction to general business revenue during the third and fourth quarters of 2011. The remaining changes in general business revenue, a decrease of $8.7 million for 2011, are primarily attributable to the effects of rate changes and usage. These factors are discussed in more detail below.

• Rates. Rate changes combined to reduce general business revenue by $38.8 million in 2011 compared to 2010. The revenue impact of several of these changes was directly offset by associated changes in operating expenses. For example, Idaho PCA amortization expense was reduced $56.3 million due to decreases in the corresponding Idaho PCA rates. The decrease in PCA rates were partially offset by an increase in base retail rates of $38.5 million for the year.

The $10.5 million decline in revenue from commercial customers in 2011 relative to 2010, notwithstanding an increase in usage, is largely due to the disproportionate impact of the PCA rate reductions that went into effect in 2010 and 2011. Commercial customer rates are typically subject to a greater adjustment when PCA rates increase or decrease.

• Customers. Changes related to a special industrial customer contract, along with small increments in customer count, increased general business revenues by $16.6 million. Customer growth from 2010 to 2011 was 0.7 percent.

• Usage. For 2011, higher usage increased general business revenue $13.5 million compared to 2010. The increase was due primarily to colder first quarter temperatures, which increased power demand for residential heating purposes, as well as a 17.7 percent increase in cooling degree-days during the year, which increased power demand for air conditioning purposes. This increase was partially offset by a 2.3 percent decrease in irrigation usage resulting from the cooler spring weather and the timing and level of precipitation during the second quarter of 2011.

General Business Revenues - 2010 Compared to 2009:

• Rates. Rate increases positively impacted general business revenue by $16.9 million in 2010 as compared to 2009, due to increases in base rates of $73.5 million, partially offset by PCA rate decreases of $56.6 million.

• 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.

• Usage. A decrease in usage reduced general business revenue by $33.4 million. Idaho Power believes the decline in total MWh sales was due primarily to mild temperatures, which decreased 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.

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



	Year Ended December 31,
	2011		2010		2009
Revenue	$	101,602	$	78,133	$	94,373
MWh sold	3,635		1,982		2,836
Revenue per MWh	$	27.95	$	39.42	$	33.28

Off-System Sales - 2011 Compared to 2010: Off-system sales revenue increased by $23.5 million, or 30 percent, in 2011 as compared to 2010. Sales volumes nearly doubled, as increases in output from hydroelectric and PURPA resources increased surplus power available for sale. This increase was partially offset by a 29 percent decrease in average prices due in part to abundant hydroelectric generation in the region.

Off-System Sales - 2010 Compared to 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.

Other Revenues: The table below presents the components of other revenues for the last three years.



	Year Ended December 31,
	2011		2010		2009
Transmission services, facility rental and other	$	48,918	$	40,364	$	36,037
Energy efficiency	37,663		44,184		31,821
Total	$	86,581	$	84,548	$	67,858

Other Revenues - 2011 Compared to 2010: Other revenues increased $2.0 million in 2011 as compared to 2010, due mainly to:


•	an increase of $7.4 million in transmission system revenues, resulting principally from increases in wheeling services attributable to increases in FERC transmission rates that took effect on October 1, 2010 and 2011, and from other facility rental increases; and

•

a decrease in energy efficiency revenues of $6.5 million, due in part to an IPUC order that moved custom efficiency payments to a regulatory asset that will be amortized over time and recovered through general rate cases rather than through the energy efficiency rider. The remaining decrease relates to lower customer incentives paid versus the prior year. Energy efficiency activities are funded through a rider mechanism on customer bills. Energy efficiency program expenditures are reported as an operating expense with an equal amount of revenues recorded in other revenues, resulting in no net impact on earnings. The cumulative variance between expenditures and amounts collected through the rider is recorded as a regulatory asset or liability pending future collection from or obligation to customers. A liability balance indicates that Idaho Power has collected more than it has spent and an asset balance indicates that Idaho Power has spent more than it has collected. As of December 31, 2011, Idaho Power’s energy efficiency rider balance was a regulatory asset of $8.9 million.

Other Revenues - 2010 Compared to 2009: Other revenues increased $16.7 million in 2010 as compared to 2009, due mainly to:


•	an increase of $4.3 million in transmission system 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.

Purchased Power: The table below presents Idaho Power’s purchased power expenses and volumes for the last three years.



