Edgar Filing: IDACORP INC

IDA 12.31.14 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, 2014



	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 ( )

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Indicate by check mark whether the registrants have submitted electronically and posted on their corporate Web sites, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrants were required to submit and post such files).



IDACORP, Inc.	Yes	(X)	No	( )	Idaho Power Company	Yes	(X)	No	( )

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

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



IDACORP, Inc.:
	Large accelerated filer	(X)	Accelerated filer	( )	Non-accelerated filer	( )	Smaller reporting company	( )

Idaho Power Company:
	Large accelerated filer	( )	Accelerated filer	( )	Non-accelerated filer	(X)	Smaller reporting company	( )

Indicate by check mark whether the registrants are shell companies (as defined in Rule 12b-2 of the Act).



IDACORP, Inc.	Yes	( )	No	(X)	Idaho Power Company	Yes	( )	No	(X)

Aggregate market value of voting and non-voting common stock held by non-affiliates (June 30, 2014):



IDACORP, Inc.:	$	2,875,967,074	Idaho Power Company:	None



Number of shares of common stock outstanding as of February 13, 2015:
IDACORP, Inc.:	50,259,292
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 2015 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	18
Item 1A	Risk Factors	19
Item 1B	Unresolved Staff Comments	28
Item 2	Properties	28
Item 3	Legal Proceedings	30
Item 4	Mine Safety Disclosures	30

Part II

Item 5	Market for Registrant's Common Equity, Related Stockholder Matters, and Issuer Purchases of Equity Securities	30
Item 6	Selected Financial Data	32
Item 7	Management's Discussion and Analysis of Financial Condition and Results of Operations	33
Item 7A	Quantitative and Qualitative Disclosures About Market Risk	72
Item 8	Financial Statements and Supplementary Data	74
Item 9	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	127
Item 9A	Controls and Procedures	127
Item 9B	Other Information	131

Part III

Item 10	Directors, Executive Officers and Corporate Governance*	131
Item 11	Executive Compensation*	131
Item 12	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters*	131
Item 13	Certain Relationships and Related Transactions, and Director Independence*	132
Item 14	Principal Accountant Fees and Services*	132

Part IV

Item 15	Exhibits and Financial Statement Schedules	133

Signatures		144

* 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 2015 annual meeting of shareholders.

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COMMONLY USED TERMS

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

ADITC	-	Accumulated Deferred Investment Tax Credits	IFS	-	IDACORP Financial Services, Inc., a subsidiary of IDACORP, Inc.
AFUDC	-	Allowance for Funds Used During Construction	IPUC	-	Idaho Public Utilities Commission
APCU	-	Annual Power Cost Update	IRP	-	Integrated Resource Plan
BACT	-	Best Available Control Technology	IRS	-	U.S. Internal Revenue Service
BCC	-	Bridger Coal Company, a joint venture of IERCo	kW	-	Kilowatt
BLM	-	U.S. Bureau of Land Management	MATS	-	Mercury and Air Toxics Standards
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	NMFS	-	National Marine Fisheries Service
EGUs	-	Electric Utility Generating Units	NOx	-	Nitrogen Oxide
EIS	-	Environmental Impact Statement	NSPS	-	New Source Performance Standards
EPA	-	U.S. Environmental Protection Agency	NSR/PSD	-	New Source Review / Prevention of Significant Deterioration
EPS	-	Earnings Per Share	O&M	-	Operations and Maintenance
ESA	-	Endangered Species Act	OATT	-	Open Access Transmission Tariff
FCA	-	Fixed Cost Adjustment	OPUC	-	Public Utility Commission of Oregon
FERC	-	Federal Energy Regulatory Commission	PCA	-	Power Cost Adjustment
FPA	-	Federal Power Act	PCAM	-	Oregon Power Cost Adjustment Mechanism
GAAP	-	Generally Accepted Accounting Principles	PURPA	-	Public Utility Regulatory Policies Act of 1978
GHG	-	Greenhouse Gas	REC	-	Renewable Energy Certificate
HAPS	-	Hazardous Air Pollutants	RPS	-	Renewable Portfolio Standard
HCC	-	Hells Canyon Complex	SEC	-	U.S. Securities and Exchange Commission
Ida-West	-	Ida-West Energy, a subsidiary of IDACORP, Inc.	SMSP	-	Security Plan for Senior Management Employees
Idaho ROE	-	Idaho-jurisdiction return on year-end equity	SO₂	-	Sulfur Dioxide
IERCo	-	Idaho Energy Resources Co., a subsidiary of Idaho Power Company	USFWS	-	U.S. Fish and Wildlife Service
IESCo	-	IDACORP Energy Services Co., a subsidiary of IDACORP, Inc.	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, such as statements regarding projected or future financial performance, cash flows, capital expenditures, dividends, capital structure or ratios, strategic goals, challenges, objectives, and plans for future operations. Such statements constitute forward-looking statements within the meaning of the Private Securities Litigation Reform Act of 1995. Any statements that express, or involve discussions as to, expectations, beliefs, plans, objectives, assumptions, or future events or performance, often, but not always, through the use of words or phrases such as "anticipates," "believes," "estimates," "expects," "intends," "plans," "predicts," "projects," "may result," "may continue," or similar expressions, are not statements of historical facts and may be forward-looking. Forward-looking statements are not guarantees of future performance and involve estimates, assumptions, risks, and uncertainties. Actual results, performance, or outcomes may differ materially from the results discussed in the statements. In addition to any assumptions and other factors and matters referred to specifically in connection with such forward-looking statements, factors that could cause actual results or outcomes to differ materially from those contained in forward-looking statements include those factors set forth in Part I, Item 1A - “Risk Factors” and Part II, Item 7 - “Management’s Discussion and Analysis of Financial Condition and Results of Operations" of this report, as well as in subsequent reports filed by IDACORP and Idaho Power with the Securities and Exchange Commission, and the following important factors:


•	the effect of decisions by the Idaho and Oregon public utilities commissions, the Federal Energy Regulatory Commission, and other regulators that impact 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 demand-side management programs, and their associated impacts 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 of receivables;


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


•	advancement of technologies that reduce loads or reduce the need for Idaho Power's generation of electric power;


•	adoption of, 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;


•	the ability to obtain debt and equity financing or refinance existing debt when necessary or advisable and on favorable terms, which can be affected by factors such as credit ratings, volatility in the financial markets, 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 credit and contractual arrangements;


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


•	the ability to purchase fuel and power 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, operations, or reputation, 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 buy and sell power, transmission capacity, and fuel in the markets;


•	the ability to enter into financial and physical commodity hedges with creditworthy counterparties to manage price and commodity risk, and the failure of any such risk management and hedging strategies to work as intended;


•	administration 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 of any interconnected transmission system;

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•	the increased costs and operational challenges associated with purchasing and integrating intermittent renewable energy sources, including mandated power purchases under federal law, into Idaho Power's resource portfolio;


•	changes in actuarial assumptions, changes in interest rates, and the return on plan assets for pension and other post-retirement plans, which can affect future pension and other postretirement plan funding obligations, costs, and liabilities;


•	the ability to continue to pay dividends based on financial performance, and in light of contractual covenants and restrictions and regulatory limitations;


•	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 and retirements, 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 fines and increase the cost of compliance, the nature and extent of investigations and audits, and the cost of remediation;


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


•	the inability to obtain or 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, and regulatory proceedings, and the ability to recover those costs or the costs of operational changes through insurance or rates, or from third parties;


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


•	adoption of or changes in accounting policies and principles, changes in accounting estimates, and new Securities and Exchange Commission or New York Stock Exchange requirements, or new interpretations of existing requirements.

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

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PART I

ITEM 1. BUSINESS

OVERVIEW

Background

IDACORP, Inc. (IDACORP) is a holding company incorporated in 1998 under the laws of the state of Idaho. 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 the Federal Energy Regulatory Commission (FERC) and state utility regulatory commissions with access to books and records 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 that was organized in 1915 and began operations in 1916. Idaho Power is an electric utility engaged in the generation, transmission, distribution, sale, and purchase of electric energy and capacity and is regulated by the state regulatory commissions of Idaho and Oregon and by the FERC. 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. Idaho Power's utility operations constitute nearly all of IDACORP's current business operations and are IDACORP’s only reportable business segment. Segment financial information is presented in Note 17 – "Segment Information" to the consolidated financial statements included in this report. As of December 31, 2014, IDACORP had 2,021 full-time employees, 2,011 of whom were employed by Idaho Power, and 22 part-time employees, 20 of whom were employed 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), the successor to IDACORP Energy L.P., a marketer of energy commodities that wound down operations in 2003.

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.

Available Information

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 Idaho Power's website is www.idahopower.com. The contents of these websites 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.

UTILITY OPERATIONS

Background

Idaho Power provided electric utility service to approximately 516,000 general business customers in southern Idaho and eastern Oregon as of December 31, 2014. Over 428,000 of these customers are residential. Idaho Power’s principal commercial and industrial customers are involved in food processing and refining, electronics and general manufacturing, agriculture, health care, and winter recreation. 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. Idaho Power's service area is shaded in the illustration on the following page and covers approximately 24,000 square miles with an estimated population of one million.

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Electric utilities have historically been recognized as natural monopolies and operate in a highly regulated environment - one in which they have an obligation to provide electric service to their customers and in return receive an exclusive franchise within their service territory - with an opportunity to earn a regulated rate of return. Idaho Power is under the jurisdiction (as to rates, service, accounting, and other general matters of utility operation) of the Idaho Public Utilities Commission (IPUC), the Public Utility Commission of Oregon (OPUC), and the FERC. The IPUC and OPUC determine the rates that Idaho Power is authorized to charge to its general business customers. Idaho Power is also under the regulatory jurisdiction of the IPUC, the OPUC, and the Public Service Commission of Wyoming as to the issuance of debt and equity securities. As a public utility under the Federal Power Act, Idaho Power has authority to charge market-based rates for wholesale energy sales under its FERC tariff and to provide transmission services under its open access transmission tariff (OATT). Additionally, the FERC has jurisdiction over Idaho Power's sales of transmission capacity and wholesale electricity, hydroelectric project relicensing, and system reliability, among other items.

Regulatory Accounting

Idaho Power is subject to accounting principles generally accepted in the United States of America, with the impacts of rate regulation reflected in its financial statements. These principles provide for the deferral as regulatory assets of certain costs that would otherwise be charged to expense, based on expected recovery from customers in future prices. Likewise, certain credits that would otherwise reduce expense or increase revenues can be deferred as regulatory liabilities, based on expected future credits or refunds to customers. Idaho Power records regulatory assets or liabilities if it is probable that they will be reflected in future prices, based on regulatory orders or other available evidence.

Business Strategy

IDACORP’s business strategy emphasizes Idaho Power as IDACORP’s core business, as Idaho Power's utility operations are the primary driver of IDACORP's operating results. Idaho Power's three-part strategy can be summarized as follows:

•

Responsible Planning: Idaho Power’s planning process is intended to ensure adequate generation, transmission, and distribution 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.

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•

Responsible Development and Protection of Resources: Idaho Power’s business strategy includes the development and protection of generation, transmission, distribution, and associated infrastructure, and stewardship of the natural resources upon which Idaho Power and the communities it serves depend. 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 legislation. The strategy also includes targeted reductions relating to carbon emission intensity and public reporting of these reductions, as well as operating Idaho Power's system in a manner that extracts additional value through changes in fuel mix and generation.

Idaho Power regularly 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.

Rates and Revenues

Idaho Power generates revenue primarily through the sale of electricity to retail and wholesale customers and the provision of transmission service. The prices that the IPUC, the OPUC, and the FERC authorize Idaho Power to charge for the electric power and services Idaho Power sells are a critical factor in determining IDACORP's and Idaho Power's results of operations and financial condition. In addition to the discussion below, for more information on Idaho Power's regulatory framework and rate regulation, 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 on its investments. Idaho Power uses general rate cases, power cost adjustment (PCA) mechanisms, a fixed cost adjustment (FCA) mechanism, balancing accounts and tariff riders, and subject-specific filings to recover its costs of providing service and to earn a return on investment. Retail prices are generally determined through formal ratemaking proceedings that are conducted under established procedures and schedules before the issuance of a final order. Participants in these proceedings include Idaho Power, the staffs of the IPUC or OPUC, and other interested parties. The IPUC and OPUC are charged with ensuring that the prices and terms of service are fair, are non-discriminatory, and provide Idaho Power an opportunity to recover its prudently incurred or allowable costs and expenditures and earn a reasonable return on investment. The ability to request rate changes does not, however, ensure that Idaho Power will recover all of its costs or 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 base rates or supplemental tariffs. Outside of base rates, three of the most significant mechanisms for recovery of costs are the PCA mechanisms, FCA mechanism, and energy efficiency rider. The Idaho and Oregon PCA mechanisms are intended to address the volatility of power supply costs and provide for annual adjustments to the rates charged to retail customers by allowing partial recovery of the difference between net power supply costs included in base rates and actual net power supply costs incurred by Idaho Power. The FCA mechanism is designed to remove Idaho Power’s financial disincentive to invest in energy efficiency programs by separating (or decoupling) the recovery of fixed costs from the variable kilowatt-hour charge for certain Idaho customer classes and linking it instead to a set amount per customer. Separately, Idaho Power collects some of its energy efficiency program costs through an energy efficiency rider on customer bills.

