Edgar Filing: IDAHO POWER CO

IDA 12.31.12 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, 2012



	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)

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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, 2012):



IDACORP, Inc.:	$	2,087,821,219	Idaho Power Company:	None



Number of shares of common stock outstanding as of February 15, 2013:
IDACORP, Inc.:	50,143,416
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 2013 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.

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TABLE OF CONTENTS

		Page

Commonly Used Terms		4
Cautionary Note Regarding Forward-Looking Statements		5

Part I

Item 1	Business	7
	Executive Officers of the Registrants	17
Item 1A	Risk Factors	19
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	29
Item 6	Selected Financial Data	31
Item 7	Management's Discussion and Analysis of Financial Condition and Results of Operations	32
Item 7A	Quantitative and Qualitative Disclosures About Market Risk	73
Item 8	Financial Statements and Supplementary Data	75
Item 9	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	131
Item 9A	Controls and Procedures	131
Item 9B	Other Information	135

Part III

Item 10	Directors, Executive Officers and Corporate Governance*	135
Item 11	Executive Compensation*	135
Item 12	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters*	135
Item 13	Certain Relationships and Related Transactions, and Director Independence*	136
Item 14	Principal Accountant Fees and Services*	136

Part IV

Item 15	Exhibits and Financial Statement Schedules	137

Signatures		148

* Except as indicated in Items 10, 12, and 14, IDACORP, Inc. information is incorporated by reference to IDACORP, Inc.'s definitive proxy statement for the 2013 annual meeting of shareholders.

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COMMONLY USED TERMS

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

ADITC	-	Accumulated Deferred Investment Tax Credits	IESCo	-	IDACORP Energy Services Co., a subsidiary of IDACORP, Inc.
AFUDC	-	Allowance for Funds Used During Construction	IFS	-	IDACORP Financial Services, a subsidiary of IDACORP, Inc.
AMI	-	Advanced Metering Infrastructure	IPUC	-	Idaho Public Utilities Commission
aMW	-	Average Megawatts	IRP	-	Integrated Resource Plan
APCU	-	Annual Power Cost Update	IRS	-	U.S. Internal Revenue Service
BACT	-	Best Available Control Technology	kW	-	Kilowatt
BCC	-	Bridger Coal Company, a joint venture of IERCo	LCAR	-	Load Change Adjustment Rate
BLM	-	U.S. Bureau of Land Management	MACT	-	Utility Maximum Available Control Technology
BPA	-	Bonneville Power Administration	MD&A	-	Management’s Discussion and Analysis of Financial Condition and Results of Operations
CAA	-	Clean Air Act	MW	-	Megawatt
CAMP	-	Comprehensive Aquifer Management Plan	MWh	-	Megawatt-hour
CO₂	-	Carbon Dioxide	NAAQS	-	National Ambient Air Quality Standards
CWA	-	Clean Water Act	NOAA	-	National Oceanic and Atmospheric Administration
DOE	-	U.S. Department of Energy	NOx	-	Nitrous Oxide
DSM	-	Demand-Side Management	NSPS	-	New Source Performance Standards
EGUs	-	Electric Utility Generating Units	NSR/PSD	-	New Source Review / Prevention of Significant Deterioration
EIS	-	Environmental Impact Statement	O&M	-	Operations and Maintenance
EPA	-	U.S. Environmental Protection Agency	OATT	-	Open Access Transmission Tariff
EPS	-	Earnings Per Share	OPUC	-	Oregon Public Utility Commission
ESA	-	Endangered Species Act	PCA	-	Power Cost Adjustment
FASB	-	Financial Accounting Standards Board	PCAM	-	Power Cost Adjustment Mechanism
FCA	-	Fixed Cost Adjustment Mechanism	PURPA	-	Public Utility Regulatory Policies Act of 1978
FERC	-	Federal Energy Regulatory Commission	REC	-	Renewable Energy Certificate
FPA	-	Federal Power Act	RES	-	Renewable Energy Standard
GAAP	-	Generally Accepted Accounting Principles	RPS	-	Renewable Portfolio Standard
GHG	-	Greenhouse Gas	SEC	-	U.S. Securities and Exchange Commission
HAPS	-	Hazardous Air Pollutants	SMSP	-	Senior Management Security Plan
HCC	-	Hells Canyon Complex	SO₂	-	Sulfur Dioxide
Ida-West	-	Ida-West Energy, a subsidiary of IDACORP, Inc.	USBR	-	U.S. Bureau of Reclamation
Idaho ROE	-	Idaho-jurisdiction return on year-end equity	USFWS	-	U.S. Fish and Wildlife Service
IERCo	-	Idaho Energy Resources Co., a subsidiary of Idaho Power Company	VIEs	-	Variable Interest Entities

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CAUTIONARY NOTE REGARDING 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," "targets" "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 Part 1 - Item 1A - "Risk Factors" of this report and the following important factors:


•	Idaho Power's rate design and the effect of regulatory decisions by the Idaho and Oregon public utilities commissions, the Federal Energy Regulatory Commission, and other regulators affecting Idaho Power's ability to recover costs and earn a return;


•	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 availability and use of energy efficiency and conservation programs, and the associated impact on loads and load growth;


•	the impacts of changes in economic conditions, including the potential for changes in customer demand for electricity, revenue from sales of excess power, financial soundness of counterparties and suppliers, and collections;


•	unseasonable or severe weather conditions, wildfires, and other natural phenomena, which affect customer demand, hydroelectric generation levels, infrastructure repair costs, and the ability and cost to procure fuel for generation plants or purchased power to serve customers;


•	advancement of new technologies that reduce loads or render Idaho Power's generation facilities obsolete;


•	adoption of or changes in, and costs of compliance with, laws, regulations, and policies relating to the environment, natural resources, and endangered species, and the ability to recover those costs through rates;


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


•	the ability to purchase fuel and power from suppliers on favorable payment terms and prices, particularly in the event of unanticipated power demands, lack of physical availability, transportation constraints, or a credit downgrade;

•

accidents, fires, explosions, and mechanical breakdowns that may occur while operating and maintaining an electric system, which can cause unplanned outages, reduce generating output, damage the companies’ assets or operations, subject the companies to third-party claims for property damage, personal injury, or loss of life, or result in the imposition of civil, criminal, or regulatory fines or penalties;

•

the ability to obtain debt and equity financing or refinance existing debt when necessary and on favorable terms, which can be affected by factors such as credit ratings, volatility in the financial markets (including as a result of European sovereign debt issues) and interest rate fluctuations, decisions by the Idaho or Oregon public utility commissions, and the companies' past or projected financial performance;


•	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 buy and sell power, transmission capacity, and fuel in the markets and the availability to enter into financial and physical commodity hedges with creditworthy counterparties, including the impact of federal legislation on counterparties' willingness to transact, market liquidity, and hedging costs, which may affect fuel and power availability and pricing, and the failure of any such risk management and hedging strategies to work as intended;


•	changes in or implementation of Federal Energy Regulatory Commission and other mandatory reliability, security, and other requirements for system infrastructure, which could result in penalties and increase costs;


•	disruptions or outages of Idaho Power's generation or transmission systems or the western interconnected transmission system;


•	the costs and operational challenges of integrating an increasing volume of mandated purchased intermittent wind power or other renewable energy sources into Idaho Power's resource portfolio;

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•	further increases in the unfunded liability or changes in actuarial assumptions, the interest rate environment, and the actual return on plan assets for pension and other post-retirement plans, which can affect future funding obligations, costs, and pension and other post-retirement plan liabilities;


•	the ability to continue to pay dividends under the terms of the companies' credit arrangements and regulatory limitations, and whether the companies' boards of directors will continue to declare dividends based on the boards of directors’ periodic consideration of factors affecting IDACORP's and Idaho Power's dividend policies;


•	changes in tax laws or related regulations or new interpretations of applicable laws by federal, state, or local taxing jurisdictions, the availability of tax credits, and the tax rates payable by IDACORP shareholders on common stock dividends;


•	employee workforce factors, including the operational and financial costs of unionization or the attempt to unionize all or part of the companies' workforce, the impact of an aging workforce, the cost and ability to retain skilled workers, and the ability to adjust the labor cost structure when necessary;


•	failure to comply with state and federal laws, policies, and regulations, including new interpretations and enforcement initiatives by regulatory and oversight bodies, which may result in penalties and increase the cost of compliance, the nature and extent of investigations and audits, and costs of remediation;


•	the inability to obtain, and cost of obtaining and complying with, required governmental permits and approvals, licenses, rights-of-way, and siting for transmission and generation projects and hydroelectric facilities;


•	the cost and outcome of litigation, dispute resolution, regulatory proceedings, and penalties, and the ability to recover those costs or the costs of operational changes through insurance, rates, or from third parties;


•	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 Reporting Standards, and new Securities and Exchange Commission or New York Stock Exchange requirements, or new interpretations of existing requirements; and


•	unusual or unanticipated changes in normal business operations, including unusual maintenance or repairs, or the failure to successfully implement technology solutions.

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.

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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 the 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 Services Co. (IESCo), which held a 99-percent limited partnership interest in IDACORP Energy L.P. (IE), a marketer of energy commodities that wound down operations in 2003. IE merged with and into IESCo effective December 31, 2012.

Idaho Power is IDACORP’s only reportable business segment, contributing substantially all of IDACORP’s net income in 2012. Segment data is presented in Note 17 – "Segment Information" to the consolidated financial statements included in this report. As of December 31, 2012, IDACORP had 2,079 full-time employees, 2,067 of whom were employed by Idaho Power, and 21 part-time employees, 20 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 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, 2012, Idaho Power supplied electric energy to approximately 501,000 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.

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Weather, customer demand, and economic conditions impact electricity sales and costs and, therefore, Idaho Power's 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.

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

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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

The prices that the IPUC and OPUC authorize Idaho Power to charge for its electric service is a critical factor in determining IDACORP's and Idaho Power's results of operations and financial condition. In addition to the discussion below, 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.

Retail Rates: Idaho Power periodically evaluates the need to seek changes to its retail electricity price structure to cover its operating costs and provide an opportunity for a reasonable rate of return. Idaho Power uses general rate cases, power cost adjustment (PCA) mechanisms, a fixed cost adjustment (FCA), balancing accounts and riders, 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 procedures and schedules, include Idaho Power, the staffs of 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. This requirement does not, however, ensure that Idaho Power will earn a specified rate of return. 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.

Wholesale Markets: 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 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 participates in the wholesale energy markets by purchasing 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, transmission constraints, and availability of generating resources. Some of Idaho Power's 17 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 following table 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, including information on energy sales, are discussed further in Part II, Item 7 - “MD&A - Results of Operations - Utility Operations.”

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	Year Ended December 31,
	2012			2011			2010
Revenues (thousands of dollars)
Residential	$	431,555		$	405,982		$	400,607
Commercial	241,519			220,962			231,440
Industrial	145,054			140,701			138,394
Irrigation	137,424			104,635			110,555
Provision for rate refund for sharing mechanism	(7,151		)	(27,099		)	—
Deferred revenue related to Hells Canyon Complex relicensing AFUDC	(10,636		)	(10,636		)	(10,625		)
Total general business revenues	937,765			834,545			870,371
Off-system sales	61,534			101,602			78,133
Other	77,426			86,581			84,548
Total revenues	$	1,076,725		$	1,022,728		$	1,033,052
Energy use (thousands of MWh)
Residential	5,039			5,146			4,967
Commercial	3,865			3,815			3,763
Industrial	3,133			3,100			3,076
Irrigation	2,048			1,673			1,707
Total general business	14,085			13,734			13,513
Off-system sales	2,183			3,635			1,982
Total	16,268			17,369			15,495

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 basin. Market purchases and sales are used to supplement Idaho Power's generation and 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 wholesale market purchased power. Economic conditions and governmental regulations can affect the market price of natural gas and coal, which may impact fuel expense and market prices for purchased power. Idaho Power has PCA mechanisms in Idaho and Oregon that mitigate in large part the potential adverse financial statement impacts of volatile fuel and power costs.