	Year Ended December 31,
	2011		2010		2009
Expense
PURPA contracts	$	90,251	$	56,022	$	59,606
Other purchased power (including wheeling)	73,085		87,747		107,592
Total purchased power expense	$	163,336	$	143,769	$	167,198
MWh purchased
PURPA contracts	1,495		910		970
Other purchased power	1,256		1,491		1,942
Total MWh purchased	2,751		2,401		2,912
Cost per MWh from PURPA contracts	$	60.36	$	61.56	$	61.45
Cost per MWh from other sources	$	58.19	$	58.85	$	55.40
Weighted average - all sources	$	59.37	$	59.88	$	57.42

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 anticipated 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.

Purchased Power - 2011 Compared to 2010: Purchased power expense increased $19.6 million, or 14 percent, in 2011 as compared to 2010. This increase was driven by MWh purchased from PURPA contracts, which increased 64 percent due to new PURPA wind generation facilities coming on-line. The increase was partially offset by reduced wholesale market purchases resulted from Idaho Power's above average hydroelectric generation in 2011, and continued reliance on financial hedges to mitigate potential changes in forecasted hydrologic conditions. Wholesale market purchases were also down due to lower system loads resulting from relatively mild weather.

Purchased Power - 2010 Compared to 2009: Purchased power expense decreased $23.4 million in 2010 as 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.

Fuel Expense: Idaho Power’s fuel expenses and generation at its thermal generating plants for the last three years are included in the table below.



	Year Ended December 31,
	2011		2010		2009
Expense
Coal	$	119,845	$	146,927	$	130,234
Natural gas and other	11,697		12,746		19,332
Total fuel expense	$	131,542	$	159,673	$	149,566
MWh generated
Coal	4,820		6,864		6,941
Natural gas and other	138		160		242
Total MWh generated	4,958		7,024		7,183
Cost per MWh
Coal	$	24.86	$	21.41	$	18.76
Natural gas and other	84.76		79.66		79.88
Weighted average, all sources	26.53		22.73		20.82

Most fuel supply contracts are subject to changes in published indexes that are closely related to materials and supplies, labor, and diesel costs. In addition to commodity (variable) costs, both natural gas and coal expense include costs that are more fixed in nature for items such as capacity charges, transportation, and fuel handling. Period to period variances in fuel expense per MWh are noticeably impacted by these fixed charges when generation output is substantially different between the two periods.

Fuel Expense - 2011 Compared to 2010: In 2011, fuel expense decreased $28.1 million, or 18 percent, compared to 2010, due to lower generation at Idaho Power's thermal plants. The output at these plants was down 2.0 million MWh, or 30 percent in 2011 compared to 2010. The reduced dispatch was primarily caused by lower regional power prices due to higher regional hydroelectric and wind generation. The impact of lower thermal generation was partially offset by higher coal prices. During parts of 2010, the Bridger and Valmy generating plants received fuel from prior lower-cost contracts.

Fuel Expense - 2010 Compared to 2009: In 2010, fuel expense increased $10.1 million compared to 2009 due to new higher-priced contracts with Black Butte Coal Company for supplying the Valmy and Jim Bridger plants that took effect in early 2010. 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. 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.

PCA Mechanisms: 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 PCA mechanisms for both the Idaho and Oregon jurisdictions. These mechanisms allow Idaho Power to recover from or refund to customers most 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, or cash that is collected is refunded to customers, resulting in fluctuations in operating cash flows from year to year.

PCA expense represents the effects of the Idaho and Oregon PCA mechanisms. The table below presents the components of the Idaho and Oregon PCA mechanisms for the last three years.



	Year Ended December 31,
	2011		2010			2009
Idaho power supply cost accrual (deferral)	$	27,768	$	(14,324	)	$	(42,533	)
Oregon power supply cost accrual	1,523		—			184
Oregon excess power cost order	—		—			(6,358		)
Amortization of prior year authorized balances	9,206		65,550			115,417
Total power cost adjustment expense	$	38,497	$	51,226		$	66,710

The power supply accruals or deferrals represent the portion of that periods' power supply cost fluctuations accrued or deferred under the PCA mechanisms. If actual power supply costs are greater than the amount forecasted in PCA rates, most of the excess is deferred. Accruals represent additional costs recorded because actual power supply costs were less than the amount forecasted in PCA rates, as was the case for both jurisdictions in 2011. The amortization of the prior year’s balances represents the amounts being collected (refunded) in the current PCA year that were deferred or accrued in the prior PCA year (the true-up component of the PCA).

PCA Mechanisms - 2011 Compared to 2010: Actual net power supply costs decreased in 2011 relative to 2010 while base net power supply costs increased, resulting in a change of $43.6 million—from a deferral of $14.3 million to an accrual of $29.3 million. For 2011, collections on deferred amounts have decreased due to lower PCA true-up rates, reducing the PCA amortization by $56.3 million.