Wholesale Markets: As a public utility subject to the provisions of 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 OATT. Idaho Power’s OATT transmission rate is revised each year based primarily 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 have responsibility for compliance and enforcement of transmission and reliability standards.

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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. These operating plans are impacted by factors such as customer demand for power, 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. Idaho Power at times operates these and its other generation facilities to take advantage of market opportunities. 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 capture wholesale marketplace economic benefits, maximize generation unit efficiency and meet peak loads. Compliance factors such as allowable river stage elevation changes and flood control requirements also influence these generation dispatch decisions. Idaho Power's off-system sales revenues depend largely on the availability of generation resources above the amount necessary to serve customer loads as well as adequate market power prices at the time when those resources are available. When either factor is low, off-system sales revenue is reduced.

Energy Sales: Weather, seasonal customer demand, and economic conditions all impact the amount of electricity that Idaho Power sells as well as the costs it incurs to provide that electricity. Idaho Power's utility revenues are not earned and associated expenses are not incurred evenly during the year. Idaho Power’s retail energy sales typically peak during the summer irrigation and cooling season, with a lower peak in the winter. 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. The table that follows presents Idaho Power’s revenues and sales volumes for the last three years, classified by customer type. Approximately 95 percent of Idaho Power’s general business revenue originates from customers located in Idaho, with the remainder originating 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.”



	Year Ended December 31,
	2014			2013			2012
General business revenues (thousands of dollars)
Residential	$	500,195		$	513,914		$	431,555
Commercial	299,462			281,009			241,519
Industrial	182,675			165,941			145,054
Irrigation	158,654			159,242			137,424
Provision for rate refund for sharing mechanism	(7,999		)	(7,602		)	(7,151		)
Deferred revenue related to Hells Canyon Complex relicensing AFUDC	(10,706		)	(10,776		)	(10,636		)
Total general business revenues	1,122,281			1,101,728			937,765
Off-system sales	77,165			54,473			61,534
Other	79,205			86,897			77,426
Total revenues	$	1,278,651		$	1,243,098		$	1,076,725
Energy sales (thousands of MWh)
Residential	4,965			5,365			5,039
Commercial	3,944			3,975			3,865
Industrial	3,217			3,182			3,133
Irrigation	1,966			2,097			2,048
Total general business	14,092			14,619			14,085
Off-system sales	2,220			1,683			2,183
Total	16,312			16,302			16,268

Competition: Idaho Power's electric utility business has historically been recognized as a natural monopoly. Idaho Power's rates for retail electric services are generally determined on a “cost of service” basis. Rates are designed to provide, after recovery of allowable operating expenses including depreciation on capital investments, an opportunity for Idaho Power to earn a reasonable return on investment as authorized by regulators. Alternative methods of generation, including customer-owned solar and other forms of distributed generation, compete with Idaho Power for sales to existing customers. Also, non-utility businesses are developing new technologies and services to help energy consumers manage energy in new ways that could alter demand for Idaho Power's electric energy. Idaho Power also competes with natural gas distribution companies in serving the energy needs of customers for space heating, water heating, and appliances, and with fuel oil providers for space heating.

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Idaho Power also participates in the wholesale energy markets and in the electric transmission markets. Generally, these wholesale markets are regulated by the FERC, which requires electric utilities to transmit power to or for wholesale purchasers and sellers and make available, on a non-discriminatory basis, transmission capacity for the purpose of providing these services.

Power Supply

Overview: Idaho Power primarily relies on company-owned hydroelectric, coal-fired, and gas-fired generation facilities and long-term power purchase agreements to supply the energy needed to serve customers. 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, economic conditions, and availability of generation resources impact power supply costs. Idaho Power’s annual hydroelectric generation varies depending on water conditions in the Snake River basin. 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 potentially 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 3,407 Megawatts (MW), set on July 2, 2013, 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 table below presents Idaho Power’s total power supply for the last three years:



	MWh			Percent of Total Generation
	2014	2013	2012	2014		2013		2012
	(thousands of MWh)
Hydroelectric plants	6,170	5,656	7,956	47	%	42	%	57	%
Coal-fired plants	5,851	6,327	5,227	44	%	47	%	38	%
Natural gas fired plants	1,175	1,576	676	9	%	11	%	5	%
Total system generation	13,196	13,559	13,859	100	%	100	%	100	%

Purchased power - cogeneration and small power production	2,286	2,127	1,961
Purchased power - other	1,867	1,775	1,709
Total purchased power	4,153	3,902	3,670
Total power supply	17,349	17,461	17,529

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 of approximately 8.5 million Megawatt-hours (MWh) under median water conditions. The amount of hydroelectric power generated depends on several factors—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, the amount and timing of water leases, and other weather and stream flow considerations. Generation at the plants located 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 participates in work groups related to 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.

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. In 2013, below average snow accumulation in the Snake River basin resulted in hydroelectric generation below the 8.5 million MWh historical median. For 2014, significantly low upstream carryover storage hindered the impact of the runoff of near-normal 2014 snow accumulation, resulting in 2014 generation below the historical median. Generation from Idaho Power’s hydroelectric facilities was 6.2

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million MWh in 2014. The Northwest River Forecast Center of the National Oceanic and Atmospheric Administration reported that Brownlee Reservoir (part of Idaho Power's Hells Canyon Complex) inflow for April through July 2014 was 3.4 million acre-feet (maf). By comparison, April through July Brownlee Reservoir inflow was 2.6 maf in 2013 and 5.5 maf in 2012. For 2015, Idaho Power estimates generation from its hydroelectric facilities of between 7.0 million MWh and 9.0 million MWh.

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, among other items, provisions relating to condemnation of a project upon payment of just compensation, amortization of project investment from excess project earnings, and possible takeover of a project after expiration of its license upon payment of net investment and severance damages.

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;


•	North 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.

PacifiCorp is the operator of the Jim Bridger power plant. Idaho Power owns a one-third interest in BCC, which owns the mine that supplies coal to the Jim Bridger power plant. The mine, which is operated by PacifiCorp and 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 and underground sources. Idaho Power believes that BCC 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 2017 from the Black Butte Coal Company’s Black Butte mine located near the Jim Bridger plant. This contract supplements the BCC 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, while limited, provides the opportunity to access other fuel supplies for tonnage requirements above established contract minimums.

NV Energy is the operator of the North Valmy power plant. NV Energy and Idaho Power have contracts with a coal supplier through 2015. Idaho Power's share of these contracts along with existing coal inventory at the plant are expected to meet Idaho Power's projected coal supply needs for 2015 and approximately 60 percent of its supply needs for 2016.

Portland General Electric Company is the operator of the Boardman power plant. Ninety percent of the Boardman plant’s projected coal requirement is under contract for 2015. The Boardman generating plant receives coal through annual contracts with suppliers from the Powder River Basin in northeast Wyoming. In December 2010, the Oregon Environmental Quality Commission approved a plan to cease coal-fired operations at the Boardman power plant no 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.

Idaho Power operates the Langley Gulch plant as a baseload 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.

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As of December 31, 2014, approximately 5.35 million MMBtu's of natural gas was financially hedged for physical delivery for the operational dispatch of the Langley Gulch plant through July 2015. 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: As described below, Idaho Power purchases power in the wholesale market as well as power pursuant to long-term power purchase contracts and exchange agreements.

Wholesale Market Transactions: To supplement its self-generated power and long-term purchase arrangements, Idaho Power purchases power in the wholesale market based on economics, operating reserve margins, risk management policy limitations, and unit availability. Depending on availability of excess power or generation capacity, pricing, and opportunities in the markets, Idaho Power also sells power in the wholesale markets.

During 2014 and 2013, Idaho Power purchased 1.9 million MWh and 1.8 million MWh of power through wholesale market purchases at an average cost of $49.31 per MWh and $47.91 per MWh, respectively. During 2014 and 2013, Idaho Power sold 2.2 million MWh and 1.7 million MWh of power in wholesale market sales, with an average price of $34.76 per MWh and $32.37 per MWh, respectively.

Long-term Power Purchase and Exchange Arrangements: In addition to its wholesale market purchases, Idaho Power has the following notable firm long-term 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 2033.


•	Telocaset Wind Power Partners, LLC - for 101 MW (nameplate generation) from its Elkhorn Valley wind project located in eastern Oregon. The contract term is through 2027.


•	USG Oregon LLC - for 22 MW (estimated average annual output) from the Neal Hot Springs #1 geothermal power plant located near Vale, Oregon. The contract term is through 2037.


•	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.

PURPA Power Purchase Contracts: Idaho Power purchases power from PURPA projects as mandated by federal law. As of December 31, 2014, Idaho Power had contracts with on-line PURPA-related projects with a total of 781 MW nameplate generation capacity, with an additional 521 MW nameplate capacity of projects projected to be on-line by June 1, 2017. The power purchase contracts for these projects have original contract 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,
	2014		2013		2012
PURPA contract expense (in thousands)	$	144,617	$	131,338	$	117,618
MWh purchased under PURPA contracts (in thousands)	2,286		2,127		1,961
Average cost per MWh from PURPA contracts	$	63.26	$	61.75	$	59.98

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.

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•	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 have generally provided for PURPA standard contract terms of up to 20 years, though a current docket exists at the IPUC to review contract terms for future agreements.


•	The IPUC requires Idaho Power to pay "published avoided cost" rates for all wind and solar projects that are smaller than 100 kilowatts (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 affected electric utilities, have engaged in proceedings at the IPUC and OPUC relating to PURPA contracts. These proceedings have related to, among other things, appropriate contract term lengths and the prices paid for energy purchased from PURPA projects. Refer to Part II - Item 7 - MD&A - "Regulatory Matters - Renewable Energy Standards and Contracts" for a summary of those proceedings.

Emerging Energy Imbalance Markets: Utilities in the western United States outside the California Independent System Operator (California ISO) have traditionally relied upon a combination of automated and manual dispatch within the hour to balance generation and load to maintain reliable supply. These utilities have limited capability to transact within the hour outside their own borders. In contrast, energy imbalance markets use automated intra-hour economic dispatch of generation from committed resources to serve loads. The California ISO, PacifiCorp, and other parties implemented a new energy imbalance market in the fourth quarter of 2014 (California ISO-PAC EIM) under which the parties enabled their systems to interact for dispatch purposes. Similarly, the Northwest Power Pool (NWPP) Members Market Assessment and Coordination Committee has stated that it intends to implement the Security Constrained Economic Dispatch (NWPP SCED), an intra-hour energy balancing market, in 2016. The California ISO-PAC EIM and the NWPP SCED are similar but not identical approaches to balancing services and each are intended to reduce the costs to serve customers through more efficient dispatch of a larger and more diverse pool of resources, to integrate intermittent power from renewable generation sources more effectively, and to enhance reliability. Participation in both the California ISO-PAC EIM and the NWPP SCED are voluntary and available to all balancing authorities in the western United States. Idaho Power is an active participant in the development stage of the NWPP SCED project and is also evaluating the potential opportunities and challenges associated with the NWPP SCED and the California ISO-PAC EIM.

Transmission Services and Federal Tariff

Electric transmission systems deliver energy from electric generation facilities to distribution systems for final delivery to customers. Transmission systems are designed to move electricity over long distances because generation facilities can be located anywhere from a few miles to hundreds of miles from customers. Idaho Power’s generating facilities are interconnected through its integrated transmission system and are operated on a coordinated basis to achieve maximum 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. 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 for eligible transmission customers on a non-discriminatory basis. Idaho Power is a member of the WECC, the NWPP, 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.

Transmission to serve Idaho Power's retail customers is subject to the jurisdiction of the IPUC and OPUC for retail rate making purposes. Idaho Power provides cost-based wholesale and retail access transmission services under the terms of a FERC approved OATT. Services under the OATT are offered on a nondiscriminatory basis such that all potential customers, including Idaho Power, have an equal opportunity to access the transmission system. As required by FERC standards of conduct, Idaho Power's transmission function is operated independently from Idaho Power's energy marketing function.