Idaho Power’s system is dual peaking, with the larger peak demand occurring in the summer. The all-time system peak demand was 3,245 MW, set on July 12, 2012, and the all-time winter peak demand was 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. The following table presents Idaho Power’s total power supply for the last three years.

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	MWh			Percent of Total Generation
	2012	2011	2010	2012		2011		2010
	(thousands of MWh)
Hydroelectric plants	7,956	10,937	7,344	57	%	69	%	51	%
Coal-fired plants	5,227	4,820	6,864	38	%	30	%	48	%
Natural gas fired plants	676	138	160	5	%	1	%	1	%
Total system generation	13,859	15,895	14,368	100	%	100	%	100	%
Purchased power - cogeneration and
small power production	1,961	1,495	910
Purchased power - other	1,709	1,256	1,491
Total purchased power	3,670	2,751	2,401
Total power supply	17,529	18,646	16,769

Hydroelectric Generation: Idaho Power operates 17 hydroelectric projects located on the Snake River and its tributaries. Together, these hydroelectric facilities provide a total nameplate capacity of 1,709 MW and annual generation equal to approximately 8.6 million MWh under median water conditions. 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 considerations. 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. During low water years, when stream flows into Idaho Power’s hydroelectric projects are reduced, Idaho Power’s hydroelectric generation is reduced, resulting in a reliance on other generation resources and power purchases.

Below average snow accumulation in the Snake River basin resulted in below average stream flow in 2012. As a consequence, annual generation from Idaho Power’s hydroelectric facilities was 3.0 million MWh lower in 2012 than in 2011. The Northwest River Forecast Center of the National Oceanic and Atmospheric Administration reported that Brownlee Reservoir (part of the Hells Canyon Complex) inflow for April through July 2012 was 5.5 million acre-feet (maf). By comparison, April through July Brownlee Reservoir inflow was 10.5 maf in 2011 and 4.6 maf in 2010.

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 project, its largest hydroelectric generation source. 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.”

Idaho Power is subject to the provisions of the FPA as a “public utility” and as a “licensee” by virtue of its hydroelectric operations. 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.

Coal-Fired Generation: Idaho Power co-owns the following coal-fired power plants:


•	Jim Bridger located in Wyoming, in which Idaho Power has a one-third interest;


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


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

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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 power plant. PacifiCorp operates both the Jim Bridger mine and the Jim Bridger power plant. 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 at least 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 Jim Bridger mine deliveries and provides another coal supply to operate the Jim Bridger plant. The Jim Bridger plant’s rail load-in facility and unit coal train provide the opportunity to access other fuel supplies for tonnage requirements above established contract minimums.

NV Energy, Inc., as the operator of the Valmy generating plant, has agreements with coal suppliers through 2015. Idaho Power's share of these agreements along with existing coal inventory at the plant are expected to meet Idaho Power's projected coal supply needs for 2013 and 2014, and approximately 60 percent of its supply needs for 2015. As a 50-percent owner of the plant, Idaho Power is obligated to purchase one-half of the coal obtained under these contracts.

The Boardman generating plant receives coal through annual contracts with suppliers from the Powder River Basin in northeast Wyoming. Portland General Electric Company is the operator of the Boardman plant. All of the Boardman plant’s projected coal requirements in 2013 and approximately 33 percent of projected coal requirements in 2014 are under contract. A portion of the 2013 and 2014 coal purchased 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 obtained 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.

Natural Gas-fired Generation: Idaho Power owns and operates the Langley Gulch natural gas-fired combined cycle power plant and the Danskin and Bennett Mountain natural gas-fired simple cycle combustion turbine power plants. All three plants are located in Idaho. The Langley Gulch power plant was placed into service in June 2012, contributing to the notable increase in gas-fired generation during 2012 relative to prior years.

Idaho Power operates the Langley Gulch plant as a base load unit and the Danskin and Bennett Mountain plants to meet peak supply needs. The plants are also used to take advantage of wholesale market opportunities. Natural gas for all facilities is purchased based on system requirements and dispatch efficiency. The natural gas is transported through the Williams-Northwest Pipeline under Idaho Power's 55,584 million British thermal units (MMBtu) per day long-term gas transportation service agreements. These transportation 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. This firm storage contract expires in 2043. Idaho Power purchases and stores natural gas with the intent of fulfilling needs as identified for seasonal peaks or to meet system requirements.

As of December 31, 2012, approximately 3.2 million MMBtu's of natural gas was financially hedged for physical delivery for the operational dispatch of the Langley Gulch plant through December 2013. Idaho Power plans to manage the procurement of additional natural gas for the peaking units on the daily spot market or from storage inventory 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 management policy limitations, and unit availability. Idaho Power seeks to manage its loads efficiently by utilizing its generation resources and long-term power purchase contracts in conjunction with buying and selling opportunities in the wholesale market. In addition to its market purchases, Idaho Power has the following notable firm wholesale power purchase contracts and energy exchange agreements:


•	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.

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•	USG Oregon LLC - for 22 MW (estimated average annual output) from the Neal Hot Springs #1 geothermal power plant located near Vale, Oregon. The contract term is 25 years with an option to extend. This project achieved commercial operation in November 2012.


•	Clatskanie People’s Utility - for the exchange of up to 18 MW of energy from the Arrowrock hydroelectric project in southern Idaho in exchange for energy from Idaho Power’s system or power purchased at the Mid-Columbia trading hub. The initial term of the agreement is through December 31, 2015. Idaho Power has the right to renew the agreement for two additional five-year terms.

During 2012, Idaho Power purchased 1.7 million MWh of power through wholesale market purchases at an average price of $46.41 per MWh. During 2011, Idaho Power purchased 1.3 million MWh of power through wholesale market purchases at an average cost of $58.19 per MWh.

PURPA Power Purchase Contracts: Idaho Power purchases power from PURPA projects as mandated by federal law. As of December 31, 2012, Idaho Power had 779 MW nameplate capacity of PURPA-related projects on-line, with an additional 52 MW nameplate capacity of projects projected to be on-line by the end of 2014. The power purchase contracts for these projects have terms ranging from one to 35 years. The expense and volume of PURPA project power purchases during the last three years is included in the table below.



	Year Ended December 31,
	2012		2011		2010
PURPA contract expense (in thousands)	$	117,618	$	90,251	$	56,022
MWh purchased under PURPA contracts (in thousands)	1,961		1,495		910
Average cost per MWh from PURPA contracts	$	59.98	$	60.36	$	61.56

The bulk of the increase in volume of PURPA power purchases resulted from additional wind projects. 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 "qualifying facilities" that meet the requirements of PURPA. 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 IPUC and OPUC have established specific rules and regulations to calculate the avoided cost that Idaho Power is required to include in PURPA contracts. For PURPA power purchase agreements:


•	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 Idaho Power's system.


•	The IPUC jurisdictional portion of the costs associated with PURPA contracts is fully recovered through base rates and the PCA, and the OPUC jurisdictional portion is recovered through general rate case filings and an Oregon PCA mechanism.


•	IPUC and OPUC jurisdictional regulations allow PURPA standard contract terms to be up to 20 years.


•	The IPUC requires Idaho Power to pay "published avoided cost" rates for all wind and solar projects that are smaller than 100 kW and all other types of projects that are smaller than 10 average MWs. For PURPA qualifying facilities that exceed these size limitations, Idaho Power is required to negotiate an applicable price (premised on avoided costs) based upon IPUC regulations.


•	The OPUC requires that Idaho Power pay the published avoided costs for all PURPA qualifying facilities with a nameplate rating of 10 MW or less and that Idaho Power negotiate an applicable price (premised on avoided costs) for all other qualifying facilities based upon OPUC regulations.

Idaho Power, as well as other power utilities with an Idaho service territory, has been engaged in proceedings at the IPUC and OPUC relating to PURPA contract terms, including the prices paid for energy purchased from PURPA projects. Refer to "MD&A - Regulatory Matters - Renewable Energy Contracts, Renewable Energy Certificates, and Emission Allowances" for a summary of those proceedings.

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

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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 capability and reliability. Idaho Power’s transmission system is directly interconnected with the transmission systems of the Bonneville Power Administration, Avista Corporation, PacifiCorp, NorthWestern Energy, and NV Energy, Inc. These interconnections, coupled with transmission line capacity made available under agreements with some of those entities, permit the interchange, purchase, and sale of power among entities in the Western Interconnection. Idaho Power provides wholesale transmission service and provides firm and non-firm wheeling services for eligible transmission customers. Idaho Power is a member of the Western Electricity Coordinating Council, the 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 Interconnection.

Resource Planning

Integrated Resource Plan: The IPUC and OPUC require that Idaho Power biennially prepare an Integrated Resource Plan (IRP). Idaho Power filed its 2011 IRP with the IPUC and OPUC in June 2011. The IRP seeks to forecast Idaho Power's loads and resources for a 20-year period, analyzes potential supply-side and demand-side resource options, and identifies potential near-term and long-term actions. The 2011 IRP was accepted by the IPUC in December 2011 and acknowledged by the OPUC in February 2012. 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 preparation of the 2013 IRP is in process. Idaho Power expects that the 2013 IRP 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 as new generation resources the 318-MW Langley Gulch natural-gas fired power plant, which came on-line in June 2012, and a 49-MW expansion of the Shoshone Falls hydroelectric facility, which is under evaluation and unlikely to be constructed prior to 2019. 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 existing Hemingway substation, together with the Gateway West transmission line, will improve reliability, relieve transmission congestion, and provide system flexibility. Additional information about Idaho Power's significant infrastructure development projects is included in Item 7 - “MD&A - Liquidity and Capital Resources - Capital Requirements - Major Infrastructure Projects.”

Preliminary work performed in connection with Idaho Power's 2013 IRP indicates more moderate load growth rates in Idaho Power's service area than what was forecast in the 2011 IRP. The moderation in load growth is in large part the result of changes in expectations surrounding economic conditions, anticipated electricity price increases incorporating impacts of carbon legislation, loss of anticipated load from the Hoku Materials, Inc. special customer contract, and the elimination of an anticipated but unidentified special contract customer that had been included in the 2011 IRP. The 2013 IRP median annual average load forecast projects growth of 1.1 percent annually over the next 20 years, whereas the 2011 IRP included a forecast growth rate of 1.4 percent. For median peak-hour load, the 2013 IRP is expected to project an annual average growth rate of 1.4 percent whereas the 2011 IRP included a forecast growth rate of 1.8 percent. Accounting for the reduced load growth and excluding approximately 400 MW of demand response programs, the preliminary 2013 IRP load and resource balance forecasts the first resource capacity deficit will not occur until the summer of 2016 under one scenario. Although the 2013 IRP is projected to forecast lower load growth rates, there is still much uncertainty regarding the rate of recovery from the recession and the subsequent impact on Idaho Power's future load growth. Idaho Power expects to be able to manage any near-term summer peak capacity deficits until completion of the Boardman-to-Hemingway transmission line, which is expected in 2018 at the earliest. If the Boardman-to-Hemingway line is not constructed by the time necessary to meet load demands, Idaho Power will need to identify alternatives to meet load requirements.

In response to the operational challenges associated with integrating intermittent wind power that Idaho Power must purchase pursuant to PURPA, and the recognition that the costs and challenges associated with integrating intermittent resources will become even more pronounced as the volume of intermittent resources in Idaho Power's portfolio increases, Idaho Power

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continues efforts to better understand the effects of wind generation on power system operation. As part of these efforts, Idaho Power issued its first wind integration study in 2007, and in late 2012 completed a second, more comprehensive wind integration study. The goal of the most recent study was to assess the additional costs incurred in modifying operations of Idaho Power's dispatchable generating resources to compensate for the variable and intermittent energy supplied by wind generators while maintaining reliable energy delivery to customers. Additionally, the study aimed to provide insight on the maximum amount of wind generation Idaho Power's system can accommodate without impacting reliability. Idaho Power has committed considerable resources to the study, including working with an independent consultant, utility industry peers, and interested parties, and has held public workshops. Idaho Power released the report publicly in February 2013 as part of its 2011 IRP update. In further response to the integration challenges, Idaho Power has implemented an internally developed wind forecasting system, in recognition that cost-intensive modifications to operations intended to integrate wind are reduced, though not eliminated, with improved wind production forecasting.