PCA Mechanisms - 2010 Compared to 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 in 2010 as 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 2009 Idaho Power recorded the effect of an order from the OPUC that allows Idaho Power to defer for future recovery $6.4 million of costs incurred in prior years.

Other Operations and Maintenance Expenses: The $44.7 million increase in other O&M expense in 2011 as compared to 2010 was principally due to:


•	$20.3 million of increased pension expenses relating to the settlement stipulation that reduced a portion of Idaho customers' future obligation through a reduction in the pension regulatory asset;


•	increased pension and other benefit expenses of $11.5 million, primarily due to pension expense amortization that began in June 2010 and was increased in June 2011 in conjunction with recovery of deferred pension costs in rates;


•	$5.0 million in higher thermal O&M due to maintenance outages at the Valmy plant, partially offset by an equipment impairment taken in 2010 at the Bridger plant that did not recur in 2011; and


•	an increase in other payroll related costs of $5.7 million.

These increases were partially offset by a combination of lower meter reading expense and the completed amortization of certain DSM expenses of $3.5 million, and lower outside service fees of $2.3 million.

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

Income Taxes

Income Tax Expense: IDACORP's and Idaho Power's income tax expense for 2011 decreased significantly relative to 2010, primarily as a result of an IRS examination settlement in 2011 related to Idaho Power's uniform capitalization tax accounting method. Income tax expense in 2010 was down significantly from 2009, principally 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. 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.

Status of Audit Proceedings and Tax Method Changes: In September 2010, Idaho Power adopted a tax accounting method change for capitalized repair 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 IRS, subject to subsequent review by the Joint Committee, regarding the allocation of mixed service costs in its method of uniform capitalization. Both methods were subject to audit under IDACORP's 2009 IRS examination.

In April 2011, IDACORP and the IRS reached an agreement on Idaho Power's tax accounting method change for capitalized repairs. Accordingly, the IRS finalized the 2009 examination and submitted its report on the 2009 tax year to the Joint Committee for review. Idaho Power considers the capitalized repairs method effectively settled and believes that no material income tax uncertainties remain for the method. As such, Idaho Power recognized $3.4 million of its previously unrecognized tax benefits for this method in the second quarter of 2011.

In September 2011, the IRS notified IDACORP that the Joint Committee had completed its review and approved the uniform capitalization method agreement. Idaho Power considers the uniform capitalization method effectively settled and believes that no material income tax uncertainties remain for the method. Accordingly, Idaho Power recognized $56.9 million of its previously unrecognized tax benefits for tax years 2009 and prior in the third quarter of 2011.

Completion of the Joint Committee review allowed the IRS to finalize its 2009 examination, process the income tax changes, and close the case in September 2011. In the fourth quarter, IDACORP and Idaho Power paid previously accrued income tax liabilities of $3.9 million and $8.1 million, respectively, related to the capitalized repairs examination agreement. The difference in liabilities is primarily due to IDACORP's utilization of deferred federal general business tax credits. There were no 2011 cash impacts related to the uniform capitalization method settlement as income tax refunds for the method change were received in 2010. In early 2011, IDACORP requested and received the return of $13 million of previously made estimated tax payments for the 2010 tax year.

In December 2011, the IRS completed its examination of IDACORP's 2010 tax year. There were no unresolved income tax issues as a result of the IRS examination. Accordingly, the examination had no impact on IDACORP or Idaho Power's 2011 financial position, results of operations, or cash flows.

Bonus Depreciation Legislation: The Small Business Jobs Act (Jobs Act) and the Tax Relief, Unemployment Insurance Reauthorization, and Job Creation Act of 2010 (Tax Relief Act) includes provisions for the extension and increase of bonus depreciation. Bonus depreciation provides for the accelerated deduction of current capital expenditures from certain asset

classes. 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. Idaho Power has included an estimated bonus deprecation deduction in its current income tax provision. The estimated deduction would reduce Idaho Power's 2011 federal income tax liability by approximately $36 million. The State of Idaho did not conform to the federal bonus depreciation rules for 2010-2012.

LIQUIDITY AND CAPITAL RESOURCES

Overview

IDACORP's and Idaho Power's operating cash flows are driven principally by Idaho Power's 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 in a period of significant 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. Idaho Power expects that total capital expenditures will be between $720 million and $740 million over the period from 2012 through 2014.