Idaho Power is jointly working on the permitting of two significant transmission projects. The Boardman-to-Hemingway line is a proposed 300-mile, 500-kV transmission project between a station near Boardman, Oregon and the Hemingway station near Boise, Idaho. The Gateway West line is a proposed 500-kV transmission project between a station located near Douglas,

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Wyoming and the Hemingway station. Both projects are intended to meet future anticipated resource needs and are discussed in Part II, Item 7 – MD&A - "Liquidity and Capital Resources - Capital Requirements" in this report.

Resource Planning

Integrated Resource Planning: The IPUC and OPUC require that Idaho Power prepare biennially an Integrated Resource Plan (IRP). Idaho Power filed its most recent IRP in June 2013. 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 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.

In February 2014, the IPUC accepted the 2013 IRP for filing and requested that Idaho Power continue monitoring environmental requirements at a national level and account for their impact in resource planning, continue to collaborate with stakeholders on how best to use energy efficiency as a resource, and continue to be actively involved in matters relating to the North Valmy coal-fired power plant and promptly apprise the IPUC of developments that could impact the company's continued reliance on that coal-fired resource. In July 2014, the OPUC acknowledged Idaho Power's short-term action items in the 2013 IRP. However, in its order the OPUC did not acknowledge Idaho Power's investments in selective catalytic reduction emissions technology being installed at the Jim Bridger plant. The OPUC stated that it would undertake a fair and thorough investigation of the prudence of the emissions technology investments at the Jim Bridger plant when Idaho Power seeks rate recovery for the investments.

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

Idaho Power expects to file the 2015 IRP in June 2015. Idaho Power has begun its 2015 IRP process, initiating the public involvement process and analyzing future anticipated loads. The load forecast Idaho Power expects to use for purposes of the 2015 IRP predicts an average annual growth rate of 1.2 percent for average loads and 1.5 percent for summer peak loads over the 20-year planning horizon from 2015 to 2034. The rate of load growth can impact the timing and extent of development of resources, such as new generation plants or transmission infrastructure, to serve those loads. The load forecast Idaho Power used in the 2013 IRP predicted an average annual growth rate of 1.1 percent for average loads and 1.4 percent for summer peak loads over the 20-year planning horizon from 2013 to 2032.

Recent studies outside of the IRP process that incorporate the potential for additional mandatory PURPA-related power purchases suggest that no peak-hour load deficit exists through 2021 under some circumstances. Thus, Idaho Power expects there may be available near term capacity to accommodate growth from economic development or increases in customers and loads. Idaho Power expects to be able to manage near-term summer peak capacity deficits until completion of the Boardman-to-Hemingway transmission line, which is expected to be in service in 2021 or beyond. If the Boardman-to-Hemingway line is not constructed by the time necessary to meet load demand, Idaho Power will need to identify alternatives to meet future load requirements. Should estimates of higher growth rates materialize, or were there to be a significant increase in loads due to new, unanticipated large-load customers, Idaho Power could be required to adjust its infrastructure development timing and plans accordingly.

Integration of Intermittent Resources: In response to the operational challenges associated with integrating intermittent wind and solar generation that Idaho Power must purchase pursuant to PURPA, and in recognition that the costs and challenges associated with integrating these resources will become even more pronounced as the volume of intermittent resources in Idaho Power's portfolio increases, Idaho Power continues efforts to better understand the effects of wind and solar generation on power system operation. As part of these efforts, Idaho Power has performed wind and solar integration studies aimed at providing insight into the maximum amounts of intermittent generation Idaho Power's system can accommodate without significantly impacting reliability. 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. Due to the large volumes of solar generation projects being proposed under PURPA, the IPUC recently directed Idaho Power to update the solar integration study, taking

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into account the higher solar penetration levels. Idaho Power expects to complete and file the updated study during 2015. Also due to the large volumes of proposed solar projects, in January 2015 Idaho Power initiated a proceeding at the IPUC regarding the length of contract terms under PURPA contracts, described in Part II - Item 7 - MD&A - "Regulatory Matters."

Energy Efficiency and Demand Response Programs: Idaho Power has 19 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;


•	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; and


•	membership in the Northwest Energy Efficiency Alliance, which supports market transformation efforts across the region.

In 2014, Idaho Power’s energy efficiency programs reduced energy usage by approximately 125,000 MWh. For 2014, Idaho Power had a demand response capacity of approximately 390 MW. In 2014 and 2013, Idaho Power expended approximately $37 million and $27 million, respectively, on energy efficiency and demand response programs. Funding for these programs is provided through a combination of the Idaho and Oregon energy efficiency tariff riders, base rates, and the Idaho PCA mechanism.

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 numerous environmental requirements, such as the aeration of turbine water to meet dissolved gas and temperature standards in the 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.

Environmental Expenditures: Idaho Power’s environmental compliance expenditures will remain significant for the foreseeable future, especially given the additional regulation proposed and 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):



	2015		2016 - 2017
Capital expenditures:
Studies and measures at hydroelectric facilities	$	13	$	28
Investments in equipment and facilities at thermal plants	60		27
Total capital expenditures	$	73	$	55
Operating expenses:
Operating costs for environmental facilities - hydroelectric	$	19	$	39
Operating costs for environmental facilities - thermal	12		26
Total operations and maintenance	$	31	$	65

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Idaho Power anticipates that finalization of a number of federal and state rulemakings and other proceedings addressing, among other things, greenhouse gas and particulate emissions, hazardous materials, and endangered species 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 potential future regulations.

Environmental Controls Cost Study: In connection with its IRP process, in February 2013 Idaho Power filed with the IPUC and OPUC the results of cost studies and scenario analyses conducted to assess the potential future investments necessary for the continued operation of the Jim Bridger and North 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. The analysis compared the cost of future compliance with regulations 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 concluded in its study that the Jim Bridger and North Valmy plants should be retained in its resource portfolio as coal-fired plants, and supports planned investments in environmental controls at those plants. However, Idaho Power will continue to monitor environmental requirements to assess whether environmental control upgrades at the coal-fired plants remain economically appropriate. Continued review of the economic appropriateness of further investment was included in a February 2014 order of the IPUC, in which the IPUC requested that Idaho Power continue monitoring environmental requirements at a national level and account for their impact in resource planning and promptly apprise the IPUC of developments that could impact the company's continued reliance on the North Valmy plant as a coal-fired resource. Idaho Power will continue to work with the plant's co-owner to monitor environmental requirements and costs associated with the plant, and to develop alignment on potential retirement dates for the plant.

Voluntary CO₂ Intensity Reduction Goal: 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 emissions 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) emissions intensity for the 2010 through 2013 time period to a level of 10 to 15 percent below Idaho Power's 2005 CO₂ emissions intensity of 1,194 lbs CO₂/MWh. Idaho Power's estimated CO₂ emissions intensity from its generation facilities, as submitted to the Carbon Disclosure Project, was as follows:



	2010	2011	2012	2013
Emission Intensity (lbs CO₂/MWh)	1,060	677	871	1,129

As of the date of this report, emission intensity information for 2014 was not yet available. The combination of effective utilization of hydroelectric projects, above average stream flows in some years, reduced usage of coal-fired facilities, and addition of the Langley Gulch natural gas-fired power plant positioned Idaho Power to extend its CO₂ emissions 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 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 has focused on a diversified approach to its investment strategy in order to limit both geographic and operational risk with most of IFS’s investments having been made through syndicated funds. IFS is no longer actively pursuing further investment opportunities, but will continue to maintain and manage its current portfolio of investments. At December 31, 2014, the gross amount of IFS’s portfolio equaled $192 million in tax credit investments. IFS generated tax credits of $5.2 million, $5.5 million, and $5.5 million in 2014, 2013, and 2012, respectively.

IDA-WEST

Ida-West operates and has a 50 percent ownership interest in nine hydroelectric projects that have 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 each year from 2012 to 2014.

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EXECUTIVE OFFICERS OF THE REGISTRANTS

The names, ages, and positions of the executive officers of IDACORP and Idaho Power are listed below, along with their business experience during at least the past five years. Mr. J. LaMont Keen, a member of IDACORP's and Idaho Power's boards of directors and former President and Chief Executive Officer of IDACORP and Idaho Power, 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, 56


•	President and Chief Executive Officer of IDACORP, May 1, 2014 - present.


•	President and Chief Executive Officer of Idaho Power Company, January 1, 2014 - present.


•	President and Chief Financial Officer of Idaho Power Company, January 1, 2012 - December 31, 2013.


•	Executive Vice President, Administrative Services and Chief Financial Officer of IDACORP, Inc., October 1, 2009 - April 30, 2014.


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


•	Member of the Boards of Directors of both IDACORP, Inc. and Idaho Power Company since September 2013.

REX BLACKBURN, 59


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

LISA A. GROW, 49


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

STEVEN R. KEEN, 54


•	Senior Vice President - Chief Financial Officer, and Treasurer of IDACORP, May 1, 2014 - present.


•	Senior Vice President - Chief Financial Officer, and Treasurer of Idaho Power Company, January 1, 2014 - present.


•	Vice President - Finance and Treasurer of IDACORP, Inc., June 1, 2010 - April 30, 2014.


•	Senior Vice President - Finance and Treasurer of Idaho Power Company, January 1, 2012 - December 31, 2013.


•	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.

WARREN KLINE, 59


•	Senior Vice President - Customer Operations of Idaho Power Company, June 1, 2014 - present.


•	Vice President - Customer Operations of Idaho Power Company, May 20, 2010 - May 31, 2014.


•	Vice President - Customer Service and Regional Operations of Idaho Power Company, July 20, 2005 - May 19, 2010.

DANIEL B. MINOR, 57

•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.

Other Executive Officers (in alphabetical order)

PATRICK A. HARRINGTON, 54


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

LONNIE KRAWL, 51


•	Vice President and Chief Information Officer of Idaho Power Company, October 1, 2013 - present.


•	Director of Human Resources of Idaho Power Company, July 25, 2009 - September 30, 2013.

LUCI K. MCDONALD, 57


•	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.

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KEN W. PETERSEN, 51


•	Vice President, Controller and Chief Accounting Officer of IDACORP, Inc. and Idaho Power Company, January 1, 2014 - present.


•	Corporate Controller and Chief Accounting Officer of IDACORP, Inc. and Idaho Power Company, May 20, 2010 - December 31, 2013.


•	Corporate Controller of IDACORP, Inc. and Idaho Power Company, December 29, 2007 - May 19, 2010.

N. VERN PORTER, 55


•	Vice President - Idaho Power Company, January 1, 2014 - present.


•	Vice President - Delivery Engineering and Construction of Idaho Power Company, May 17, 2012 - December 31, 2013.


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

GREGORY W. SAID, 60


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


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


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

LORI D. SMITH, 54


•	Vice President and 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

IDACORP and Idaho Power operate in an industry and business environment that involves significant risks, many of which are beyond the companies' control. 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. These risk factors, as well as other information in this report and in other reports the companies file with the SEC, should be considered carefully when evaluating IDACORP and Idaho Power.

If the Idaho Public Utilities Commission, the Public Utility Commission of Oregon, or the Federal Energy Regulatory Commission grant less recovery through rates than Idaho Power needs to cover costs and earn a reasonable 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 Public Utility Commission of Oregon 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 rates ultimately approved by regulators may not match prior or anticipated future expenses, and recovery of expenses may lag behind the occurrence of those expenses. The ratemaking process typically involves multiple intervening parties, including governmental bodies, consumer advocacy groups, and customers, generally with the common objective of limiting rate increases or even reducing rates.

Further, while rate regulation is premised on the assumption that rates will be established that are fair, just, and reasonable, regulators have considerable discretion in applying this standard. The Idaho Public Utilities Commission and the Public Utility Commission of Oregon have the authority to disallow recovery of any costs that they consider unreasonable or imprudently incurred. Collection of costs and capital expenditures through rates often occurs subsequent to the time those costs and expenditures are incurred, resulting in a lag in collection. Idaho Power's regulators may also disagree with Idaho Power's rate calculations under various tracking and decoupling mechanisms, like the power cost adjustment and fixed cost adjustment mechanisms. Regulators may also decide to modify or eliminate these mechanisms, which may make it more difficult for Idaho Power to recover its costs in the rates it charges to customers. Thus, the regulatory process does not assure that Idaho Power will be able to fully recover its costs or achieve the rate of return authorized or contemplated in connection with the ratemaking process. In a number of proceedings in recent years, Idaho Power has been denied recovery, or required to defer recovery pending the next general rate case, including denials or deferrals related to compensation expenses and construction expenditures. In some instances, denial of recovery may cause IDACORP and Idaho Power to record an impairment of those assets. If Idaho Power's costs are not fully and timely recovered through the rates ultimately approved by regulators, IDACORP's and Idaho Power's financial condition and results of operations, and its ability to earn a return on investment and meet financial obligations, could be adversely affected.