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 over the long term. Idaho Power continues to evaluate the timing for proceeding with solar PV technology.

Energy Efficiency and Demand Response Programs: Idaho Power has 18 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 2012, Idaho Power’s energy efficiency programs reduced energy usage by approximately 157,000 MWh. Idaho Power's demand response programs had available capacity of approximately 411 MW; however, because of a relatively high cost to dispatch Idaho Power's Irrigation Peak Rewards program it was not used in 2012. Idaho Power realized approximately 91 MW in summer peak demand reduction through the A/C Cool Credit and the FlexPeak Management programs as these programs have no marginal dispatch costs. In December 2012, Idaho Power filed with the IPUC to temporarily suspend the A/C Cool Credit and Irrigation Peak Rewards programs for the summer of 2013 in order to work with stakeholders and IPUC Staff to explore the near-term need for and design of the demand response programs. A settlement stipulation relating to temporary suspension of the programs is pending before the IPUC.

In 2012, Idaho Power spent approximately $49.3 million on energy efficiency and targeted demand reduction response programs. Approximately $27.1 million annually 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 and the PCA mechanism. In 2012, as approved by the IPUC, Idaho Power capitalized approximately $6 million of custom efficiency program incentives as a regulatory asset. For expenditures in 2012, Idaho Power will also recover approximately $14.5 million in demand response incentives through its annual PCA as approved by the IPUC.

Approximately $4.7 million of Idaho Power’s 2012 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.

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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's three coal-fired power plants and three natural gas combustion turbine power plants are also 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 Item 7 – “MD&A – Environmental Matters” in this report.

Cost Estimates: Idaho Power’s environmental compliance expenditures will continue to be significant for the foreseeable future, especially with potential additional regulation under discussion at the federal level. Idaho Power estimates its environmental expenditures, based upon present environmental laws and regulations, will be as follows for the periods indicated, excluding allowance for funds used during construction (AFUDC) (in millions of dollars):



Environmental Expenditures	2013		2014 - 2015
Capital expenditures:
Studies and measures at hydroelectric facilities	$	12	$	41
Investments in equipment and facilities at thermal plants	50		94
Total capital expenditures	$	62	$	135
Operating expenses:
Operating costs for environmental facilities - hydroelectric	$	21	$	49
Operating costs for environmental facilities - thermal	8		22
Total operations and maintenance	$	29	$	71

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, but Idaho Power is unable to estimate those costs given the uncertainty associated with pending regulations.

Environmental Controls Cost Study: In connection with its IRP process, Idaho Power has been conducting cost studies and scenario analyses to assess the potential future investments necessary for the continued operation of the Jim Bridger and Valmy coal-fired generation facilities. The Boardman plant was not included in the study because of the existing schedule to cease coal-fired operations at that plant by the end of 2020. Some of the future environmental control requirements for the Jim Bridger and Valmy plants are known; however, additional requirements could arise from future regulations. In the analysis, the cost of future compliance was compared to the cost of replacement generation capacity provided by combined-cycle combustion turbine technology and conversion of the units to natural gas. Because of the speculative nature of many of the future requirements, the analysis was performed under a range of fuel pricing assumptions, carbon cost assumptions, plant upgrade and retirement costs, environmental regulation assumptions, and replacement costs. Idaho Power published the results of the study with its 2011 IRP update filed with the IPUC and OPUC in February 2013. Idaho Power concluded in its study that the Jim Bridger and Valmy plants should be retained in its resource portfolio and supports planned investments in environmental controls at those plants. This is particularly true in light of the desire to maintain a diversified portfolio of generation assets and fuel diversity that can mitigate risk associated with increases in natural gas prices. However, the study also concluded that in the event significant additional operating and maintenance or capital expenditures are necessary at the Valmy plant as a result of new environmental requirements, Idaho Power will conduct a further review to determine whether such investments are economically appropriate, and whether conversion of the facility to a natural-gas fired plant would be appropriate.

Inaugural Sustainability Report: In May 2012, IDACORP publicly issued its inaugural sustainability report. The sustainability report highlights Idaho Power's continuing efforts to operate in a manner that supports financial, environmental, and social stewardship. IDACORP plans to issue its second sustainability report in May 2013 and make it available on its or Idaho Power's website.

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Extension of Idaho Power's Voluntary CO₂ Intensity Reduction Goal: While there is currently no national mandatory greenhouse gas reduction requirement, Idaho Power continues to prepare for potential legislative and/or regulatory restrictions on emissions in order to help reduce the costs of complying with such restrictions on its customers. To that end, Idaho Power is engaged in voluntary greenhouse gas emission intensity reduction efforts. In September 2009, IDACORP's and Idaho Power's boards of directors approved guidelines that established a goal to reduce Idaho Power's resource portfolio's average carbon dioxide (CO₂) emission intensity for the 2010 through 2013 time period to a level of 10 to 15 percent below Idaho Power's 2005 CO₂ emission intensity of 1,194 lbs CO₂/MWh. Idaho Power's estimated CO₂ emission intensity from its generation facilities, as submitted to the Carbon Disclosure Project, was 672, 1,051, and 1,004 lbs/MWh for 2011, 2010, and 2009 respectively. As of the date of this report, Idaho Power is on track to exceed the CO₂ emission intensity reduction goal it established in 2009. The combination of effective utilization of hydroelectric projects, above average stream flows, reduced usage of coal-fired facilities, and addition of the Langley Gulch natural gas-fired power plant have positioned Idaho Power to extend its CO₂ intensity reduction goal period for an additional two years, targeting an average reduction of 10 to 15 percent below its 2005 levels for the entire 2010 through 2015 time period.

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 $5.5 million, $6.4 million, and $7.3 million in 2012, 2011, and 2010, respectively. IFS’s portfolio also includes historic rehabilitation projects such as the Empire Building in Boise, Idaho. IFS made no new investments in 2012 or 2011, but did have $7 million of new investments during 2010.

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, 2012, the gross amount of IFS’s portfolio equaled $195 million in tax credit investments. These investments cover 49 states, Puerto Rico, and the U.S. Virgin Islands. The underlying investments include approximately 570 individual properties, of which all but four 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, $9 million, and $8 million in 2012, 2011, and 2010, 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 appointed.

Senior Executive Officers (in alphabetical order)

DARREL T. ANDERSON, 54


•	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 - September 30, 2009.

REX BLACKBURN, 57


•	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.

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LISA A. GROW, 47


•	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, 60


•	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.


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

STEVEN R. KEEN, 52


•	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.

DANIEL B. MINOR, 55

•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 - September 30, 2009.

Other Executive Officers (in alphabetical order)

DENNIS C. GRIBBLE, 60

•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.

PATRICK A. HARRINGTON, 52


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

WARREN KLINE, 57


•	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 19, 2010.

JEFFREY MALMEN, 45


•	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 - September 30, 2008.

LUCI K. MCDONALD, 55


•	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 19, 2010.

KEN W. PETERSEN, 49


•	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 19, 2010.

N. VERN PORTER, 53


•	Vice President, Delivery Engineering and Construction, Idaho Power Company, May 17, 2012 - present.

•Vice President, Delivery Engineering and Operations, Idaho Power Company, October 1, 2009 - May 16, 2012.

•General Manager of Power Production of Idaho Power Company, April 22, 2006 - September 30, 2009.

GREGORY W. SAID, 58


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

•General Manager of Regulatory Affairs, Idaho Power Company, April 3, 2010 - January 19, 2011.

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•Director, State Regulation, Idaho Power Company, August 23, 2008 - April 2, 2010.

•Manager, Revenue Requirement, Idaho Power Company, November 14, 1998 - August 22, 2008.

NAOMI SHANKEL, 41


•	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 19, 2010.

LORI D. SMITH, 52


•	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 19, 2010.

ITEM 1A. RISK FACTORS

The circumstances and factors set forth below may have a material 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 an acceptable rate of return, IDACORP's and Idaho Power's financial condition and results of operations may be adversely affected. 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 its transmission services, are generally the most significant factors influencing IDACORP’s and Idaho Power’s business, results of operations, and financial condition. 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. The regulatory process does not assure that Idaho Power will be able to achieve the rate of return allowed by the Idaho and Oregon public utility commissions. 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 what rates of return will be authorized, the extent to which costs will be allowed for recovery, or the timing of recovery. The failure of Idaho Power to obtain approvals from regulatory authorities to recover costs, construct new generating or transmission facilities, install environmental emission control equipment, or otherwise operate Idaho Power's business may adversely impact Idaho Power's ability to achieve its strategic plan, cause IDACORP and Idaho Power to record an impairment of their assets, and have a material adverse impact on their results of operations and financial condition. In a number of proceedings in recent years, Idaho Power has been denied recovery, or deferred recovery pending the next general rate case, including denials or deferrals related to compensation expenses and construction expenditures. For additional information relating to Idaho Power's regulatory framework and recent matters, see Item 1 - "Business - Utility Operations," Note 3 - "Regulatory Matters" to the consolidated financial statements included in this report, and Item 7 - "Management's Discussion and Analysis of Financial Condition and Results of Operations - Regulatory Matters" in this report.

Idaho Power's cost recovery deferral mechanisms may not function as intended, which may adversely affect IDACORP's and Idaho Power's financial condition and results of operations. Idaho Power has power cost adjustment mechanisms in its Idaho and Oregon jurisdictions and a fixed cost adjustment mechanism in Idaho that provide for periodic adjustments to the rates charged to its retail customers. The power cost adjustment mechanisms track 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 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 through rates. Consequently, 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

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supply cost variations is on the timing of cash flows. When costs rise above the level recovered in current retail rates it adversely affects Idaho Power’s operating cash flow and liquidity until those costs are recovered from customers.

Unanticipated changes in loads in Idaho Power’s service territory expose Idaho Power to market and operational risk and could increase costs and adversely affect IDACORP's and Idaho Power's results of operations and financial condition. While Idaho Power’s customer growth rate has slowed in recent years, Idaho Power believes its service territory is an attractive one for both businesses and individuals. Idaho Power has recently adjusted its load forecast as part of its integrated resource planning process, predicting a lower growth rate over its 20-year resource planning horizon compared to prior estimates. In its efforts to balance loads and resources, Idaho Power makes load estimates that are based on a number of factors that are uncertain and difficult to estimate, and any unanticipated increase in the demand for energy could result in increased reliance on purchased power to meet peak system demand, the need to reinstate or initiate new demand response and energy efficiency programs, or the need for investment in additional generation resources. If the incremental costs associated with the unanticipated changes in loads exceed the incremental revenue and Idaho Power is unable to secure timely rate relief to recover those costs, the resulting disconnect between the time costs are incurred or investments are made and the time costs are recovered could have an adverse effect on IDACORP's or Idaho Power's financial condition and results of operations.

National and regional economic conditions may reduce customer growth rates, reduce energy consumption, or cause increased late payments and uncollectible customer accounts, which would adversely affect IDACORP's and Idaho Power's financial condition and results of operations. Beginning in 2008, economic conditions in Idaho Power’s service area have been relatively weak. Weak economic conditions may reduce the amount of energy Idaho Power’s customers consume, result in a loss of customers (including large-load industrial and commercial customers) or further decrease the customer growth rate, and increase the likelihood and prevalence of late payments and uncollectible accounts. A resulting decrease in overall customer usage or collections and load growth at a rate less than anticipated may alter capital spending plans and rate base growth and may reduce revenues, earnings, and cash flows. Also, Idaho Power's regulatory mechanisms, including its load change adjustment rate and fixed cost adjustment mechanism in Idaho, are unlikely to result in Idaho Power recovering all of its costs related to load decreases, which would have a negative impact on IDACORP's and Idaho Power's financial condition and results of operations.