Idaho Power's operating cash flows usually do not fully support the amount required for utility capital expenditures during periods of significant infrastructure development. 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 operations, 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 and Idaho Power expect to continue financing capital requirements with a combination of internally generated funds and externally financed capital, and expect minimal need for external financing in 2012. However, IDACORP and Idaho Power monitor debt market conditions and may issue debt securities when they determine that, under the circumstances and in light of the timing and extent of financing needs, conditions are favorable for issuance of debt securities. Idaho Power has $100 million in principal amount of medium-term notes due in November 2012 and expects to fund retirement of those notes with cash from operations or some combination of cash from operations and the issuance of debt securities. IDACORP plans to continue to issue common stock under the pre-existing dividend reinvestment and employee-related stock purchase plans in 2012. While not expected in 2012, IDACORP may also determine to issue IDACORP common stock from time to time under its continuous equity program, depending on market conditions and capital needs. IDACORP and Idaho Power seek to maintain capital structures of approximately 50 percent debt and 50 percent equity, and maintaining this ratio influences IDACORP's and Idaho Power's debt and equity issuance decisions. As of December 31, 2011, IDACORP's capital structure consisted of approximately 52 percent equity and 48 percent debt, which decreases the likelihood that IDACORP will issue equity securities during 2012. A significant focus for 2012 will be to control costs and generate sufficient cash from operations to meet operating needs and contribute to capital expenditure requirements.

On October 26, 2011, IDACORP and Idaho Power entered into agreements that amended and restated their respective credit agreements. IDACORP's new credit facility consists of a revolving line of credit not to exceed the aggregate principal amount at any one time outstanding of $125 million, including swingline loans in an aggregate principal amount at any time outstanding not to exceed $15 million and letters of credit in an aggregate principal amount at any time outstanding not to exceed $50 million. Idaho Power's new credit facility consists of a revolving line of credit, through issuance of loans and standby letters of credit, not to exceed the aggregate principal amount at any one time outstanding of $300 million, including swingline loans in an aggregate principal amount at any time outstanding not to exceed $30 million. IDACORP and Idaho Power each have the right to request an increase in the aggregate principal amount of the new credit facilities to $150 million and $450 million, respectively, in each case subject to certain conditions.

As of February 17, 2012, IDACORP's and Idaho Power's access to debt, equity, and credit arrangements included:


•	their respective $125 million and $300 million revolving credit facilities;


•	IDACORP's shelf registration statement, which can be used for the issuance of debt securities and common stock, including up to 3.0 million shares of IDACORP common stock available for issuance under its continuous equity program. Approximately $539 million of debt and equity securities issuances remained available under the shelf registration statement;


•	Idaho Power's shelf registration statement, which can be used for the issuance of first mortgage bonds and debt securities. $300 million remained available under the shelf registration statement; and


•	IDACORP's and Idaho Power's issuance of commercial paper, which can be used to meet short-term liquidity requirements.

The conditions of the capital markets and the weak economy have in recent years caused a general concern regarding access to sufficient capital at a reasonable cost. Notwithstanding these concerns, IDACORP and Idaho Power have not been significantly affected by this disruption in the credit environment, including in the commercial paper markets, and currently expect to continue to be able to access the capital markets to meet anticipated short- and long-term borrowing needs.

Idaho Power has PCA mechanisms in place that provide for the deferral of fluctuations in purchased power and fuel costs. However, if costs rise above the level currently recovered in retail rates, deferral balances will increase, which will negatively affect cash flow and liquidity until those costs are recovered from customers.

Operating Cash Flows

IDACORP’s and Idaho Power’s operating cash inflows for the year ended December 31, 2011 were $310 million and $292 million, respectively. IDACORP's operating cash flows increased by $5 million and Idaho Power's decreased by $38 million compared to the year ended December 31, 2010. With the exception of cash flows related to income taxes, IDACORP’s operating cash flows are principally derived from the operating cash flows of Idaho Power. Significant items that affected the companies' operating cash flows in 2011 relative to 2010 included:


•	income before income taxes decreased by $27 million for IDACORP and $28 million for Idaho Power;


•	in 2011, Idaho Power recorded a $27 million regulatory liability in addition to a $20 million reduction to pension-related regulatory assets as a result of sharing mechanisms, which reduced income before income taxes but did not reduce operating cash flows. No sharing was recorded during 2010;


•	cash outflows related to the pension and postretirement benefit plans decreased by $44 million. Idaho Power made an $18.5 million cash contribution to its defined benefit pension plan in 2011, compared with a $60 million cash contribution in 2010;

• cash inflows related to income taxes decreased by $15 million and $57 million for IDACORP and Idaho Power, respectively. IDACORP received income tax refunds of $12 million in 2011 compared with $27 million in 2010. Idaho Power’s net refunds from IDACORP for income tax were $1 million for the year, compared with $57 million for the same period in 2010;