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For additional information relating to Idaho Power's regulatory framework and recent regulatory matters, see Part I - Item 1 - "Business - Utility Operations," Note 3 - "Regulatory Matters" to the consolidated financial statements included in this report, and Part II - 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 and methods 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 compare 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. 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. Further, during 2014 the Idaho Public Utilities Commission opened dockets to review the operation of the Idaho power cost adjustment mechanism and the fixed cost adjustment mechanism. Any future modification or elimination of the mechanisms based on these or subsequent proceedings may increase Idaho Power's financial exposure to changes in power costs and collection of fixed costs.

IDACORP's and Idaho Power's business, financial condition, and results of operations may be negatively affected by changes in customer growth or customer usage. Customer growth and customer usage are affected by a number of factors outside of the control of IDACORP and Idaho Power, such as implementation of energy efficiency measures, customer-generated power such as from rooftop solar panels, demand side management requirements, and economic and demographic conditions, such as population changes, job and income growth, housing starts, new business formation or migration, and the overall level of economic activity. The regional economy in which Idaho Power operates is influenced by conditions in the agriculture, recreation, technology, medical, and other industries, and as these conditions change, IDACORP's and Idaho Power's revenues will be impacted. 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. The adoption of technology by customers can also have both positive and negative impacts on sales. Some new technologies and modern equipment utilize less energy than in the past, while new electric technologies like electric vehicles can create additional demand.

In light of the need to predict future electric power demands and how Idaho Power can meet those demands, Idaho Power prepares and periodically updates a load forecast as part of its integrated resource planning process. In doing so, Idaho Power makes load estimates that are based on a number of factors that are uncertain and difficult to estimate, including those described above. Any unanticipated increase in the demand for energy could result in increased reliance on higher-cost purchased power to meet peak system demand, the need to initiate new demand response and energy efficiency programs, or the need to accelerate investment in additional generation or transmission resources. If the incremental costs associated with the unanticipated changes in loads exceed the incremental revenue received from those sales, and Idaho Power is unable to secure timely and full rate relief to recover those costs, the resulting imbalance could have an adverse effect on IDACORP's and Idaho Power's financial condition and results of operations. Decreases in loads also have the potential to adversely affect IDACORP and Idaho Power. A resulting decrease in overall customer usage or collections and slower or negative load growth may delay or decrease capital spending, which can adversely affect Idaho Power's rate base used for establishing customer rates and may reduce revenues, earnings, and cash flows.

Depending on changes in load and infrastructure project timing, Idaho Power may seek to accelerate, scale back, modify, or eliminate projects, or seek alternative projects, to accommodate anticipated resource needs and to help ensure its ability to provide reliable electric service and meet load and transmission capacity obligations. Scaling back or eliminating a project due to regulatory challenges or other factors influencing the feasibility of a project may result in Idaho Power pursuing one or more separate, more costly projects. For instance, if Idaho Power were unable to secure permits or joint funding commitments to develop its 500-kV transmission projects, it may terminate those projects and seek other resources to serve loads. Termination of a project carries with it the potential for a write-off of all or a portion of the costs associated with the project if regulators deem the costs incurred imprudent.

Extreme weather events and their associated impacts can adversely affect IDACORP's and Idaho Power's results of operations and financial condition. Extreme weather events and their associated impacts (such as fires and high winds) can

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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. The effect of the failure of Idaho Power's facilities to operate as planned under extreme weather conditions is particularly burdensome during peak demand periods, such as hot summer days. 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 operations and financial condition. Economic losses incurred as a result of such events might not be recoverable through customer rates or covered in full by insurance.

New advances in power generation, energy efficiency, or other technologies that impact the power utility industry could decrease revenues. Idaho Power primarily generates power at large central facilities, which results in economies of scale and lower costs than many newer generation technologies. However, the increasing costs of energy have incentivized the development of new technologies for power generation, power storage, and energy efficiency, and further 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, in recent years there have been numerous advancements in the design of solar generation facilities and the materials used in panels that may further increase the efficiency and power output of solar generation sources in a more cost-effective manner. As the cost of the technology has decreased, there has been an increase in adoption of rooftop solar systems by both residential and commercial customers, particularly in areas where electric rates are high and the weather is suitable for solar power systems. There is potential that these alternative power generation systems, particularly if coupled with power storage devices, could become sufficiently cost-effective and efficient that an increasing number of Idaho Power's customers choose to install such systems on their homes or businesses. Additionally, considerable emphasis has been placed on energy efficiency, such as LED lighting. Energy efficiency programs, including programs sponsored by Idaho Power under a directive from state regulatory commissions, are designed to reduce energy demand. If Idaho Power is unable to maintain adequate regulatory mechanisms or develop new mechanisms or rate structures allowing for timely and adequate cost recovery, declining usage would result in under-recovery of fixed costs. Further, widespread adoption of distributed generation and declining usage may decrease the need for electric power supplied by Idaho Power, which would reduce Idaho Power's revenue, potentially result in the impairment of assets that produce and deliver energy, and have a negative impact on IDACORP's and Idaho Power's results of operations and financial condition.

Capital expenditures for infrastructure, risks associated with construction of that infrastructure, and the timing and availability of cost recovery for the 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. A significant portion of Idaho Power’s facilities were constructed many years ago, and thus require periodic upgrades and frequent maintenance. Also, long-term anticipated 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, which are intended to help meet future customer energy demands. Construction projects are subject to usual permitting and construction risks that can adversely affect project costs and the completion time. These risks include, as examples:


•	the ability to timely obtain labor or materials at reasonable costs, and defaults by contractors;


•	equipment, engineering, and design failures;


•	the effects of adverse weather conditions;


•	availability of financing;


•	the ability to obtain and comply with permits and land use rights, and environmental constraints;


•	delays and costs associated with 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 be unable to recover its costs in full through rates or on a timely basis. In many instances, review by regulators of the prudence of investments will not occur until expenditures have been made. 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. Further, if Idaho Power is unable to secure permits or joint funding commitments to develop transmission infrastructure necessary to serve loads, it may terminate those projects and, as an alternative, seek to develop additional generation facilities within areas where Idaho Power has available transmission capacity or pursue other more costly options to serve loads. To limit the timing-related risks of these projects, Idaho Power may enter into purchase orders and construction contracts and incur engineering and design service costs in advance of receiving necessary regulatory approvals or siting or environmental permits. If any of the projects are canceled for any reason, including Idaho Power's failure to receive necessary regulatory approvals or permits or because the project is no longer economical, Idaho Power could incur significant cancellation penalties under the purchase order or construction contracts. Additionally, termination of a project carries with it the potential for impairment of the associated asset if regulators

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deny full recovery of project costs. Thus, termination of a project could negatively affect IDACORP's and Idaho Power's financial condition and results of operations.

IDACORP's and Idaho Power’s businesses are subject to an extensive set of environmental laws, rules, and regulations, which could impact their 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 and water quality, natural resources, and health and safety are applicable to IDACORP's and Idaho Power's operations. Many of these laws, including the Environmental Protection Agency's proposed rules under Section 111(d) under the Clean Air Act, are described in Part II - Item 7 - "Management's Discussion and Analysis of Financial Condition and Results of Operations - Environmental Matters" in this report. These laws and regulations generally require IDACORP and Idaho Power to obtain and comply with a wide variety of environmental licenses, permits, and other approvals, including through substantial investment in pollution controls, and may be enforced by both public officials and private individuals. Some of these regulations are pending, changing, or subject to interpretation, and failure to comply may result in penalties, mandatory operational changes, and other adverse consequences, including costs associated with defending against claims by governmental authorities or private parties and complying with new operating requirements.

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 and co-owned power generation facilities, often at a substantial cost. For instance, Idaho Power is in the process of installing environmental control apparatus in two units of its co-owned Jim Bridger power plant at an estimated cost of $113 million, and may install a second set of control apparatus at two other units at that plant in or around 2021 and 2022. IDACORP and Idaho Power will incur other costs associated with existing environmental regulations, and the companies expect to incur additional costs associated with pending and future environmental regulations, and those costs are likely to be substantial. If the costs of compliance with those new regulations renders the generating facilities uneconomical to maintain or operate, Idaho Power would need to identify alternative resources for power, potentially in the form of new generation and transmission facilities, market power purchases, demand-side management programs, or a combination of these and other methods.

Idaho Power is not guaranteed timely or full recovery of those costs, and regulators may not grant prior approval of cost recovery. For example, in 2013 the Idaho Public Utilities Commission declined to approve Idaho Power's application requesting a binding commitment to provide rate base treatment for Idaho Power's estimated share of the capital investment in environmental control upgrades at the Jim Bridger power plant, instead reserving the prudence determination (and thus ratemaking treatment) for subsequent proceedings. Furthermore, Idaho Power may not be able to obtain or maintain all environmental regulatory approvals necessary for operation of its existing infrastructure or construction of new 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. If Idaho Power is unable to recover in full these increased costs through the ratemaking process, such under-recovery would negatively impact IDACORP's and Idaho Power's financial condition and results of operations.

Relicensing of the Hells Canyon hydroelectric project and construction of the proposed Gateway West and Boardman-to-Hemingway 500-kV 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 presence of sage grouse, which is being considered for listing as an endangered species, in the vicinity of the Gateway West and Boardman-to-Hemingway transmission projects has required more extensive, costly, and time consuming evaluation and engineering. These and other requirements of the Endangered Species Act, Clean Air Act, Clean Water Act, and similar environmental laws may increase costs, adversely affect the timing or ability to complete major projects, and may have an adverse effect on IDACORP's and Idaho Power's results of operations and financial condition.

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. During 2014, 47 percent of Idaho Power's electric power generation was from hydroelectric facilities. Because of Idaho Power’s heavy reliance on hydroelectric generation, snow pack, the timing of run-off, drought conditions, and the availability of water in the Snake River basin can significantly affect its operations. The combination of a long-term trend 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

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aquifer by diverting surface water to porous locations and permitting it to sink into the aquifer is one proposed approach 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 existence of endangered and threatened species in the watershed may result in major operational changes to the region’s hydroelectric projects, which may be reflected in hydroelectric licenses. 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. One particularly significant issue identified in connection with the Hells Canyon Complex relicensing effort involves water temperature gradients in the Snake River below the Hells Canyon dam. 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 (including power purchase 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 or extreme temperatures and weather can impact their results of operations and financial condition. Idaho Power's electric power sales are seasonal, with demand in Idaho Power's service area peaking during the hot summer months, with a secondary peak during the cold winter months. Electric power demands by irrigation customers in Idaho Power's service area, which are impacted by temperatures and the timing and amount of precipitation, among other factors, can also create significant seasonal changes in usage. Seasonality of revenues may be enhanced by Idaho Power's tiered rate structure, under which rates charged to customers are often higher during higher-load periods. Market prices for power also often increase significantly during these peak periods, at times when Idaho Power is required to purchase power in the wholesale markets to meet customer demand. By contrast, when temperatures are relatively mild or where precipitation supplants irrigation systems, loads are often lower as customers are not using electricity for heating and air conditioning or irrigation purposes. Thus, unusually mild weather or the timing and extent of precipitation can cause IDACORP's and Idaho Power's results of operations and financial condition to fluctuate seasonally and from year to year.

Complying with 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. Renewable portfolio standards 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 10 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 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. In accordance with a renewable energy certificate management plan on file with the Idaho Public Utilities Commission, Idaho Power currently sells the renewable energy certificates it receives in connection with its power purchases from some renewable energy generation resources, using the proceeds to benefit customers. Enactment of a renewable portfolio standard in Idaho would cause Idaho Power to retain and retire some or all of those renewable energy certificates rather than sell them for the benefit of customers, and could thus result in increased rates.

Idaho Power’s use of coal and natural gas to fuel power generation facilities exposes it to commodity availability and price risk, which can adversely affect IDACORP's and Idaho Power's results of operations and financial condition. As part of its

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normal business operations, Idaho Power purchases coal and natural gas in the open market or under short-term or long-term contracts, often with variable-pricing terms. 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. Following the completion of the Langley Gulch natural gas-fired power plant, Idaho Power has become more dependent on natural gas for a portion of its electric generating capacity. Natural gas transportation to Idaho Power's natural gas plants is limited to one primary pipeline, presenting a heightened possibility of supply constraint and disruptions separate from the risk of counterparty default. Most of Idaho Power's coal supply arrangements are under long-term contracts for coal originating in Wyoming, and thus Idaho Power is exposed to risk of disruption of coal production in, or transportation from, that region. Idaho Power may from time to time enter into new, or renegotiate, these long-term contracts, but can provide no assurance that such contracts will be negotiated or renegotiated, as the case may be, on satisfactory terms, or at all. There also can be no assurance that counterparties to the coal supply agreements will fulfill their obligations to supply coal, and they may experience financial or technical problems that inhibit their ability to deliver coal. The coal supply agreements also contain terms that allow the coal suppliers to curtail the delivery of coal in certain circumstances, such as in the event of a natural disaster.