Extreme weather events and their associated impacts, such as high winds and fires, whether as a result of climate change or otherwise, can adversely affect IDACORP's and Idaho Power's results of operations and financial condition. Extreme weather events can damage generation facilities and disrupt transmission and distribution systems, causing service interruptions and extended outages, increasing supply chain costs, and limiting Idaho Power's ability to meet customer energy demand. Disruption in generation, transmission, and distribution systems due to weather-related factors also increases operations and maintenance expenses and could negatively affect IDACORP's and Idaho Power's results of operation and financial condition.

New advances in power generation, energy efficiency, or other technologies that impact the power utility industry could cause an erosion in revenues. With the escalating costs of energy has come the incentive for the development of new technologies for power generation and energy efficiency, and an investment in research and development to make those technologies more efficient and cost-effective. For instance, while solar technology remains a relatively high-cost means of power generation, there have been numerous recent advancements in the design of solar generation facilities and the materials used in panels (for example, copper indium gallium diselenide and amorphous silicon). These advancements may further increase the efficiency and power output of solar generation sources. Considerable emphasis has also been placed on energy efficiency and products that reduce electricity usage, such as LED lighting. There is potential that power generation systems provided by third parties, whether solar generation or otherwise, and energy efficiency measures could become sufficiently cost-effective and efficient that customers choose to install such systems on their homes or businesses. This may render traditional generation sources owned by Idaho Power obsolete or decrease the need for energy supplied by Idaho Power, which would reduce Idaho Power's revenue and have a negative impact on IDACORP's and Idaho Power's results of operations and financial condition.

Capital expenditures for power generation and delivery infrastructure and replacement of that infrastructure, and the timing and availability of cost recovery for those expenditures, can significantly affect IDACORP's and Idaho Power's financial condition and results of operations. Idaho Power’s business is capital intensive and requires significant investments in energy generation, transmission, and distribution infrastructure. Long-term increases in both the number of customers and the demand for energy require expansion and reinforcement of that infrastructure. For instance, Idaho Power is in the permitting process for two 500-kV transmission line projects. Construction projects are subject to usual construction risks that can adversely affect project costs and completion time. These risks include the ability to obtain labor or materials; increases in cost of labor and materials; contractor defaults; equipment, engineering, and design failures; adverse weather conditions; lack of availability of financing; the ability to obtain and comply with permits and land use rights; environmental constraints;

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disputes and litigation with third parties; and changes in applicable laws or regulations. If Idaho Power is unable to complete the construction of a project, or incurs costs that regulators do not deem prudent, it may not be able to recover its costs in full through rates. Even if Idaho Power completes a construction project, the total costs may be higher than estimated and/or higher than amounts approved for recovery by regulators. 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, which may negatively affect IDACORP's and Idaho Power's financial condition and results of operations.

Further, if Idaho Power were unable to secure permits or joint funding commitments to develop transmission infrastructure necessary to serve loads, such as the Boardman-to-Hemingway transmission line, it may terminate those projects and, as an alternative, develop additional generation facilities within areas where Idaho Power has available transmission capacity or pursue other more costly options to serve loads. Termination of a project carries with it the potential for a write-off of all or a significant portion of the costs associated with the project if state public utility commissions deny recovery of costs they deem imprudently incurred, which could negatively affect IDACORP's and Idaho Power's financial condition and results of operations.

Idaho Power’s business is subject to an extensive set of environmental laws, rules, and regulations, which could impact Idaho Power's operations and increase costs of operations, potentially rendering some generating units uneconomical to maintain or operate, and could increase the costs and alter the timing of major projects. A number of federal, state, and local environmental statutes, rules, and regulations relating to air quality, water quality, natural resources, and health and safety are applicable to Idaho Power's operations. 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. Some of these regulations are changing or subject to interpretation, and failure to comply may result in penalties or other adverse consequences. Environmental regulations have created the need for Idaho Power to install new pollution control equipment at, and may cause Idaho Power to perform environmental remediation on, its owned or co-owned facilities, often at a substantial cost. For instance, Idaho Power plans to install environmental control apparatus at its co-owned Jim Bridger power plant in 2015 and 2016 at a cost of approximately $120 million, and a second set of control apparatus in 2021 and 2022. Idaho Power expects that there will be other costs relating to environmental regulations, and those costs are likely to be substantial. Idaho Power is not guaranteed recovery of those costs. For instance, in December 2012 the Oregon Public Utility Commission disallowed in part cost recovery for certain environmental upgrades made to a coal plant by one of Idaho Power's Northwest region peer utilities, citing an insufficient cost analysis. If Idaho Power is similarly unable to recover in full its costs through the ratemaking process, such non-recovery would negatively impact IDACORP's and Idaho Power's financial condition and results of operations.

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, or the compliance costs Idaho Power would incur in connection with that legislation. Future changes in environmental laws or regulations governing emissions reduction may make certain electric generating units (especially coal-fired units) uneconomical and subject to shut-down, may 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. 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 generation or transmission facilities could be delayed, halted, or subjected to additional costs. At the same time, consumer preference for renewable or low greenhouse gas-emitting sources of energy could impact the desirability of generation from existing sources and require significant investment in new generation and transmission resources.

Relicensing of the Hells Canyon hydroelectric project and construction of the proposed 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 will result in a costly Endangered Species Act consultation for the two transmission projects and for any 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

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Species Act, Clean Air Act, Clean Water Act, and similar environmental laws may increase costs, the timing or ability to complete major projects, and reduce earnings and cash flows.

Factors contributing to lower hydroelectric generation can increase costs and negatively impact IDACORP's and Idaho Power's financial condition and results of operations. Idaho Power derives a significant portion of its power supply from its hydroelectric facilities. Because of Idaho Power’s heavy reliance on hydroelectric generation, snowpack, the timing of run-off, and the availability of water in the Snake River basin can significantly affect its operations. 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. When hydroelectric generation is reduced, Idaho Power must increase its use of more expensive thermal generating resources and purchased power; therefore, costs increase and opportunities for off-system sales are reduced, reducing earnings. Through its power cost adjustment mechanisms, Idaho Power expects to recover most of the increase in net power supply costs caused by lower hydroelectric generation. Recovery of the increased costs, however, may not occur until the subsequent power cost adjustment year, negatively affecting cash flows and liquidity.

Conditions imposed in connection with hydroelectric license renewals may require large capital expenditures, increase operating costs, reduce hydroelectric generation, and negatively affect IDACORP's or Idaho Power's results of operations and financial condition. For the last several years, Idaho Power has been engaged in an effort to renew its federal license for 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 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. Idaho Power may be unable to recover in full the costs of such an apparatus through rates, particularly given the magnitude of any potential impact on customer rates. Idaho Power also cannot predict the requirements that might be imposed during the relicensing process, the financial 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 negatively affect results of operations and financial condition.

IDACORP's and Idaho Power's operating results are subject to seasonal fluctuations, and unusually mild temperatures can impact their results of operations and financial condition. Electric power sales are generally seasonal, with demand in Idaho Power's service territory peaking during the hot summer months, with a secondary peak during the cold winter months. The loads required by irrigation customers in Idaho Power's service territory can also create significant seasonal changes in usage. When temperatures are relatively mild, loads are often lower as customers are not using electricity for heating and air conditioning purposes. Thus, unusually mild weather or the timing and extent of precipitation in the future could adversely impact IDACORP's and Idaho Power's results of operations and financial condition.

Complying with state or federal renewable portfolio standards could increase capital expenditures and operating costs and adversely affect IDACORP's and Idaho Power's results of operations and financial condition. 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. The cost of purchasing or generating power from renewable energy sources is often greater than

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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 negatively affect results of operations and financial condition.

Idaho Power’s reliance on coal and natural gas to fuel its non-hydroelectric power generation facilities exposes it to the risk of increased costs and reduced earnings. As part of its normal business operations, Idaho Power purchases coal 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 transportation availability, economic conditions, and changes in technology. Most of Idaho Power's coal supply arrangements are for coal originating in Wyoming and any disruption of coal production in, or transportation from, that region may cause Idaho Power to incur additional fuel supply costs or use alternative generation sources or wholesale market power purchases. Natural gas transportation to Idaho Power's natural gas plants is limited to one primary pipeline, presenting a heightened possibility of supply disruptions. Idaho Power is also exposed to the risk that its counterparties to fuel purchase arrangements will default on their obligations, causing Idaho Power to seek alternative sources of fuel or rely on other generation sources or wholesale market power purchases. Idaho Power may not be able to fully recover these increased costs through rates or its power cost adjustment mechanisms, which may adversely affect IDACORP's and Idaho Power's financial condition and results of operations.

Idaho Power’s generation, transmission, and distribution facilities are subject to numerous operational risks unique to it and its industry. Operating risks associated with Idaho Power's generation, transmission, and distribution facilities include equipment failures, volatility in fuel and transportation pricing, interruptions in fuel supplies, increased regulatory compliance costs, labor disputes, accidents and workforce safety matters, release of hazardous or toxic substances into the air or water, the failure of a hydroelectric facility, 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 those 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 for alternative fuels or wholesale market power purchases. Accidents, fires, explosions, system damage or dysfunction, and other unplanned events related to Idaho Power's infrastructure may expose Idaho Power to claims for personal injury or property damage. Further, the transmission system in Idaho Power's service territory is constrained, limiting the ability to transmit electric energy within the service territory and access electric energy from outside the service territory during high-load periods. The transmission constraints could result in failure to provide reliable service to customers and the inability to deliver energy from generating facilities to the power grid, or not being able to access lower cost sources of electric energy, which could have a negative effect on IDACORP's and Idaho Power's financial condition and results of operations.

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, most recently as a result of the European sovereign debt situation, generally resulting in a decrease in the availability of liquidity and credit for borrowers. In a volatile credit environment, Idaho Power may be unable to issue long-term indebtedness at reasonable interest rates or at all, 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 may 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 results of operations 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.

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 IDACORP's and Idaho Power's ability to operate and to complete capital projects, including its planned 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

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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 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.

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 IDACORP and Idaho Power may suffer economic losses. Idaho Power enters into transactions to hedge its positions in coal, natural gas, power, and other commodities, and enters into financial hedges. IDACORP and Idaho Power could recognize financial losses as a result of volatility in the market value of these contracts or if a counterparty fails to perform. The derivative instruments might not offset the underlying exposure being mitigated as intended, due to pricing inefficiencies or other terms of the derivative instruments, and any such failure to mitigate exposure could result in financial losses. Further, forecasts of future fuel needs and 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. As a result, risk management actions may adversely affect IDACORP’s and Idaho Power’s financial condition and results of operations.

Idaho Power could be subject to penalties and operational changes if it violates mandatory reliability and security requirements, which could adversely impact IDACORP's and Idaho Power's results of operations and financial condition. 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 in recent years notices 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 a negative effect on its and IDACORP’s results of operations and financial condition.

Federally mandated purchases of power from PURPA power projects, and integration of power generated from those projects into Idaho Power's system, may increase costs and decrease system reliability, and adversely affect Idaho Power's and IDACORP's results of operations and financial condition. 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, increasing power purchase costs. Further, balancing load and generation from Idaho Power's power generation portfolio is challenging, and Idaho Power expects that its operational costs will increase as a result of its efforts to integrate intermittent, non-dispatchable power from a large number of PURPA power projects. Recent efforts to obtain further authorization to curtail certain intermittent power sources during light-load times have been unsuccessful. Idaho Power anticipates that costs will escalate as the volume of wind and other intermittent power on Idaho Power's system increases, which may negatively affect IDACORP's and Idaho Power's results of operations and financial condition.

The performance of pension and postretirement benefit plan investments and other factors impacting plan costs and funding obligations could adversely affect IDACORP's and Idaho Power's financial condition and results of operations - primarily 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 plan costs and 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 inherently uncertain, and actual results could vary significantly from the estimates. Changes in demographics, including timing of retirements or changes in life expectancy assumptions, may also increase Idaho Power's plan costs and funding requirements. Future pension funding requirements and the timing of funding payments are also subject to the impacts of changes in legislation. Depending on the timing of contributions to the plans and Idaho Power's ability to recover costs through

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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.