Defaults by coal and natural gas suppliers may cause Idaho Power to seek alternative, and potentially more costly, 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.

Historically, natural gas prices have tended to be more volatile than prices for other fuel sources. Recently, however, the availability of natural gas from shale production has lessened both natural gas prices and price volatility. Market power prices are impacted in part by the availability and cost of natural gas -- as the price of natural gas falls, other market participants that utilize natural gas-fired generation will be able to generate and sell into the wholesale markets electricity at increasingly competitive prices, which could decrease Idaho Power's off-system sales revenues.

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, water, or ground, acts of terrorism or sabotage, the loss of cost-effective disposal options for solid waste such as coal ash, operator error, and the occurrence of catastrophic events at the facilities. Diminished availability or performance of those facilities could result in reduced customer satisfaction, reputational harm, 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, electrical contacts, fires, explosions, catastrophic failures, general system damage or dysfunction, and other unplanned events related to Idaho Power's infrastructure would increase repair costs and 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. Idaho Power's transmission facilities are also interconnected with those of third parties, and thus operation of Idaho Power's and third parties' facilities could be adversely affected by unexpected or uncontrollable events. These transmission constraints and events 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.

As discussed in Item 1 - "Business" in this report, in the fourth quarter of 2014 new energy imbalance markets began to emerge in the western United States. The energy imbalance markets are intended to allow for automated near real-time dispatch of generation resources. Idaho Power has not yet joined the energy imbalance markets and cannot predict the ultimate impact, whether positive or negative, that the energy imbalance markets will have on its ability to make economic off-system sales and purchase power in the market. There is potential that, whether Idaho Power joins an energy imbalance market or not, Idaho Power's off-system sales will decrease or purchased power costs will increase, which could adversely affect IDACORP's and Idaho Power's results of operations and financial condition.

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 use short-term and long-term debt as a significant source of liquidity and funding for capital requirements not satisfied by operating cash flow. In a volatile credit environment IDACORP and Idaho Power may be unable to issue short-term or long-term debt 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,

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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.

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 and capital expenditures. 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. IDACORP's and Idaho Power's credit facilities include financial covenants that limit the amount of debt that can be outstanding as a percentage of total capital. Idaho Power's long-term debt has also been issued under an indenture that contains a number of financial covenants. Failure to maintain these covenants could preclude IDACORP and Idaho Power from issuing commercial paper, borrowing under their credit facilities, or issuing long-term debt, and could trigger a default and repayment obligation under debt instruments, which could adversely impact IDACORP's and Idaho Power's financial condition and liquidity.

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. Credit rating agencies periodically review the corporate credit ratings and long-term ratings of IDACORP and Idaho Power. These ratings are premised on financial ratios and performance, the regulatory environment and mechanisms, management and their effectiveness, resource risks and power supply costs, and other factors. These ratings impact access to, and the cost of, borrowing. IDACORP and Idaho Power also have borrowing arrangements that rely on the ability of the banks to fund loans or support commercial paper, a principal source of short-term financing. Downgrades of IDACORP’s or Idaho Power’s credit ratings, or those affecting relationship banks, could limit the companies’ ability to access short- and long-term capital under reasonable terms or at all, 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 commodity exposures and credit risk 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 to mitigate in part exposure to variable commodity prices. 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. To the extent that commodity markets are illiquid, Idaho Power may not be able to execute its risk management strategies, which could result in undesired over-exposure to unhedged positions. As a result, risk management actions, or the failure or inability to manage commodity price and counterparty risk, 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. Idaho Power has received in recent years notices of violations from, and regularly self-reports reliability standard compliance issues to, the Federal Energy Regulatory Commission, the North American Electric Reliability Corporation, and the Western Electricity Coordinating Council, as applicable. 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 for its actual or alleged failure to comply with reliability and security requirements could have a negative effect on its and IDACORP’s results of operations and financial condition.

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Federally mandated purchases of power from renewable energy 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 generation from renewable energy projects interconnected with Idaho Power's system during 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. Idaho Power's purchases of power from certain renewable energy projects, which Idaho Power is generally obligated to purchase under federal law regardless of the then-current load demand, availability of lower cost generation resources, or wholesale energy market prices, increase 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 and customer rates. Further, balancing load and generation from Idaho Power's power generation portfolio is challenging, and Idaho Power expects that its operational costs will continue to increase as a result of its efforts to integrate intermittent, non-dispatchable generation from a large number of renewable energy projects. Idaho Power anticipates that costs will escalate as the volume of intermittent wind and solar generation on its 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 rates, cash contributions to the plans could reduce the cash available for the companies' businesses and payment of dividends. 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 Note 6 - "Common Stock" to the consolidated financial statements included in this report for a further description of restrictions on IDACORP's and Idaho Power's payment of dividends.

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. 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 new employees to help prevent a loss of institutional knowledge and avoid a skills gap. Without a skilled workforce, Idaho Power’s ability to provide reliable 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 also have a negative effect on IDACORP's and Idaho Power's financial condition and results of operations.

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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 adverse consequences. 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 parties relating to alleged violations of environmental statutes and regulations at its co-owned 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, including the nature and extent of operation of generation facilities, which could also have a negative effect 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 electric power grid could negatively impact IDACORP's and Idaho Power's financial condition and results of operations. Idaho Power operates in an industry that requires the continuous use and operation of sophisticated information technology systems and network infrastructure. Idaho Power's generation and transmission facilities and its grid operations 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. These events, and governmental actions in response, could result in a material decrease in revenues and significant additional costs to protect, 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 employee information and the proprietary information of both Idaho Power and third parties. Cyber attacks have evolved to become increasingly sophisticated and difficult to detect in recent years. Despite the cyber security measures in place, Idaho Power's networks and infrastructure could be vulnerable to security breaches, data leakage, or other similar events that could interrupt operations, expose Idaho Power to liability, and require that Idaho Power remedy the security breaches. Those breaches and events may result from acts of Idaho Power employees, contractors, or third parties. Separate from liability to third parties and information owners, 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.

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. Amounts of tax-related assets and liabilities involve judgments and estimates of the timing and probability of recognition of income, deductions, and tax credits, which are subject to challenge by taxing authorities. The companies’ tax obligations include income, real estate, public utility, municipal, sales and use, business and occupation, employment-related taxes, and Canadian goods and services and provincial taxes, and ongoing issues related to these taxes. In recent years, tax settlements, as well as state regulatory mechanisms with tax-related provisions (such as Idaho Power's 2011 regulatory settlement stipulation with the Idaho Public Utilities Commission, which has been extended, with modifications, for future periods), 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

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Power anticipate or request from applicable state regulatory commissions, which could have a negative effect on their financial condition and results of operations.

Changes in accounting standards or 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. 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 some or all of 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 financial condition and results of operations.

ITEM 1B. UNRESOLVED STAFF COMMENTS

None.

ITEM 2. PROPERTIES

Idaho Power's properties consist of the physical assets necessary to support its utility operations, which include 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 use 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 in southern Idaho, and interests in three coal-fired steam electric generating plants located in Wyoming, Nevada, and Oregon. As of December 31, 2014, the system also includes approximately 4,858 pole-miles of high-voltage transmission lines, 24 step-up transmission substations located at power plants, 24 transmission substations, 10 switching stations, 222 energized distribution substations (excluding mobile substations and dispatch centers), and approximately 27,072 pole-miles of distribution lines.

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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
North 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.

IDACORP's and Idaho Power's headquarters are located in Boise, Idaho. The corporate headquarters campus is comprised of approximately 306,000 square feet of owned office space and approximately 51,000 square feet of leased office space. Excluding Idaho Power's power generation facilities and substations, Idaho Power owns an additional 605,000 square feet of office, warehouse, and industrial space to support its operations in Idaho and Oregon.

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 it believes 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.

Idaho Energy Resources Co. 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 hydroelectric plants that have a total generating capacity of 45 MW. These plants are located in Idaho and California.

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ITEM 3. LEGAL PROCEEDINGS

Refer to Note 10 – “Contingencies” to the consolidated financial statements included in this report.

ITEM 4. MINE SAFETY DISCLOSURES

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

PART II

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

IDACORP’s common stock, without par value, is traded on the New York Stock Exchange (NYSE). On February 13, 2015, there were 10,872 holders of record of IDACORP common stock and the closing stock price was $61.55 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.

IDACORP and Idaho Power paid dividends of $89 million, $79 million, and $69 million in 2014, 2013, and 2012, respectively.

The amount and timing of dividends paid on IDACORP’s common stock are within the discretion of IDACORP’s board of directors, subject to other restrictions. The board of directors reviews the dividend rate quarterly to determine its appropriateness in light of IDACORP’s current and long-term financial position and results of operations, capital requirements, rating agency requirements, contractual and regulatory restrictions, legislative and regulatory developments affecting the electric utility industry in general and Idaho Power in particular, competitive conditions, and any other factors the board of directors deems relevant. The ability of IDACORP to pay dividends on its common stock is dependent upon dividends paid to it by its subsidiaries, primarily Idaho Power. At its November 2011 meeting, the IDACORP board of directors adopted a dividend policy for IDACORP that provides for a target long-term dividend payout ratio of between 50 and 60 percent of sustainable IDACORP earnings, with the flexibility to achieve that payout ratio over time and to adjust the payout ratio or to deviate from the target payout ratio from time to time based on the various factors that drive the board of director's dividend decisions. Notwithstanding the dividend policy adopted by IDACORP's 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.

IDACORP's and Idaho Power's payment of dividends is subject to a number of restrictions. For information relating to those restrictions, 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 2014 and 2013 as reported by the NYSE:



	2014						2013
Quarter	High		Low		Dividends paid per share		High		Low		Dividends paid per share
1st	$	56.65	$	50.21	$	0.43	$	48.53	$	43.13	$	0.38
2nd	57.86		52.91		0.43		50.16		46.03		0.38
3rd	58.79		51.70		0.43		54.74		45.62		0.38
4th	70.05		53.39		0.47		53.99		47.57		0.43

During 2014, 2013, and 2012, 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 did not repurchase any shares of its common stock during the fourth quarter of 2014.

Performance Graph

The graph below 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

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December 31, 2009, with beginning-of-period weighting of the peer group indices (based on market capitalization) and monthly compounding of returns.

Source: Bloomberg and EEI



	2009		2010		2011		2012		2013		2014
IDACORP	$	100.00	$	119.85	$	141.72	$	149.76	$	184.97	$	243.49
S&P 500	100.00		115.08		117.47		136.24		180.33		204.96
EEI Electric Utilities Index	100.00		107.04		128.43		131.11		148.17		191.00

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 shall 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 and statistics)
	2014			2013			2012			2011			2010
Operating revenues	$	1,282,524		$	1,246,214		$	1,080,662		$	1,026,756		$	1,036,029
Operating income	253,696			291,742			242,602			155,352			191,811
Net income attributable to IDACORP, Inc.	193,480			182,417			173,014			169,981			145,018
Diluted earnings per share	3.85			3.64			3.46			3.43			3.00
Dividends declared per share	1.76			1.57			1.37			1.20			1.20

Financial Condition:
Total assets	5,716,853			5,364,563			5,291,290			4,925,319			4,635,304
Long-term debt (including current portion)	$	1,615,502		$	1,616,322		$	1,537,696		$	1,488,614		$	1,610,859

Financial Statistics:
Times interest charges earned:
Before tax⁽¹⁾	3.38			3.87			3.41			2.48			2.78
After tax⁽²⁾	3.19			3.06			3.02			3.00			2.69
Book value per share⁽³⁾	$	38.85		$	36.84		$	34.73		$	32.76		$	30.51
Market-to-book ratio⁽⁴⁾	170		%	141		%	125		%	129		%	121		%
Payout ratio⁽⁵⁾	46		%	43		%	40		%	35		%	40		%
Return on year-end common equity⁽⁶⁾	9.9		%	9.9		%	9.9		%	10.4		%	9.6		%

The financial statistics listed above are calculated in the following manner:
⁽¹⁾The sum of interest on long-term debt, other interest expense excluding AFUDC 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 I - 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 516,000 general business customers as of December 31, 2014. 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 jurisdiction (as to rates, service, accounting, and other general matters of utility operation) of the Idaho Public Utilities Commission (IPUC), the Public Utility Commission of Oregon (OPUC), and the Federal Energy Regulatory Commission (FERC). The IPUC and OPUC determine the rates that Idaho Power charges to its retail customers. Idaho Power is also under the regulatory jurisdiction of the IPUC, the OPUC, and the Public Service Commission of Wyoming as to the issuance of debt and equity securities. As a public utility under the Federal Power Act, Idaho Power has authority to charge market-based rates for wholesale energy sales under its FERC tariff and to provide transmission services under its open access transmission tariff (OATT). Idaho Power uses general rate cases, cost adjustment mechanisms, tariff riders, and subject-specific filings to recover its costs of providing service and the costs of its energy efficiency and demand-response 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 economy across the service territory), 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

Management's Outlook

In recent years Idaho Power has seen positive growth in its customer count and associated positive impacts on Idaho Power's revenue. To encourage responsible and sustainable growth, and as part of its planning for the future, Idaho Power actively participates in and supports state and local economic development initiatives. At the same time that Idaho Power pursues customer growth, it must also plan for that growth. Idaho Power's biennial Integrated Resource Plan (IRP) seeks to identify cost-effective and responsible means for Idaho Power to address future customer demand for electricity. Preparation of the 2015 IRP is underway and is expected to be completed by the end of the second quarter of 2015. Recent infrastructure investments and future anticipated infrastructure projects are intended to help Idaho Power both provide reliable service to existing customers and meet projected future customer growth. Idaho Power has invested significant capital in recent years to maintain and replace aging assets and to build for the future. Idaho Power expects to continue these significant levels of capital investment going forward. Idaho Power's noteworthy capital projects include the replacement of aging assets, upgrades to generation plants, a multi-year plan for replacement of underground conductor, ongoing system upgrades, and continued progress on permitting the Boardman-to-Hemingway and Gateway West 500-kV transmission lines. As of the date of this report, Idaho Power estimates total capital expenditures of approximately $1.5 billion over the next five years.

Idaho Power operates within what it believes to be a constructive regulatory framework, achieved through general rate cases, subject-specific rate filings, tariff riders, and cost recovery mechanisms that share risks and benefits with Idaho Power customers. To further complement these efforts, Idaho Power has also been focusing on controlling power supply, operating, maintenance, and capital costs through process review and improvement initiatives, and by empowering employees to identify new means to reduce costs, increase efficiencies, and enhance individual and enterprise performance for the benefit of IDACORP's shareholders, Idaho Power's customers, and other stakeholders. Based on its assessment, as of the date of this report Idaho Power does not expect to file an application for a general rate change in Idaho or Oregon during 2015.

Another area of recent focus has been IDACORP's dividend. In November 2011, IDACORP's board of directors adopted a target dividend payout ratio of between 50 and 60 percent of sustainable IDACORP earnings. From 2012 through 2014, IDACORP's board of directors has approved a collective 57 percent increase in the quarterly dividend, from $0.30 to $0.47 per share. Idaho Power's need and ability to construct infrastructure, the availability of timely regulatory recovery of costs associated with that construction, and IDACORP's earnings, among other factors discussed elsewhere in this report, all influence dividend decisions. A number of positive outcomes in those areas have been important elements that IDACORP's board of directors has considered in its recent dividend decisions.

2014 Accomplishments and 2015 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 IDACORP's and Idaho Power's achievements during 2014 under its three-part business strategy include:


•	achieved net income growth for a seventh consecutive year;


•	extended (with modifications) the December 2011 Idaho settlement stipulation to provide potential earnings support for 2015 through 2019;


•	executed on business optimization initiatives, focusing on improving operations and controlling expenditures;


•	managed through planned retirements, natural attrition, and business optimization, while scoring in the top quartile of a benchmark employee engagement survey;


•	implemented Safety4Life—an initiative to increase employee safety awareness and improve employee safety behaviors and practices, and maintained Occupational Safety and Health Administration recordable injury rates well below utility industry national averages;


•	continued progress toward the permitting of the Boardman-to-Hemingway and Gateway West 500-kV transmission projects, including the issuance of the U.S. Bureau of Land Management's (BLM) draft environmental impact statement for the Boardman-to-Hemingway project in December 2014;


•	remained on target to meet its goal to reduce average CO₂ emissions intensity by 10 to 15 percent below 2005 emissions for the six-year period 2010 through 2015; and


•	improved Idaho Power's ranking from 29 to 17 in the annual "40 Best Energy Companies" list published by Public Utilities Fortnightly.

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For 2015, in addition to its specific infrastructure and regulatory projects noted above, Idaho Power has established a number of organizational initiatives, including the following:


•	emphasize and enhance its enterprise safety culture;


•	actively manage costs and the ability to fund planned capital investments by optimizing business practices;


•	continue innovative approaches to regulatory strategy;


•	promote economic development through collaboration with the states of Idaho and Oregon to attract new businesses and expand existing businesses that utilize Idaho Power's available capacity and generation resources;


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


•	continue progress toward federal relicensing for the Hells Canyon Complex (HCC) hydroelectric facility and permitting of the 500-kV transmission projects;


•	address issues related to the integration of renewable generation resources on the system grid;


•	actively participate in the process for shaping carbon emission regulation for the electric utility industry; and


•	address workforce attrition associated with anticipated retirements, using targeted succession planning and development programs.

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, operational, weather-related, economic, and other factors, many of which are described below.

Timely Regulatory Cost Recovery: 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 on the prudent management of expenses and investments.

One of the most notable regulatory developments during 2014 was the IPUC's October 2014 approval of a regulatory settlement stipulation extending, with modifications, a December 2011 settlement stipulation that permitted Idaho Power to amortize additional accumulated deferred investment tax credits (ADITC) to help achieve a minimum 9.5 percent Idaho-jurisdictional return on year-end equity (Idaho ROE) in 2012, 2013, and 2014, subject to prescribed limits and conditions. The October 2014 settlement stipulation allows for Idaho Power's amortization of up to a total of $45 million of additional ADITCs for the period from 2015 through 2019 to help achieve a minimum 9.5 percent Idaho ROE for an applicable year, subject to prescribed limits and conditions. Like the December 2011 settlement stipulation, the new settlement stipulation provides for the sharing between Idaho Power and Idaho customers of Idaho-jurisdictional earnings in excess of specified levels of Idaho ROE. 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 under the settlement stipulation provides an element of earnings stability for 2015 and potentially the next several years.

Another item that Idaho Power believes is representative of its active approach to regulatory matters was the IPUC's approval during 2014 of Idaho Power's request to shift recovery of approximately $99 million in Idaho-jurisdiction power supply expenses historically collected through the PCA mechanism to collection via base rates. While approval of the application results in no net change in the amount collected through base rates and the PCA mechanism in the aggregate, approval of the application will decrease the amount of any base rate increase requested in Idaho Power's next general rate case application filed with the IPUC.

The October 2014 settlement stipulation, base level power supply expense order, and other significant rate proceedings during 2012, 2013, and 2014 are described in "Regulatory Matters" in this MD&A. Important regulatory matters are also discussed in Note 3 - "Regulatory Matters" to the consolidated financial statements included in this report.

Economic Conditions and Customer/Load Growth: Idaho Power monitors a number of economic indicators, including employment statistics, growth in customer numbers, foreclosure rates, and other housing-related data on a national and state 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 construct and improve infrastructure, purchase power, and implement programs to meet customer load demands. Idaho Power has in recent years observed what it believes to be a number of positive economic factors in its service territory. For example:

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•	Based on Idaho Department of Labor preliminary data, the total number of persons employed in the service area in December 2014 was 459,531, compared with 452,666 in December 2013, and the associated unemployment rate for the service area was 3.6 percent, compared with 5.3 percent in December 2013. The U.S. rate stood at 5.6 percent in December 2014, according to U.S. Department of Labor data.


•	Gross area product for Idaho Power's service area, as reported by Moody's Analytics, grew by 1.9 percent for 2014. Moody's forecasts, as of January 14, 2015, 3.1 percent and 3.5 percent growth in gross area product for 2015 and 2016, respectively.


•	Customer growth from 2013 to 2014 was 1.4 percent.


•	A number of businesses have recently constructed, or are in the process of constructing, sizable facilities in Idaho Power's service territory, including office and manufacturing complexes, particularly in the food processing industry.

Based on recent economic data, Idaho Power predicts that customer growth within its service area will continue to be positive. Idaho Power's most recent load forecast predicts a 1.4 percent five-year compound annual growth rate in residential loads and a 2.1 percent five-year compound annual growth rate in residential customers. For longer-term resource planning purposes, Idaho Power expects to include in its 2015 IRP, to be filed with the IPUC and OPUC in June 2015, a forecasted long-term annual residential customer growth rate of 1.6 percent, an increase over the 1.4 percent residential customer growth rate used in the 2013 IRP. These projected residential customer growth rates are improvements over the 1.0 percent growth rate experienced the past 5 years, but less than the 2.3 percent growth rate realized over the past 20 years.

Should the updated estimates of higher growth rates materialize, or if there is a significant increase in loads due to new, unanticipated large-load customers, growth would exceed the projections and Idaho Power could be required to adjust its infrastructure development timing and plans accordingly.

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 use 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, and weather conditions can impact the timing and degree of use of those pumps. Idaho Power also has tiered rates and seasonal rates, which contribute to increased revenues during higher-load periods, most notably during the third quarter of each year when overall customer demand is highest. In 2014, weather-related sales fluctuations were less dramatic than during the abnormally cold first quarter of 2013 and abnormally hot third quarter of 2013.

Idaho Power's hydroelectric facilities comprise nearly one-half of Idaho Power's nameplate generation capacity. However, the availability and volume of hydroelectric power generated depends on several factors - the snow pack levels in the mountains upstream of Idaho Power's 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's hydroelectric generation during 2014 was 6.2 million megawatt-hours (MWh), compared with actual generation of 5.7 million MWh in 2013 and 8.0 million MWh in 2012. Since 1928, the resource-adjusted median annual hydroelectric generation is 8.5 million MWh. For 2015, Idaho Power estimates generation from its hydroelectric facilities of between 7.0 million MWh and 9.0 million MWh.

When hydroelectric generation is reduced, Idaho Power must rely on more expensive generation sources and purchased power. Most of the increase in power supply costs is collected from customers through the Idaho and Oregon PCA mechanisms. 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. When favorable hydroelectric generating conditions exist for Idaho Power, they also may exist for other Pacific Northwest hydroelectric facility operators – increasing the available supply of lower-cost power, lowering regional wholesale market prices, and impacting 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 generally have less surplus energy available for sale into the wholesale markets at those times. Much of the adverse or favorable impact of this volatility is addressed through the PCA mechanisms.

Fuel and Purchased Power Expense: In addition to hydroelectric generation, Idaho Power relies significantly on coal and natural gas to fuel its generation facilities and power purchases in the wholesale markets. Fuel costs are impacted by electricity sales volumes, the terms of contracts for fuel, Idaho Power's generation capacity, 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 Langley Gulch power plant, placed into operation in June 2012, has increased Idaho Power's use of natural gas as a generation fuel and thus its exposure to volatility in natural gas prices.

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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 or solar energy, and wholesale energy market prices. Idaho Power is required by law 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 at times 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. Softened market prices due to PURPA impacts also decrease Idaho Power's excess power sales. The proceeds from off-system sales lower overall power supply costs. Integration of intermittent, non-dispatchable resources (such as wind or solar energy) into Idaho Power's portfolio also creates a number of complex operational challenges and risks that Idaho Power must address. 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 3,407 MW on July 2, 2013, wind resources on Idaho Power's system, representing roughly 675 MW of nameplate capacity, were contributing only 57 MW of power due to lack of wind. Increases in federally mandated PURPA power purchases have contributed to increases in customer rates.

The Idaho and Oregon PCA mechanisms mitigate in large part the potential adverse impacts of fluctuations in power supply costs to Idaho Power, including substantially all of the Idaho-jurisdiction PURPA power purchase costs. Idaho Power also uses physical and financial forward contracts for both electricity and fuel and other hedging strategies in order to manage the risks relating to fuel and power price exposures.

Regulatory and Environmental Compliance Costs: Idaho Power is subject to extensive federal and state laws, policies, and regulations, as well as regulatory actions and audits by agencies and quasi-governmental agencies, including the FERC and the North American Electric Reliability Corporation. Compliance with these requirements directly influences Idaho Power's operating environment and affects Idaho Power's operating costs. Potential fines and monetary awards that result from a violation of, and costs associated with operational changes that are necessary to comply with, applicable laws or regulations may be substantial. Accordingly, Idaho Power has in place numerous compliance policies and initiatives to help ensure compliance, and periodically evaluates and updates those policies and initiatives.

Environmental laws and regulations in particular may, among other things, increase the cost of operating 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 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 required by existing regulations. Idaho Power expects to spend a considerable amount on environmental compliance and controls in the next decade. As legislation and regulations concerning greenhouse gas emissions develop, including the proposed rule under Section 111(d) of the Clean Air Act, Idaho Power will continue to actively participate in the rulemaking process.

Other Notable Matters and Areas of Focus

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 its federal license for the HCC, its largest hydroelectric generation source. Relicensing involves numerous environmental issues and substantial costs. Idaho Power is working with the states of Idaho and Oregon, federal and state 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, and the terms of, and costs associated with, any resulting license are not currently determinable.