As a holding company, IDACORP does not have its own operating income and must rely on the 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. 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 subsidiary's 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 may reduce or cease payment of dividends at any time. See Item 5 - "Market for Registrant's Common Equity, Related Stockholder Matters, and Issuer Purchases of Equity Securities" in this report for a further description of restrictions on IDACORP's and Idaho Power's payment of dividends.

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 and results of operations. 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. In recent years, tax settlements, as well as state regulatory mechanisms with tax-related provisions (such as Idaho Power's December 2011 settlement with the Idaho Public Utilities Commission), have significantly impacted IDACORP's and Idaho Power's results of operations. The outcome of ongoing and future income tax proceedings, or the state public utility commissions' treatment of those tax outcomes, could differ materially from the amounts IDACORP and Idaho Power record prior to conclusion of those proceedings, and the difference could negatively affect 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, which could have a negative effect on their financial condition and results of operations.

Employee workforce factors, including the impacts of an aging workforce with specialized utility-specific functions, could increase costs and adversely affect IDACORP's and Idaho Power's financial condition and results of operations. 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 the workforce. A unionization attempt that was launched in late-2012 failed, but does not prevent future unionization attempts. Idaho Power’s operations require a skilled workforce to perform specialized utility functions. Many of these positions, such as linemen, grid operators, and generation plant operators, require extensive, specialized training. Idaho Power expects that a significant portion of its skilled workforce will be retiring within the current decade, which will require Idaho Power to attract, train, and retain skilled workers to prevent a loss of institutional knowledge and avoid a skills gap. Without a skilled workforce, Idaho Power’s ability to provide quality service to its customers and meet regulatory requirements will be challenging, which could negatively affect earnings. The costs associated with attracting and retaining appropriately qualified employees to replace an aging and skilled workforce could have a negative effect on IDACORP's and Idaho Power's financial condition and results of operations.

IDACORP and Idaho Power are subject to costs and other effects of legal and regulatory proceedings, disputes, and claims. From time to time in the normal course of business IDACORP and Idaho Power are subject to various lawsuits, regulatory proceedings, disputes, and claims that could result in adverse judgments or 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. As an example, over the past decade Idaho Power has been a party to proceedings relating to high prices for electricity, energy shortages, and blackouts in California and in western wholesale markets during 2000 and 2001, which caused numerous purchasers of electricity in those markets to initiate proceedings seeking refunds or other forms of relief and the Federal Energy Regulatory Commission to initiate its own investigations. While Idaho Power has largely disposed of direct claims in those proceedings, the settlements and associated Federal Energy Regulatory Commission orders did not eliminate the potential for speculative "ripple claims," which involve potential claims for refunds from an upstream seller of power based on a finding that its downstream buyer was liable for refunds as a seller of power during the relevant period. Idaho Power's settlement payments in those proceedings have been relatively small to date, but the legal costs of defending the claims over the past decade have been substantial. In recent years, Idaho Power has also been a party to legal proceedings advanced by private

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parties relating to alleged violations of environmental laws at coal-fired plants. The legal costs and final resolution of matters in which IDACORP or Idaho Power are involved could have a negative effect on their financial condition and results of operations. Similarly, the terms of resolution could require the companies to change their business practices and procedures, which could also have a negative affect on their financial positions and results of operations.

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 negatively impact IDACORP's and Idaho Power's financial condition and results of operations. 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- or coal-fired power plants.

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. Despite the security measures in place, Idaho Power's facilities and systems could be vulnerable to security breaches, data leakage, or other similar events that could interrupt operations, 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 information technology and security 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. In such case, confidential and proprietary business, employee, or customer information could be compromised, exposing Idaho Power to liability and causing business disruptions, which could negatively affect Idaho Power's business operations and IDACORP's and Idaho Power's financial condition and results of operations.

Idaho Power's business and operations may be adversely affected by its inability to successfully implement current information technology projects. Idaho Power is currently undertaking several multi-year company-wide information technology solution upgrades intended to replace existing software and systems. These projects include a new customer information system, Idaho Power's SmartGrid initiative, and migration from Idaho Power's existing mainframe system to an open system. Idaho Power is also implementing systems to augment and improve its ability to pinpoint the sources of electric system outages, respond to them more quickly, and focus repair efforts. Implementation of these information systems and technology solutions is complex, expensive, and time consuming. If Idaho Power does not successfully implement the new systems and processes, or if the systems do not operate as intended or cause data or operational errors, it could result in substantial disruptions to Idaho Power's business, which could have a material adverse effect on IDACORP's and Idaho Power's results of operations and financial condition.

Changes in accounting standards or Securities and Exchange Commission rules may impact IDACORP's and Idaho Power's financial results and disclosures. The Financial Accounting Standards Board and the Securities and Exchange Commission may make changes to accounting standards that impact presentation and disclosures of financial condition and results of operations. Further, new accounting orders issued by the Federal Energy Regulatory Commission could significantly impact IDACORP's and Idaho Power's reported financial condition. Idaho Power meets conditions under generally accepted accounting principles to reflect the impact of regulatory decisions in its financial statements and to defer certain costs as regulatory assets until those costs are collected in rates, and to defer some items as regulatory liabilities. Idaho Power expects to recover its regulatory assets from customers through rates but recovery is subject to review by the regulatory bodies. If recovery of these amounts ceases to be probable, if Idaho Power determines that it no longer meets the criteria for applying regulatory accounting, or if accounting rules change to no longer provide for regulatory assets and liabilities, Idaho Power could be required to eliminate those regulatory assets or liabilities. Any of these circumstances could result in write-offs and have a material effect on IDACORP's and Idaho Power’s reported financial condition and results of operations.

ITEM 1B. UNRESOLVED STAFF COMMENTS

None.

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ITEM 2. PROPERTIES

Idaho Power's properties consist of the physical assets necessary to support its electricity business, which include electric generation, transmission, and distribution facilities, as well as coal assets that support one of its coal-fired generation plants. In addition to these physical assets, Idaho Power has rights-of-way and water rights that enable it to utilize its facilities. Idaho Power’s system is comprised of 17 hydroelectric generating plants located in southern Idaho and eastern Oregon, three natural gas-fired plants located in southern Idaho, and interests in three coal-fired steam electric generating plants located in Wyoming, Nevada, and Oregon. As of December 31, 2012, the system also includes approximately 4,851 pole miles of high-voltage transmission lines, 24 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 26,764 pole miles of distribution lines.

Idaho Power holds FERC licenses for all of its hydroelectric projects that are subject to federal licensing. Relicensing of Idaho Power’s hydroelectric projects is discussed in Item 7 - “MD&A – Regulatory Matters – Relicensing of Hydroelectric Projects.”

Idaho Power's hydroelectric projects and other owned and co-owned generating facilities and their nameplate capacities are listed below.



Project	Nameplate Capacity (kW)⁽¹⁾	License Expiration
Hydroelectric Projects:
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 (Hells Canyon Complex)	1,166,900	2005	⁽²⁾
Swan Falls	27,170	2042
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) ⁽³⁾	770,501
Valmy (coal-fired)⁽³⁾	283,500
Boardman (coal-fired)⁽³⁾⁽⁴⁾	64,200
Danskin (gas-fired)	270,900
Langley Gulch (gas-fired)	318,452
Bennett Mountain (gas-fired)	172,800
Salmon (diesel-internal combustion)	5,000
Total Steam and Other	1,885,353
Total Generation	3,594,398
⁽¹⁾ Actual generation capacity from a facility may be greater or less than the rated nameplate generation capacity.
⁽²⁾Licensed on an annual basis while the application for a new multi-year license is pending.
⁽³⁾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.
⁽⁴⁾ Pursuant to an Oregon Environmental Quality Commission plan and associated rules, the Boardman power plant is scheduled for cessation of coal-fired operations by December 31, 2020.

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Idaho Power's headquarters are located in Boise, Idaho, consisting of approximately 334,000 square feet of owned office space throughout the corporate campus. Idaho Power also leases approximately 84,000 square feet of office space in Boise for corporate, engineering, and administrative functions, and owns and leases approximately 468,000 square feet of office, operations, and warehouse space in various other locations throughout Idaho Power's service territory in Idaho and Oregon, excluding supportive offices located at generation facilities.

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. Substantially all of Idaho Power’s property is subject to the lien of its Mortgage and Deed of Trust and the provisions of its project licenses. 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.

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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 15, 2013, there were 11,898 holders of record of IDACORP common stock and the closing stock price was $46.73 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 deem 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, 2012, 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 $889 million and $794 million, respectively, at December 31, 2012. 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 $69 million, $60 million, and $58 million in 2012, 2011, and 2010, 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. On September 20, 2012, IDACORP's board of directors voted to increase the quarterly dividend, commencing with the dividend payable on November 30, 2012, to $0.38 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 2012 and 2011 as reported by the NYSE.



	2012						2011
Quarter	High		Low		Dividends paid per share		High		Low		Dividends paid per share
1st	$	42.89	$	39.66	$	0.33	$	38.72	$	36.14	$	0.30
2nd	42.22		38.17		0.33		40.38		37.65		0.30
3rd	44.03		41.00		0.33		40.71		33.88		0.30
4th	45.67		40.18		0.38		42.66		37.26		0.30

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During 2011, 2010, and 2009, Idaho Power paid dividends to its parent, IDACORP, in the amounts shown in Idaho Power's Consolidated Statements of Retained Earnings included in this report.

IDACORP, Inc. did not repurchase any shares of its common stock during the fourth quarter of 2012.

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, 2007, with beginning-of-period weighting of the peer group indices (based on market capitalization) and monthly compounding of returns.

Source: Bloomberg and EEI



	2007		2008		2009		2010		2011		2012
IDACORP	$	100.00	$	86.99	$	98.78	$	118.39	$	140.00	$	147.94
S&P 500	100.00		63.01		79.69		91.71		93.62		108.59
EEI Electric Utilities Index	100.00		74.10		82.03		87.80		105.35		107.55

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.

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ITEM 6. SELECTED FINANCIAL DATA



IDACORP, Inc.
SUMMARY OF OPERATIONS
(thousands of dollars, except per share amounts)
	2012			2011			2010			2009			2008
Operating revenues	$	1,080,662		$	1,026,756		$	1,036,029		$	1,049,800		$	960,414
Operating income	242,602			155,352			191,811			196,363			183,818
Net income attributable to IDACORP, Inc.	168,761			166,693			142,798			124,350			98,414
Diluted earnings per share from
continuing operations	3.37			3.36			2.95			2.51			2.17
Dividends declared per share	1.37			1.20			1.20			1.20			1.20

Financial Condition:
Total assets	$	5,319,516		$	4,960,609		$	4,238,727		$	4,022,845		$	3,653,308
Long-term debt (including current portion)	1,537,696			1,488,614			1,419,070			1,269,979			1,168,336

Financial Statistics:
Times interest charges earned:
Before tax ⁽¹⁾	3.27			2.35			2.65			2.88			2.47
After tax ⁽²⁾	2.97			2.97			2.66			2.59			2.23
Book value per share ⁽³⁾	$	35.07		$	33.18		$	31.01		$	29.17		$	27.76
Market-to-book ratio ⁽⁴⁾	124		%	128		%	119		%	110		%	106		%
Payout ratio⁽⁵⁾	41		%	36		%	41		%	45		%	55		%
Return on year-end common equity ⁽⁶⁾	9.6		%	10.1		%	9.3		%	8.9		%	7.6		%

The financial statistics listed above are calculated in the following manner:
⁽¹⁾The sum of interest on long-term debt, other interest expense excluding AFUDC 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.

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

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. Also refer to "Cautionary Note Regarding Forward-Looking Statements" and Part 1 - Item 1A - "Risk Factors" in this report for important information regarding forward-looking statements made in this MD&A and elsewhere in this report.