Transmission Projects: Idaho Power continues to focus on expansion of its transmission system in an effort to enhance system reliability and access to wholesale markets. Its most notable transmission projects in progress are 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. As it relates to the Boardman-to-Hemingway project, for which Idaho Power is the project manager, environmental requirements and regulations (particularly relating to sage grouse) for the siting process have changed significantly since commencement of the project, making permitting for the transmission line more difficult. This has resulted in project delays and increased permitting costs. In light of the delays and siting impediments that have occurred and are expected to continue, Idaho Power estimates that the in-service date for the Boardman-to-

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Hemingway line would be 2021 or beyond. The Boardman-to-Hemingway line remains Idaho Power's preferred resource alternative, as identified in Idaho Power's 2013 IRP.

Summary of 2014 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, 2014, 2013, and 2012 (in thousands, except earnings per share amounts):



	Year Ended December 31,
	2014		2013		2012
Idaho Power net income	$	189,387	$	176,741	$	168,168
Net income attributable to IDACORP, Inc.	$	193,480	$	182,417	$	173,014
Average outstanding shares – diluted (000’s)	50,199		50,126		50,010
IDACORP, Inc. earnings per diluted share	$	3.85	$	3.64	$	3.46

The table below provides a reconciliation of net income attributable to IDACORP, Inc. for year ended December 31, 2014 to the year ended December 31, 2013 (items are in millions and are before tax unless otherwise noted):



Net income attributable to IDACORP, Inc. - December 31, 2013				$	182.4
Change in Idaho Power net income:
Decreased sales volumes attributable to usage per customer, net of associated power supply costs and PCA mechanism impacts	$	(38.1	)
Increased sales volumes attributable to customer growth, net of associated power supply costs and PCA mechanism impacts	9.1
Increased labor-related expenses	(4.6		)
Increased depreciation, property tax, and other (net)	(3.8		)
Greater sharing-related costs reflected as pension expense and revenue sharing	(0.6		)
Decrease in Idaho Power operating income	(38.0		)
Increase in allowance for funds used during construction (AFUDC)	3.9
Gains on sale of investments in 2013, not repeated in 2014	(11.6		)
Changes in other non-operating income and expenses	1.6
Decreased income taxes due to tax method changes for years prior to 2014	29.1
Decreased income taxes due to greater capitalized repairs deduction in 2014	7.8
Decreased other income tax expense	19.8
Total increase in Idaho Power net income				12.6
Other net changes (net of tax)				(1.5		)
Net income attributable to IDACORP, Inc. - December 31, 2014				$	193.5

IDACORP's net income increased $11.1 million for the year ended December 31, 2014 when compared with 2013. Idaho Power's operating income decreased by $38.0 million for 2014 compared with 2013. Lower overall usage per customer, primarily due to a return to moderate weather conditions in 2014 compared with 2013, decreased operating income by $38.1 million. These weather-related decreases were partially offset by increased sales volumes associated with continued growth in the number of Idaho Power customers, which increased operating income by $9.1 million when compared with 2013. The number of Idaho Power's general business customers increased by 1.4 percent from December 31, 2013 to December 31, 2014. Increases in labor-related expenses, depreciation, property taxes, and other items combined to decrease operating income by $8.4 million in 2014 when compared with 2013.

In 2014, Idaho Power recorded a $3.9 million increase in AFUDC related to greater average construction work in progress, while in 2013 it recorded a gain of $11.6 million related to the sale of investments in securities that was not repeated in 2014. The net decrease in income tax expense of $56.7 million more than offset the lower pre-tax income in 2014.

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Effect of Income Taxes and Tax Method Changes on Results

Income tax accounting method changes for years prior to 2014 increased net income by $29.1 million for 2014 when compared with 2013. In 2013, Idaho Power recorded $4.6 million of income tax expense as a result of a cumulative method change adjustment related to its capitalized repairs deduction for generation assets for years prior to 2013. By contrast, during 2014, Idaho Power recorded an income tax benefit of $24.5 million related to finalization of its method change adjustment for generation assets for years prior to 2014 as well as modifications to its overall capitalized repairs deduction tax method as agreed to with the U.S. Internal Revenue Service (IRS). The income tax benefit related to Idaho Power's 2014 capitalized repairs deduction was $7.8 million greater than 2013, due to the impact of the method changes and the amount and type of 2014 capital additions. Income tax expense at Idaho Power not related to method changes was $19.8 million lower in 2014 than in 2013, primarily due to lower pre-tax earnings in 2014.

Effect of Sharing Mechanism on Results

During 2014, Idaho Power recorded a total of $24.7 million related to a December 2011 Idaho regulatory settlement agreement, which requires sharing with Idaho customers of a portion of 2014 earnings exceeding a 10.0 percent Idaho ROE. In accordance with the terms of the settlement agreement, of the $24.7 million, $16.7 million was recorded as additional pension expense and $8.0 million was recorded as a provision against current revenues to be refunded to customers through a future rate reduction. Idaho Power recorded similar amounts in 2013. A total of $118 million in earnings has been shared with Idaho customers through sharing mechanisms since 2009. The settlement agreement is described further in "Regulatory Matters" in this MD&A. The impact of sharing on 2014 and 2013 results is reflected in the following table (in millions):



	2014			2013			Variance
Additional pension expense funded through sharing	$	(16.7	)	$	(16.5	)	$	(0.2	)
Provision against current revenue as a result of sharing	(8.0		)	(7.6		)	(0.4		)
Total	$	(24.7	)	$	(24.1	)	$	(0.6	)

Key Operating and Financial Metric Estimates for 2015

IDACORP's and Idaho Power's estimates, as of the date of this report, for 2015 metrics are as follows:



	2015 Estimate	2014 Actual
Idaho Power Operating & Maintenance Expense (millions)	$340-$350	$	355
Idaho Power Additional Amortization of ADITC (millions)	None	None
Idaho Power Capital Expenditures, excluding AFUDC (millions)	$300-$310	$	265
Idaho Power Hydroelectric Generation (MWh)	7.0-9.0	6.2

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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. In this analysis, the results for 2014 are compared with 2013 and the results for 2013 are compared with 2012. In the MD&A, MWh and dollar amounts in tables, other than earnings per share, are in thousands unless otherwise indicated.

Utility Operations

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



	Year Ended December 31,
	2014		2013		2012
General business sales	14,092		14,619		14,085
Off-system sales	2,220		1,683		2,183
Total energy sales	16,312		16,302		16,268
Hydroelectric generation	6,170		5,656		7,956
Coal generation	5,851		6,327		5,227
Natural gas and other generation	1,175		1,576		676
Total system generation	13,196		13,559		13,859
Purchased power	4,153		3,902		3,670
Line losses	(1,037	)	(1,159	)	(1,261	)
Total energy supply	16,312		16,302		16,268

Sales Volume and Generation: In 2014, general business sales volume decreased by 0.5 million MWh, or 4 percent, compared with the prior year, mostly related to decreased residential customer usage attributable to more moderate weather conditions in 2014 compared with 2013. Industrial customer usage increased when compared with the prior year, partially offsetting the overall decrease in general business sales volumes. Off-system sales volume increased by 0.5 million MWh, or 32 percent, in 2014 as small increases in output from hydroelectric resources, a decrease in general business customer load, and favorable wholesale market conditions increased surplus power available for sale.

Hydroelectric generation provided 47 percent of Idaho Power’s total system generation during 2014. Hydroelectric generation in 2014 was 73 percent of the annual median generation of 8.5 million MWh, which is based on median hydrologic conditions as derived from the Snake River Basin historical stream flow record normalized to reflect the current level of water resource development. The below-average hydroelectric generation during 2012 through 2014 resulted from relatively low snow pack and spring season run-off in the Snake River basin during the three-year period.

The small increase in hydroelectric generation during 2014 compared with 2013 contributed to decreased utilization of coal-fired and natural-gas fired generation.

The financial impacts of fluctuations in off-system sales, purchased power, fuel expense, and other power supply-related expenses are addressed in Idaho Power's Idaho and Oregon PCA mechanisms, which are described later in this MD&A.

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



	Year Ended December 31,
	2014			2013			2012
Revenue
Residential	$	500,195		$	513,914		$	431,555
Commercial	299,462			281,009			241,519
Industrial	182,675			165,941			145,054
Irrigation	158,654			159,242			137,424
Total	1,140,986			1,120,106			955,552
Provision for sharing	(7,999		)	(7,602		)	(7,151		)
Deferred revenue related to HCC relicensing AFUDC⁽¹⁾	(10,706		)	(10,776		)	(10,636		)
Total general business revenues	$	1,122,281		$	1,101,728		$	937,765
Volume of Sales (MWh)
Residential	4,965			5,365			5,039
Commercial	3,944			3,975			3,865
Industrial	3,217			3,182			3,133
Irrigation	1,966			2,097			2,048
Total MWh sales	14,092			14,619			14,085
Number of customers at year-end
Residential	428,294			422,188			416,020
Commercial	67,522			66,734			65,920
Industrial	121			115			119
Irrigation	19,826			19,398			19,045
Total customers	515,763			508,435			501,104

⁽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 is deferring revenue recognition of the amounts collected until the license is issued and the asset is placed in service under the new license.

Changes in rates and changes in customer demand are the primary causes of fluctuations in general business revenue from period to period. See "Regulatory Matters" in this MD&A for a list of rate changes implemented over the last three years. The primary influence on changes in customer demand for electricity is weather conditions. Extreme temperatures increase sales to customers who use electricity for cooling and heating, while moderate temperatures decrease sales. Precipitation levels and the timing of precipitation during the agricultural growing season affect sales to customers who use electricity to operate irrigation pumps. Rates are 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. For purposes of illustration and comparison, Boise, Idaho weather-related information for the last three years is presented in the following table:



	Year Ended December 31,
	2014	2013	2012	Normal
Heating degree-days⁽¹⁾	4,976	6,032	4,723	5,514
Cooling degree-days⁽¹⁾	1,129	1,320	1,274	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. While Boise, Idaho weather conditions are not necessarily representative of weather conditions throughout Idaho Power's service territory, the greater Boise area has the majority of Idaho Power's customers.

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General Business Revenues - 2014 Compared with 2013: General business revenue increased $20.6 million in 2014 compared with 2013. The factors affecting general business revenues are discussed below.

•

Rates. Rate changes, primarily associated with increased power supply costs, combined to increase general business revenue by $64.8 million. The revenue impact of the rate changes was partially offset by associated changes in operating expenses—Idaho PCA amortization expense increased $42.8 million in 2014 due to the change in the corresponding Idaho PCA true-up rate in the current year. The PCA mechanism is discussed later in this MD&A.


•	Usage. Lower usage per customer, primarily driven by the impact of more moderate weather during 2014 on residential customer usage, decreased general business revenue by $55.7 million. Residential usage per customer was 9.1 percent lower in 2014.


•	Customers. Continued customer growth partially offset the decrease in overall MWh sales, increasing revenue by $11.9 million. Customer growth from 2013 to 2014 was 1.4 percent.

•

Sharing. The overall increase in general business revenue was impacted by Idaho Power's revenue sharing mechanism. This mechanism, which was in place for 2012 through 2014, is associated with the December 2011 Idaho regulatory settlement agreement that provides for the sharing with customers of a portion of Idaho-jurisdiction earnings exceeding a 10.0 percent Idaho ROE. The impact of this mechanism is partially recorded as a reduction to general business revenue. Reductions of $8.0 million and $7.6 million were recorded in 2014 and 2013, respectively, resulting in a net decrease to general business revenue of $0.4 million in 2014.

General Business Revenues - 2013 Compared with 2012: General business revenue increased $164.0 million in 2013 compared with 2012. The factors affecting general business revenues are discussed below.

•

Rates. Rate changes, primarily associated with increased power supply costs, combined to increase general business revenue by $130.8 million. The revenue impact of several of the rate changes was directly offset by associated changes in operating expenses. For example, Idaho PCA amortization expense increased $42.0 million in 2013 due to the change in the corresponding Idaho PCA true-up rate in the current year.


•	Usage. Higher usage per customer, primarily driven by residential customers, increased general business revenue by $27.9 million. While usage increased across all customer classes, residential usage per customer was 5.2 percent higher for 2013 due largely to more extreme summer and winter temperatures.

•

Customers. Customer growth contributed to the increase in overall MWh sales, increasing revenue $12.3 million. Customer growth from 2012 to 2013 was 1.5 percent. The positive impact of customer growth was partially offset by a $6.6 million decrease in revenues resulting from the termination in 2012 of an electric service agreement with Hoku Materials, Inc. Combined, these changes increased general business revenues by $5.7 million.