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 501,000 general business customers as of December 31, 2012. 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 experiences its highest retail energy sales during the summer irrigation and cooling season, with a lower peak in the winter that generally results from heating demand. IDACORP’s and Idaho Power’s financial condition are also affected by regulatory decisions through which Idaho Power seeks to recover its costs on a timely basis and 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 Services Co., which is the former limited partner of, and successor by merger to, IDACORP Energy L.P., a marketer of energy commodities that 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.

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EXECUTIVE OVERVIEW

Brief Overview of 2012 Results

IDACORP's 2012 earnings per diluted share of $3.37 were one cent above its 2011 earnings per diluted share of $3.36 and reflect the impacts of general rate increases that went into effect during 2011 and 2012 and increased irrigation sales volumes. Idaho Power's 2012 return on year-end equity in the Idaho jurisdiction exceeded 10.5 percent, triggering the sharing mechanism in Idaho Power's December 2011 settlement agreement, discussed below, and resulting in a $21.8 million reduction to operating income, reflecting earnings to be shared with Idaho customers to reduce rates. For purposes of comparison, during 2011 IDACORP's earnings were significantly impacted by the recognition of $56.9 million in tax benefits relating to prior tax years. The 2011 tax benefit, combined with operating results, triggered a similar sharing mechanism in Idaho during 2011 that reduced 2011 operating income by $47.4 million. A more specific discussion of the factors influencing IDACORP's and Idaho Power's results for 2012, including a quantification of their respective impacts, is included below in this MD&A.

2012 Accomplishments and 2013 Initiatives

IDACORP’s business strategy emphasizes Idaho Power as IDACORP’s core business. For the past several years, Idaho Power has been implementing its three-part strategy of responsible planning, responsible development and protection of resources, and responsible energy use to ensure adequate energy supplies. This strategy is described in Part I, Item 1 - "Business" of this report. Examples of Idaho Power's achievements during 2012 under its three-part business strategy include:


•	commencement of the Langley Gulch power plant's commercial operation, ahead of schedule and within budget;


•	continued execution of Idaho Power's purposeful regulatory strategy, which resulted in approval of Idaho Power's requests for recovery of, and a return on, Idaho Power's investment in the Langley Gulch power plant, a general rate increase in Idaho on January 1, 2012, and the issuance of an order by the IPUC pertaining to PURPA-related matters;


•	continued progress toward the permitting of the Boardman-to-Hemingway and Gateway West 500-kV transmission projects and execution of associated cost-sharing agreements with PacifiCorp and the Bonneville Power Administration (BPA);


•	continued progress toward achieving IDACORP's previously adopted dividend policy; during 2012 the IDACORP Board of Directors voted to increase the quarterly dividend twice, resulting in an aggregate increase from $0.30 per share quarterly to $0.38 per share quarterly, or nearly 27 percent;


•	receipt of a 30-year license from the FERC for the continued operation of the Swan Falls hydroelectric facility;


•	ranking in the top quartile of the 126 largest utilities in the country for customer satisfaction in the J.D. Power and Associates 2012 Electric Utility Residential Customer Satisfaction Study;


•	recognition for Highest Customer Satisfaction with Business Electric Service in the Western U.S. among Midsize Utilities in a Tie in the J.D. Power and Associates 2012 Electric Utility Business Customer Satisfaction Study of more than 90 utility brands across the U.S.; and


•	ranking among the "40 Best Energy Companies" by Public Utilities Fortnightly.

One of management's primary goals during 2011 and 2012 was to reduce Idaho Power's regulatory lag, which results from the period of time between making an investment or incurring an expense and earning a return and recovering that investment or expense. Management focused heavily on implementation of new rates and approval of regulatory mechanisms during 2011 and 2012. As Idaho Power transitions to 2013 and into 2014 it will focus on optimizing operations and managing growth in expenses in an effort to achieve or exceed a rate of return reflective of those allowed by the IPUC and OPUC. Management anticipates that the IDACORP Board of Directors will, when appropriate, take steps during 2013 in furtherance of the dividend policy it adopted in November 2011, which provides for a target long-term dividend payout ratio of between 50 and 60 percent of sustainable IDACORP earnings. Other specific matters that the companies expect will require management's focus and attention in 2013 include continued efforts toward permitting of the Boardman-to-Hemingway and Gateway West 500-kV transmission projects, completion and filing of the 2013 integrated resource plan (IRP), implementation of a significant new customer relations and billing system, and continued work toward federal relicensing of the Hells Canyon Complex (HCC) hydroelectric facility.

For 2013, in addition to its specific projects, Idaho Power has established a number of organizational initiatives, including the following:


•	actively manage through the challenging economic environment by optimizing business practices, maintaining capital liquidity, and maintaining credit ratings;


•	continue to emphasize innovative approaches to regulatory strategy;

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•	promote economic development through collaboration with the states of Idaho and Oregon to attract new businesses that fit Idaho Power's resource and load profile mix;


•	focus on operational excellence by matching resources to customer loads, managing the impacts of environmental regulations, maintaining Idaho Power's hydroelectric base, enhancing power quality and reliability, and customer satisfaction; and


•	maintain an enterprise safety culture and an effective and motivated workforce, address workforce attrition, and enhance succession planning and training programs in anticipation of a significant number of retirements in the next few years.

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 and Expense Management; Support from Regulatory Settlement: The price that Idaho Power is authorized to charge for its electric service is a critical factor in determining IDACORP's and Idaho Power's results of operations and financial condition. Because of the significant impact of ratemaking decisions, and in furtherance of its goal of advancing a purposeful regulatory strategy, Idaho Power has focused on timely recovery of its costs through filings with the company's regulators, and the prudent management of expenses and investments after receiving rate orders from the IPUC and OPUC. Effective implementation of Idaho Power's regulatory strategy is particularly important in a climate of slow economic recovery that continues to put pressure on regulators to limit rate increases or otherwise take actions to limit the potential adverse impact of rate increases on customers.

The number of regulatory filings and activity during the period from 2010 to 2012 exceeded historical averages, driven by Idaho Power's regulatory strategy. The rate orders Idaho Power has received in recent years and their associated mechanisms have decreased the likelihood that Idaho Power would seek rate relief through a general revenue rate case during 2013, and instead focus on optimizing business operations and processes. Particularly notable regulatory developments that have impacted or that IDACORP and Idaho Power expect will impact 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:



Proceeding	Description	Amount and Timing of Rate Increase/Decrease
Idaho General Rate Case Settlement	General rate case, requesting an increase in Idaho-jurisdiction base rates	IPUC approved a $34.0 million increase in rates, effective January 1, 2012
Langley Gulch Power Plant	Request for recovery of and return on Idaho Power's investment in the Langley Gulch power plant, including operating costs	IPUC approved a $58.1 million increase in rates, effective July 1, 2012; OPUC approved a $3.0 million increase in rates effective October 1, 2012
Revenue Sharing	Rate adjustment pursuant to January 2010 and December 2011 settlement agreements⁽¹⁾	IPUC approved a $27.1 million decrease in rates, effective only for the period from June 1, 2012 to May 31, 2013⁽¹⁾
Oregon General Rate Case Settlement	General rate case, requesting an increase in Oregon-jurisdiction base rates	OPUC approved a $1.8 million increase in rates, effective March 1, 2012

⁽¹⁾

The rate change for the Idaho PCA was partially offset by the revenue-sharing order issued pursuant to the January 2010 and December 2011 settlement agreements. Idaho Power's revenue-sharing arrangements had two components: (a) a PCA mechanism component, which reduced net rates by $27.1 million, and (b) a pension balancing account component, which resulted in a $20.3 million net reduction to Idaho Power's pension regulatory asset (reducing Idaho customers' future obligation). Idaho Power recorded the $27.1 million revenue reduction and $20.3 million pension regulatory asset reduction in 2011.

In addition to the rate changes listed in the table above, in December 2011 the IPUC approved a settlement stipulation, separate from the Idaho general rate case settlement, that permits Idaho Power to amortize additional accumulated deferred investment tax credits (ADITC) to help achieve a minimum 9.5 percent rate of return on year-end equity in the Idaho jurisdiction (Idaho ROE) in 2012, 2013, and 2014, subject to prescribed limits and conditions. The settlement stipulation also provides for the potential sharing between the company and customers of Idaho-jurisdictional earnings in excess of specified levels of Idaho ROE. The specific terms of the settlement stipulation are described in "Regulatory Matters" in this MD&A and in Note 3 - "Regulatory Matters" to the consolidated financial statements included in this report. While providing no assurance that Idaho Power will obtain a 9.5 percent Idaho ROE in any of the years, IDACORP and Idaho Power believe the ability to amortize additional ADITC provides an element of earnings stability for 2013 and 2014. Because its 2012 Idaho ROE exceeded 9.5

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percent, Idaho Power did not amortize additional ADITC in 2012 under the settlement stipulation. Based on the terms of the December 2011 settlement stipulation, Idaho Power recorded during 2012 a $7.2 million provision against current revenues, as a benefit to Idaho customers in the form of a future rate reduction, and an additional $14.6 million of pension expense, which will benefit Idaho customers by reducing the amount of deferred pension expense that will be collected from customers in the future. Idaho Power recorded $47.4 million for the impact of similar sharing mechanisms in 2011.

Economic Conditions and Customer/Load Growth: When seeking to predict utility load changes for both short-term load forecasts and long-term infrastructure planning purposes, Idaho Power monitors a number of economic indicators, including employment rates, growth in customer numbers, and foreclosure rates and other housing-related data on both a national scale and within Idaho Power's service territory. Economic conditions can impact consumer demand for electricity, collectability of accounts, the volume of off-system sales, and the need to purchase power to meet demand.

Since 2008, economic conditions in Idaho Power's service territory have been relatively weak. However, a number of improvements in economic conditions have occurred over the last few months. After peaking at 10.0 percent in early 2011, the service area unemployment rate fell to 8.4 percent by the end of 2011 and reached 6.2 percent by the end of 2012, according to Idaho Department of Labor data. The housing market in Idaho Power's service territory has improved when measured by foreclosure rates and the available supply and pricing of housing. Idaho Power also continues to experience customer growth, and a number of businesses have constructed facilities in Idaho Power's service territory. For the year ended December 31, 2012, the customer growth rate in Idaho Power's service territory was approximately 1.1 percent—roughly twice the growth rate of the prior two years. However, by comparison, for the 20-year period ending in 2011 the average annual customer growth rate in Idaho Power's service territory was 2.6 percent. Idaho Power predicts that customer growth within its service territory in the next few years will be positive, though at a rate below the 20-year historical annual average.

In light of the uncertainty of the timing and pace of economic recovery in its service territory, and general underlying concerns remaining about the strength and pace of recovery of the economy and financial markets, 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. As the customer growth rate and demand have potentially stabilized, Idaho Power is transitioning from an emphasis on large capital projects, particularly generation, to an emphasis on maintaining and replacing aging assets while planning and building for the future. Idaho Power plans to control operating and maintenance and capital costs through process and project reviews and through process improvement initiatives, and by empowering employees to identify means to reduce costs, build efficiencies, and enhance individual and enterprise performance. These actions are particularly important at a time when customer growth is relatively low and new rates have been approved and implemented.

In December 2012, Idaho Power filed an application with the IPUC requesting the temporary suspension during 2013 of two demand response programs that Idaho Power had previously implemented to reduce peak-hour loads. Included was a discussion of the results of preliminary studies conducted in connection with Idaho Power's 2013 IRP, including a load and resource balance for the 2013 to 2032 period. After application of a number of assumptions, under a scenario that excludes demand response programs and power capacity from the proposed Boardman-to-Hemingway 500-kV transmission line, the peak-hour load and resource balance indicates no peak-hour load deficit until 2016, which under those assumptions the need for near-term peak-hour resources like demand response programs or new near-term supply-side resources does not exist. While these results preliminarily suggest that new generation projects are not necessary in the near-term, Idaho Power has not completed its analysis and will not have completed its analysis until the publication of its 2013 IRP in mid-2013. The 2013 IRP will describe the estimated timing of potential generation and transmission projects.

Weather Conditions and Associated Impacts: Weather and agricultural growing conditions 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, irrigation customers use electricity to operate irrigation pumps. For instance, the 2.6-percent increase in energy use by general business customers during 2012 compared to 2011 was largely attributable to agricultural growing conditions from April through June that required above average use of irrigation equipment. As noted above, Idaho Power also has tiered rates and seasonal rates, which contribute to increased revenues during higher-load periods, most notably the third quarter of each year when customer demand is typically at its peak. On July 12, 2012, Idaho Power achieved a record load demand of 3,245 MW. The previous record load demand was 3,214 MW, set on June 30, 2008.

Idaho Power's hydroelectric facilities comprise nearly one-half of Idaho Power's nameplate generation capacity. The availability and volume 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. Idaho Power expects

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hydroelectric generation during 2013 to be in the range of 6.0 to 8.0 million megawatt-hours (MWh), based on reservoir storage levels and forecasted weather conditions as of the date of this report, compared to actual generation of 8.0 million MWh in 2012, 10.9 million MWh in 2011, and 7.3 million MWh in 2010. Median annual hydroelectric generation is 8.6 million MWh. When hydroelectric generation is reduced Idaho Power must rely on more expensive generation sources and purchased power; however, most of the increase in power supply costs is deferred as a regulatory asset and collected from customers through its Idaho and Oregon power cost adjustment (PCA) mechanisms described later in this MD&A. Conversely, in periods of greater hydroelectric generation most of the resulting decrease in power supply costs that typically occurs is returned to customers through the PCA mechanisms.

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. Conversely, when hydroelectric generating conditions are poor, wholesale market prices may be higher due to lower supply, but Idaho Power would have less surplus energy available for sale into the wholesale markets. Again, much of the adverse or favorable impact of these costs is addressed through the PCA mechanisms.

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. Operation of Idaho Power's newly constructed Langley Gulch power plant has increased Idaho Power's use of natural gas as a generation fuel, 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 obligated to purchase power from some 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 (such as wind energy) into Idaho Power's portfolio also creates a number of complex operational risks and challenges that Idaho Power is working to address, including through evaluation of the results of a recent comprehensive wind integration study. Notably, integration of these sources of power into Idaho Power's portfolio does not eliminate Idaho Power's need to construct facilities and infrastructure that provide reliable power. For instance, at the time Idaho Power reached its all-time system peak demand of 3,245 MW on July 12, 2012, wind resources on Idaho Power's system, representing roughly 500 MW of capacity, were contributing only 14 MW of power due to lack of wind. Increases in federally mandated PURPA power purchases were a significant driver of increased power purchase costs during 2012 and will likely continue to push power purchase costs, and correspondingly, customer rates, higher.

The Idaho and Oregon PCA mechanisms mitigate in large part the potential adverse impacts to Idaho Power of fluctuations in Idaho Power's power supply costs, including 100-percent of the Idaho-jurisdiction PURPA power purchase 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, including FERC and North American Electric Reliability Corporation (NERC) reliability requirements. 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 cease operating certain power generation plants. For instance, the Boardman coal-fired power plant, in which Idaho Power owns a 10-percent interest, is scheduled to cease coal-fired operations by the end of 2020, the decision for which was driven in large part by the substantial cost of environmental controls. Idaho Power expects to spend a considerable amount on environmental compliance and controls in the next decade. As legislation and regulations concerning

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greenhouse gas emissions develop, Idaho Power assesses, when and to the extent determinable, the potential impact on the costs to operate its power generation facilities, as well as the willingness or ability of joint owners of power plants to fund any required pollution control equipment upgrades in lieu of early plant retirements. For instance, Idaho Power recently concluded cost studies and scenario analyses to assess the potential future investments necessary for the continued operation of the Jim Bridger and Valmy coal-fired generation facilities. Idaho Power published the results of the study with its IRP update filed with the OPUC in February 2013, concluding that planned investments in environmental controls at the plants are appropriate.

Other Notable Matters and Areas of Focus

Pension Plan Funding: From 2010 to 2012 Idaho Power contributed $123 million to its defined benefit pension plan. In May 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. While Idaho Power does not anticipate that any cash contributions will be required in 2013, it does expect to make additional significant cash contributions to the pension plan in the future. Idaho Power defers pension costs related to its Idaho jurisdiction until those costs are recovered through rates. While the IPUC's authorization to increase the annual recovery has mitigated in large part the adverse impacts of the contributions, the magnitude of the contributions relative to the annual cost recovery creates a lag between the timing of expenditures and their recovery, which impacts IDACORP's and Idaho Power's cash flows. While Idaho Power does not, as of the date of this report, have an expected date to request from regulators an additional increase in cost recovery, it may determine to do so if future contributions continue to be similar in magnitude to those made in recent years.

Water Management and Relicensing of the Hells Canyon Hydroelectric Project: Because of Idaho Power's reliance on stream flow 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 HCC, its largest hydroelectric generation source, and recently received a 30-year license renewal from the FERC for its 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 the HCC. However, 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 access to wholesale markets. Its most notable projects in progress include the proposed Boardman-to-Hemingway and Gateway West 500-kV transmission projects. In January 2012, Idaho Power entered into cost-sharing arrangements with third parties for the permitting phases of both projects. Construction of these projects cannot commence until all federal, state, and local regulatory requirements are met. Based on Idaho Power's assessment of the status and future milestones for the Boardman-to-Hemingway project, Idaho Power has determined that an in-service date prior to 2018 is unlikely.

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Summary of 2012 Financial Results

The following is a summary of Idaho Power's net income, net income attributable to IDACORP, and IDACORP's earnings per diluted share for the years ended December 31, 2012, 2011, and 2010 (in thousands, except earnings per share amounts):



	Year Ended December 31,
	2012		2011		2010
Idaho Power net income	$	168,168	$	164,750	$	140,634
Net income attributable to IDACORP, Inc.	$	168,761	$	166,693	$	142,798
Average outstanding shares – diluted (000’s)	50,010		49,558		48,340
IDACORP, Inc. earnings per diluted share	$	3.37	$	3.36	$	2.95

The following table presents a reconciliation of net income attributable to IDACORP, Inc. for 2011 to 2012 (items are in millions and are before tax unless otherwise noted):




Net income attributable to IDACORP, Inc. - December 31, 2011					$	166.7
Change in Idaho Power net income before taxes:
Rate and other regulatory changes, including power cost adjustment, pension expense
recovery, and fixed cost adjustment mechanisms		$	65.2
Changes in sales volumes		16.1
Change in payroll-related expenses		(6.8		)
Change in pension expense funded through rate increases		(5.1		)
Increased depreciation expense, property tax, and other		(8.7		)
Increase in Idaho Power operating income prior to sharing mechanisms		60.7
Greater pension expense in 2011 than in 2012 as a result of sharing mechanisms	5.7
Greater revenue sharing in 2011 than in 2012	19.9
Increase in operating income as a result of sharing mechanisms		25.6
Increase in Idaho Power operating income		86.3
Decrease in allowance for funds used during construction (AFUDC)		(4.5		)
Other net decreases		(1.0		)
Change in income tax expense		(22.1		)
Increase in Idaho Power net income prior to effects of tax method changes and related
examination settlements		58.7
Net decrease in tax method changes and related examination settlements		(55.3		)
Total increase in Idaho Power net income					3.4
Other net decreases (net of tax)					(1.3		)
Net income attributable to IDACORP, Inc. - December 31, 2012					$	168.8

IDACORP's net income was $168.8 million in 2012, an increase of $2.1 million compared to 2011. IDACORP's 2012 results reflect an $86.3 million increase in operating income at Idaho Power compared to 2011, which was largely driven by increases in rates and higher irrigation sales volumes. This increase was substantially offset by the net impact of a tax method change and favorable IRS examination settlements recorded in 2011.

General rate increases implemented in the first quarter of 2012, a July 2012 rate increase related to Idaho Power's new Langley Gulch power plant, and other rate changes combined to increase operating income by $65.2 million when compared to 2011. Higher sales volumes, driven primarily by a warmer, drier spring in 2012 that caused significant increases in irrigation usage when compared with the prior year, increased operating income by $16.1 million. As a result of an IRS examination settlement reached in 2011, Idaho Power recognized approximately $56.9 million of previously unrecognized tax benefits related to a uniform capitalization method agreement with the IRS for tax years 2009 and prior.

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As a result of the impact on 2012 earnings of the rate and sales volume increases described above, Idaho Power recorded a total of $21.8 million related to a December 2011 settlement agreement with the IPUC, which required sharing with customers of a portion of 2012 Idaho-jurisdiction earnings exceeding a specified return on year-end equity. Of the total, $14.6 million was recorded as additional pension expense, which will benefit Idaho customers by reducing the amount of deferred pension expense that will need to be collected from customers in the future, and $7.2 million was recorded as a provision against current revenues to be refunded to customers through a future rate reduction. In 2011, Idaho Power recorded $20.3 million of additional pension expense and a $27.1 million provision against revenues to be refunded to customers under similar agreements. The table below summarizes the effect of the sharing mechanisms on operating income between 2012 and 2011.



Effect of Sharing on Operating Income
	2012			2011			Variance
Provision against current revenue as a result of sharing	$	(7.2	)	$	(27.1	)	$	19.9
Additional pension expense funded through sharing	(14.6		)	(20.3		)	5.7
Total	$	(21.8	)	$	(47.4	)	$	25.6

Key Operating and Financial Metrics for 2013

IDACORP’s and Idaho Power’s outlook for 2013 full year metrics as of the date of this report are as follows:



	2013 Estimate	2012 Actual
Idaho Power Operating & Maintenance Expense (millions)	$340-$350	$	349
Idaho Power Additional Amortization of ADITC (millions)	Less than $5	None
Idaho Power Capital Expenditures, excluding AFUDC (millions)	$245-$255	$	228
Idaho Power Hydroelectric Generation (million MWh)	6.0-8.0	8.0

The estimated hydroelectric generation range is based on reservoir storage levels and forecasted weather conditions as of the date of this report.

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, 2012. In this analysis, the results for 2012 are compared to 2011 and the results for 2011 are compared to 2010.

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,
	2012		2011		2010
General business sales	14,085		13,734		13,513
Off-system sales	2,183		3,635		1,982
Total energy sales	16,268		17,369		15,495
Hydroelectric generation	7,956		10,937		7,344
Coal generation	5,227		4,820		6,864
Natural gas and other generation	676		138		160
Total system generation	13,859		15,895		14,368
Purchased power	3,670		2,751		2,401
Line losses	(1,261	)	(1,277	)	(1,274	)
Total energy supply	16,268		17,369		15,495

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Sales Volume and Generation: In 2012, general business sales volume increased by 0.4 million MWh, mostly related to increased irrigation customer usage compared to the prior year. Off-system sales volume decreased by 1.5 million MWh in 2012 as decreases in output from hydroelectric resources and a small increase in customer load decreased surplus power available for sale.

Hydroelectric generation comprised 57 percent of Idaho Power’s total system generation during 2012. Hydroelectric generation in 2012 was 93 percent of the annual median generation of 8.6 million MWh, which is based on hydrologic conditions for the period 1928 through 2011 and adjusted to reflect the current level of water resource development. The 3.0 million MWh decrease in hydroelectric generation in 2012 compared to 2011 was primarily due to lower than normal hydroelectric generating conditions. The 3.6 million MWh increase in hydroelectric generation in 2011 compared to 2010 was due largely to favorable hydroelectric generating conditions.

The decrease in hydroelectric generation during 2012 led to an increased utilization of coal-fired and natural-gas fired generation. The commencement of operations of the Langley Gulch natural gas-fired power plant in the summer of 2012 allowed for less reliance on purchased power to replace the decreased hydroelectric generation.

Idaho Power’s system is dual peaking, with the larger peak demand occurring in the summer. During 2012, 2011, and 2010, to reduce the magnitude of peak demands, Idaho Power utilized a number of demand response and energy efficiency programs. On July 12, 2012, Idaho Power achieved a record load demand of 3,245 MW. 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 through purchase contracts (from which power may not be available when needed 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,
	2012			2011			2010
Revenue
Residential	$	431,555		$	405,982		$	400,607
Commercial	241,519			220,962			231,440
Industrial	145,054			140,701			138,394
Irrigation	137,424			104,635			110,555
Total	955,552			872,280			880,996
Provision for sharing	(7,151		)	(27,099		)	—
Deferred revenues ⁽¹⁾	(10,636		)	(10,636		)	(10,625		)
Total general business revenues	$	937,765		$	834,545		$	870,371
MWh
Residential	5,039			5,146			4,967
Commercial	3,865			3,815			3,763
Industrial	3,133			3,100			3,076
Irrigation	2,048			1,673			1,707
Total	14,085			13,734			13,513
Customers at year-end
Residential	416,020			411,487			408,754
Commercial	65,920			65,226			64,647
Industrial	119			121			125
Irrigation	19,045			18,736			18,547
Total	501,104			495,570			492,073

⁽¹⁾ As part of its January 30, 2009 general rate case order, the IPUC allowed Idaho Power to recover AFUDC for the HCC 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.

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Changes in rates and changes in customer demand 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, that impacted revenues over the last three years.



		Estimated Annualized $ Impact (millions)
	Effective Date
Description	Effective Date
2010 Idaho settlement agreement	6/1/2010	89
2010 Idaho PCA	6/1/2010	(147	)
2010 Idaho pension expense recovery	6/1/2010	5
2011 Idaho PCA	6/1/2011	(40	)
2011 Idaho pension expense recovery	6/1/2011	12
2011 Idaho general rate case settlement agreement	1/1/2012	34
2012 Idaho PCA	6/1/2012	43
2012 Idaho non-AMI meter depreciation	6/1/2012	(11	)
2012 Idaho Langley Gulch	7/1/2012	58
2012 Oregon Langley Gulch	10/1/2012	3

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. Rates are also seasonally adjusted and based on a tiered rate structure that provides for higher rates during peak load periods. These seasonal and tiered rate structures contribute to seasonal fluctuations in revenues and earnings. Boise, Idaho weather-related information for the last three years is included in the table that follows.



	Year Ended December 31,
	2012	2011	2010	Normal
Heating degree-days⁽¹⁾	4,723	5,554	5,078	5,514
Cooling degree-days ⁽¹⁾	1,274	1,076	914	942
⁽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 - 2012 Compared to 2011: General business revenue increased $103.2 million in 2012 compared to 2011. The factors affecting general business revenues are discussed below.

• Rates. Rate changes, including those shown in the table above, combined to increase general business revenue by $73.5 million in 2012 compared to 2011. The revenue impact of several of these rate changes was directly offset by associated changes in operating expenses. For example, Idaho-jurisdiction pension expense recovery rate changes were fully offset by increased pension expense.

•

Sharing. A part of the increase in 2012 revenue resulted from revenue sharing mechanisms associated with two Idaho regulatory agreements that provide for the sharing of Idaho-jurisdiction earnings exceeding a specified Idaho ROE. The amount to be shared through future rate reduction is recorded as a current reduction to general business revenue. Reductions of $7.2 million and $27.1 million were recorded in 2012 and 2011, respectively, resulting in a net increase to general business revenue of $19.9 million in 2012. The smaller amount recorded in 2012 when compared with the prior year is partially due to changes in the terms of the mechanism in place each year, described in "Regulatory Matters" in this MD&A and in Note 3 - "Regulatory Matters" to the consolidated financial statements included in this report.

• Usage. For 2012, higher summer usage per customer increased general business revenue $13.7 million compared to 2011. Irrigation usage per customer was 20.9 percent higher for 2012 when compared with 2011 due to agricultural growing conditions, including warm temperatures that allowed for the earlier planting of crops, and lower relative springtime precipitation, which resulted in greater electricity use to operate irrigation pumps.

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•	Customers. Termination of service to Hoku Materials, Inc. (Hoku) during 2012 under an electric service agreement, offset by only moderate customer growth, decreased general business revenues by $3.9 million. Customer growth from 2011 to 2012 was 1.1 percent.

In March 2009, the IPUC approved an electric service agreement between Idaho Power and Hoku, to provide electric service to Hoku’s polysilicon production facility then under construction in Idaho. The initial term of the agreement was four years beginning December 1, 2009, with a maximum demand obligation during the initial term of 82 MW. In connection with an overdue invoice for electric service, in February 2012 Idaho Power, Hoku, and the IPUC Staff filed with the IPUC a settlement stipulation to amend the electric service agreement, and on March 15, 2012, the IPUC approved the stipulation revising the contract. As a result of Hoku's failure to remain timely in payments under the revised agreement, Idaho Power terminated its provision of electric service under the revised agreement in May 2012. Idaho Power applied a $2 million deposit to Hoku's April, May, and June 2012 invoices under the revised agreement and fully exhausted the deposit required by the revised agreement. For full year 2012 and prior to termination of service, Idaho Power had anticipated contract payments of $5.4 million that are unaffected by the PCA mechanism and $6.8 million of revenues that are affected by and flow through the PCA mechanism, for a total of $12.2 million. As a result of termination of service and non-payment, Idaho Power recognized $6.6 million of full year 2012 revenues that are unaffected by the PCA mechanism and no revenues that are affected by and flow through the PCA mechanism. The impact of non-payment and associated decreases in revenue on 2012 net income was tempered in part by a decrease in costs Idaho Power would have incurred in connection with the provision of service to Hoku and the impact of the PCA mechanism.

General Business Revenues - 2011 Compared to 2010: General business revenue decreased $35.8 million in 2011 compared to 2010. The factors affecting general business revenues are discussed below.

• Rates. Rate changes noted in the table above combined to reduce general business revenue by $38.8 million in 2011 as compared to 2010. The $10.5 million decline in revenue from commercial customers in 2011 relative to 2010, notwithstanding an increase in usage, was 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.

•

Sharing. Much of the decrease in 2011 revenue resulted from revenue sharing mechanisms associated with Idaho regulatory agreements that provide for the sharing of Idaho-jurisdiction earnings exceeding a specified Idaho ROE. The amount shared through rate reduction was recorded as a reduction to general business revenue. A reduction of $27.1 million was recorded in 2011. No such amount was recorded in 2010.

• Usage. Higher usage per customer in 2011 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.

• Customers. Changes related to the Hoku contract discussed above, along with a small increase in customer count, increased general business revenues by $16.6 million. Customer growth from 2010 to 2011 was 0.7 percent.

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,
	2012		2011		2010
Revenue	$	61,534	$	101,602	$	78,133
MWh sold	2,183		3,635		1,982
Revenue per MWh	$	28.19	$	27.95	$	39.42

Off-System Sales - 2012 Compared to 2011: Off-system sales revenue decreased by $40.1 million, or 39 percent, in 2012 as compared to 2011, as a result of lower volumes. Sales volumes decreased by 40 percent due to lower output from hydroelectric plants (as a result of less favorable snow pack and spring season run-off) and a small increase in load needs when compared with 2011.

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Off-System Sales - 2011 Compared to 2010: Off-system sales revenue increased $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.

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



	Year Ended December 31,
	2012		2011		2010
Transmission services, facility rental and other	$	50,126	$	48,918	$	40,364
Energy efficiency	27,300		37,663		44,184
Total	$	77,426	$	86,581	$	84,548

Other Revenues - 2012 Compared to 2011: Other revenues decreased $9.2 million in 2012 as compared to 2011, mainly due to:

•

a decrease in energy efficiency revenues of $10.4 million, primarily due to demand response incentive payments to customers, which had been treated as an energy efficiency expense and recovered through the energy efficiency rider in 2011 and prior, were recorded as purchased power expense and recovered through the PCA mechanism during 2012, as discussed in Note 3 - "Regulatory Matters" to the consolidated financial statements included in this report; and


•	an increase of $1.7 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, 2011 and October 1, 2012.

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.

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

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



	Year Ended December 31,
	2012		2011		2010
Expense
PURPA contracts	$	117,618	$	90,251	$	56,022
Other purchased power (including wheeling)	79,317		73,085		87,747
Total purchased power expense	$	196,935	$	163,336	$	143,769
MWh purchased
PURPA contracts	1,961		1,495		910
Other purchased power	1,709		1,256		1,491
Total MWh purchased	3,670		2,751		2,401
Cost per MWh from PURPA contracts	$	59.98	$	60.36	$	61.56
Cost per MWh from other sources	$	46.41	$	58.19	$	58.85
Weighted average - all sources	$	53.66	$	59.37	$	59.88

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The purchased power cost per MWh often exceeds the off-system sales revenue per MWh because Idaho Power generally needs to purchase more 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 transaction prices.

Purchased Power - 2012 Compared to 2011: Purchased power expense increased $33.6 million, or 21 percent, in 2012 as compared to 2011, principally due to additional PURPA wind generation that came on-line and less favorable hydroelectric generating conditions. MWh purchased through PURPA contracts increased 31 percent, contributing to a $27.4 million increase in PURPA power purchase expense in 2012 compared to 2011, while MWh purchased through other sources increased 36 percent. Overall MWh purchases increased due to less favorable hydroelectric generating conditions decreasing Idaho Power's volume of self-generated power. The increase in MWh purchased was partially offset by a reduction in expense per MWh purchased. Average wholesale electricity prices were lower in 2012 relative to 2011 as a result of lower natural gas prices in the region, which reduced generation costs and, correspondingly, power prices. In addition, $14.5 million of demand response program charges were recorded as purchased power expense in 2012. These costs had been treated as an energy efficiency expense and recovered through the energy efficiency rider in 2011 and prior.

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 hydroelectric conditions. Wholesale market purchases were also down due to lower system loads resulting from relatively mild weather.

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,
	2012		2011		2010
Expense
Coal	$	134,501	$	119,845	$	146,927
Natural gas and other	24,912		11,697		12,746
Total fuel expense	$	159,413	$	131,542	$	159,673
MWh generated
Coal	5,227		4,820		6,864
Natural gas and other	676		138		160
Total MWh generated	5,903		4,958		7,024
Cost per MWh
Coal	$	25.73	$	24.86	$	21.41
Natural gas and other	36.85		84.76		79.66
Weighted average, all sources	27.01		26.53		22.73

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 (such as the cost per MWh for natural gas and other in 2012 compared to 2011 and 2010) are noticeably impacted by these fixed charges when generation output is substantially different between the two periods.

Fuel Expense - 2012 Compared to 2011: In 2012, fuel expense increased $27.9 million, or 21 percent, compared to 2011, due to higher output at the coal-fired power plants and at the Langley Gulch plant, which came on-line during the summer of 2012. The output at the coal-fired plants was up 0.4 million MWh, or 8 percent, in 2012 compared to 2011. The increased dispatch was primarily caused by lower hydroelectric generation in 2012 than in 2011.

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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.

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, in addition to its hedging program 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,
	2012			2011		2010
Idaho power supply cost (deferral) accrual	$	(45,064	)	$	27,768	$	(14,324	)
Oregon power supply cost (deferral) accrual	(1,523		)	1,523		—
Amortization to expense of prior year authorized balances	(14,503		)	9,206		65,550
Total power cost adjustment expense	$	(61,090	)	$	38,497	$	51,226

The power supply accruals or deferrals represent the portion of that period's power supply cost fluctuations accrued or deferred under the PCA mechanisms. Accruals represent additional costs being recorded as a result of actual power supply costs that were less than the amount forecasted in PCA rates. The power supply cost is a deferral in 2012 because actual power supply costs in 2012 were higher than the amounts forecasted in PCA rates. If actual power supply costs are greater than the amount forecasted in PCA rates, the majority of the excess is deferred. 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 - 2012 Compared to 2011: Actual net power supply costs increased in 2012 relative to 2011, resulting in a change of $75.9 million—from accruals of $29.3 million to deferrals of $46.6 million. The $14.5 million of amortization reflects the net refunding to customers of prior years' accruals.

PCA Mechanisms - 2011 Compared to 2010: Actual net power supply costs decreased in 2011 relative to 2010, resulting in a change of $43.6 million—from a deferral of