•	Sharing. The overall increase in general business revenue was impacted by Idaho Power's revenue sharing mechanism under the December 2011 Idaho regulatory settlement agreement noted above. Reductions of $7.6 million and $7.2 million were recorded in 2013 and 2012, respectively, resulting in a net decrease to general business revenue of $0.4 million in 2013.

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,
	2014		2013		2012
Revenue	$	77,165	$	54,473	$	61,534
MWh sold	2,220		1,683		2,183
Revenue per MWh	$	34.76	$	32.37	$	28.19

Off-System Sales - 2014 Compared with 2013: Off-system sales revenue increased by $22.7 million, or 42 percent, in 2014 as a result of favorable market conditions, at times, for selling power off-system. Off-system sales volumes also benefitted from

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greater amounts of surplus system energy resulting from slightly lower system loads and increased hydroelectric generation and PURPA power purchases.

Off-System Sales - 2013 Compared with 2012: Off-system sales revenue decreased by $7.1 million, or 11 percent, in 2013 as a result of lower volumes of surplus power available for sale. Sales volumes decreased by 23 percent due to lower output from hydroelectric plants due to unfavorable hydroelectric generating conditions (as a result of lower snow pack and spring season run-off) and an increase in general business customer loads.

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



	Year Ended December 31,
	2014		2013		2012
Transmission services and other	$	52,051	$	51,260	$	50,126
Energy efficiency	27,154		35,637		27,300
Total other revenues	$	79,205	$	86,897	$	77,426

Other Revenues - 2014 Compared with 2013: Other revenues decreased $7.7 million in 2014, resulting primarily from an order issued by the IPUC in the prior year that allowed Idaho Power to recover custom efficiency program incentive payments made between January 1, 2011 and June 1, 2013, through the energy efficiency rider. Based on the order, $14.3 million of other revenue (as well as energy efficiency program expense) was recognized in the second quarter of 2013. Partially offsetting the impact of this order from the IPUC was higher utilization of energy efficiency programs when compared with 2013.

Most energy efficiency activities are funded through a rider mechanism on customer bills. Energy efficiency program expenditures funded through the rider are reported as an operating expense with an equal amount of revenues recorded in other revenues, resulting in no net impact on earnings.

Other Revenues - 2013 Compared with 2012: Other revenues increased $9.5 million in 2013, mainly due to an increase in energy efficiency revenues of $8.3 million, due to an order issued by the IPUC allowing Idaho Power to recover custom efficiency program incentive payments between January 1, 2011 and June 1, 2013, through the energy efficiency rider. Based on the order, $14.3 million of other revenue (as well as energy efficiency program expense) was recognized in the second quarter of 2013. The impact of the order was offset by decreased utilization of demand response programs during 2013.

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



	Year Ended December 31,
	2014		2013		2012
Expense
PURPA contracts	$	144,617	$	131,338	$	117,618
Other purchased power (including wheeling)	92,071		85,038		64,838
Demand response incentive payments	7,940		4,203		14,479
Total purchased power expense	$	244,628	$	220,579	$	196,935
MWh purchased
PURPA contracts	2,286		2,127		1,961
Other purchased power	1,867		1,775		1,709
Total MWh purchased	4,153		3,902		3,670
Cost per MWh from PURPA contracts	$	63.26	$	61.75	$	59.98
Cost per MWh from other purchased power	$	49.31	$	47.91	$	37.94
Weighted average - all sources (excluding demand response incentive payments)	$	56.99	$	55.45	$	49.72

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 than during light load periods, and conversely has less energy available for off-system sales during heavy load periods than light load periods. Market energy prices are typically higher during heavy load periods than during 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

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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. Most of the non-PURPA purchased power and substantially all of the PURPA power purchase costs are recovered through base rates and Idaho Power's PCA mechanisms.

Purchased Power - 2014 Compared with 2013: Purchased power expense increased $24.0 million, or 11 percent, in 2014, mostly resulting from an increase in generation provided by PURPA wind contracts when compared with 2013. In addition, wholesale gas and electricity market conditions warranted third-party power purchases to serve system load at times rather than dispatching Idaho Power-owned thermal resources. Finally, the increases in demand response program incentive payments primarily relate to the temporary cessation of some of these programs during 2013, which were reinstated for 2014.

Purchased Power - 2013 Compared with 2012: Purchased power expense increased $23.6 million, or 12 percent, in 2013, principally due to additional PURPA wind generation that came on-line, as well as less favorable hydroelectric generating conditions, which increased the need to purchase power from third parties. The volume of power purchased through PURPA contracts increased 8 percent, contributing to a $13.7 million increase in PURPA power purchase expense in 2013, while MWh purchased through other sources increased 4 percent. Reductions in demand response program costs, due to temporary suspension of two programs in 2013, partially offset the increased expenses related to power purchases.

Fuel Expense: The table below presents Idaho Power’s fuel expenses and generation at its thermal generating plants for the last three years:



	Year Ended December 31,
	2014		2013		2012
Expense
Coal	$	156,172	$	160,277	$	134,501
Natural gas and other thermal	45,069		54,205		24,912
Total fuel expense	$	201,241	$	214,482	$	159,413
MWh generated
Coal	5,851		6,327		5,227
Natural gas and other thermal	1,175		1,576		676
Total MWh generated	7,026		7,903		5,903
Cost per MWh
Coal	$	26.69	$	25.33	$	25.73
Natural gas and other thermal	38.36		34.39		36.85
Weighted average, all sources	$	28.64	$	27.14	$	27.01

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

Fuel Expense - 2014 Compared with 2013: In 2014, fuel expense decreased $13.2 million, or 6 percent, compared with 2013, due principally to decreased output from the natural gas-fired plants during 2014, resulting from lower system load demands and increased generation provided by facilities under PURPA contracts. The thermal coal plants were also operated less in 2014 when compared with 2013, as higher hydroelectric generation enabled lower utilization of the coal plants to serve system load requirements. Partially offsetting these decreases were higher commodity costs when compared with 2013.

Fuel Expense - 2013 Compared with 2012: In 2013, fuel expense increased $55.1 million, or 35 percent, compared with 2012, due principally to the following factors:

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Idaho Power's Langley Gulch natural gas-fired power plant came on line on June 29, 2012. Operation of the plant accounted for $23.9 million of the increase in fuel expense. Idaho Power operated the plant primarily to serve peak load, to integrate intermittent resources, and for economic dispatch opportunities. During 2013, Idaho Power relied more on Langley Gulch and other gas plants to meet customer loads as a result of the decline in hydroelectric generation compared with the same period in 2012; and


•	generation from coal-fired facilities increased 21 percent in 2013. This increase in generation accounted for $25.6 million of the increase in fuel expense compared with 2012. During 2013, higher wholesale power prices and lower

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hydroelectric generation when compared with 2012 increased Idaho Power's reliance on its coal-fired plants to meet customer loads.

PCA Mechanisms: Idaho Power's power supply costs (primarily purchased power and fuel, less off-system sales) can vary significantly from year to year. Volatility of power supply costs arises from factors such as weather conditions, wholesale market prices and volumes of power purchased and sold in the wholesale markets, Idaho Power's hydroelectric and thermal generation volumes and fuel costs, generation plant availability, and retail loads. To address the volatility of power supply costs, Idaho Power's PCA mechanisms in the Idaho and Oregon jurisdictions allow Idaho Power to recover from or refund to customers most of the fluctuations in power supply costs. In the Idaho jurisdiction, the PCA includes a cost or benefit sharing ratio that allocates the deviations in net power supply expenses between customers (95 percent) and the company (5 percent), with the exception of PURPA power purchases and demand-response program incentives, which are allocated 100 percent to customers. Because of the PCA 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 in a future period, resulting in fluctuations in operating cash flows from year to year. The table that follows presents the components of the Idaho and Oregon PCA mechanisms for the last three years:



	Year Ended December 31,
	2014			2013			2012
Idaho power supply cost deferral	$	(48,104	)	$	(67,127	)	$	(45,064	)
Oregon power supply cost deferral	—			—			(1,523		)
Amortization of prior year authorized balances	70,339			27,590			(14,503		)
Total power cost adjustment expense	$	22,235		$	(39,537	)	$	(61,090	)

The power supply deferrals represent the portion of the power supply cost fluctuations deferred under the PCA mechanisms. When actual power supply costs are higher than the amount forecasted in PCA rates, which was the case for 2014, 2013, and 2012, most of the difference is deferred. The amortization of the prior year’s balances represents the offset to the amounts being collected or 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 - 2014 Compared with 2013: Actual net power supply cost deferrals decreased in 2014 relative to 2013, a change of $19.0 million—from $67.1 million to $48.1 million. Power supply costs collected through base rates increased on June 1, 2014, resulting in less costs needing to be recovered through the PCA mechanism since that time. The $70.3 million of amortization offsets the collection from customers of prior years' deferrals.

PCA Mechanisms - 2013 Compared with 2012: Actual net power supply cost deferrals increased in 2013 relative to 2012, a change of $20.5 million—from deferrals of $46.6 million to $67.1 million. The $27.6 million of amortization offsets the net collection from customers of prior years' deferrals.

Other Operations and Maintenance Expenses: The changes in operations and maintenance (O&M) expenses for the periods presented are discussed below.

O&M - 2014 Compared with 2013: Other O&M expense increased by $5.7 million in 2014 compared with 2013, an increase of less than two percent, due to the following factors:


•	an increase of $4.6 million in labor-related expenses, caused by normal escalations in labor and benefits costs; and


•	an increase of $0.9 million in bad debt expense resulting from fewer collections related to a billing system change made in 2013. Due to full implementation of the billing system change, Idaho Power expects that bad debt expense will return to more normal levels in future periods.

O&M - 2013 Compared with 2012: Other O&M expense decreased by $0.2 million in 2013 compared with 2012, a decrease of less than one percent, due to the following factors:


•	pension expense increased $1.9 million as the sharing mechanism in place during both years resulted in higher sharing-related pension expense in 2013;


•	other O&M expenses were $1.3 million lower, reflecting business optimization efforts;


•	labor-related expenses increased by $1.5 million as a result of normal escalations in labor and benefits costs; and

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•	O&M expenses associated with hydroelectric generation were $2.3 million lower, primarily due to water lease payments made in 2012 that were not made in 2013 because less water associated with these leases was available in 2013.

Gain on Sale of Investments

In 2013, Idaho Power recognized an $11.6 million gain on the sale of marketable securities. These investments relate to the Rabbi trust designated to provide funding for Idaho Power's obligations under its Security Plan for Senior Management Employees. Gross proceeds from the sale were $25.7 million. No such sale occurred in 2014 or 2012.

Income Taxes

Income tax accounting method changes decreased 2014 income tax expense by $29.1 million when compared with 2013. In 2013, Idaho Power recorded $4.6 million of income tax expense as a result of a method change related to its capitalized repair deduction for generation assets for years prior to 2013. By contrast, in 2014, Idaho Power, in coordination with the IRS through IDACORP’s Compliance Assurance Process program, implemented aspects of the final tangible property regulations and other technical interpretations of these rules into its existing capitalized repairs tax accounting method for generation, transmission, and distribution assets. These technical interpretations were received from the IRS in 2014. An $11.1 million tax benefit related to the portion of the 2013 capitalized repairs deduction based on these modifications was recorded in 2014. Idaho Power finalized these changes with the filing of IDACORP’s 2013 consolidated federal income tax return in September 2014. In 2014, Idaho Power also recorded a $13.4 million for years prior to 2013 income tax benefit for the finalization of the cumulative method change impact related to the generation asset method change. The income tax benefit related to Idaho Power's 2014 capitalized repairs deduction was $7.8 million greater than 2013, due to the impact of the method changes and the amount and type of 2014 capital additions. Further, income tax expense (excluding the tax method changes) decreased $19.8 million compared with 2013, principally due to lower Idaho pre-tax earnings in 2014. Income tax expense in 2013 increased significantly compared with 2012, principally as a result of greater Idaho Power pre-tax earnings in 2013.

On August 18, 2014, the U.S. Treasury and IRS issued final regulations addressing the disposition of property subject to depreciation and general asset accounts. The regulations are generally effective for tax years beginning on or after January 1, 2014. IDACORP and Idaho Power do not believe these disposition regulations will have a material adverse effect on future tax filings. Therefore, as of December 31, 2014, no income tax impacts have been recorded related to the new guidance.

For additional information relating to IDACORP's and Idaho Power's income taxes, including the availability of tax credit carryforwards, see Note 2 - “Income Taxes” to the consolidated financial statements included in this report.

LIQUIDITY AND CAPITAL RESOURCES

Overview

Idaho Power has been pursuing significant enhancements to its utility infrastructure in an effort to ensure an adequate supply of electricity, to provide service to new customers, and to maintain system reliability. Idaho Power's existing hydroelectric and thermal generation facilities also require continuing upgrades and component replacement. Idaho Power's expenditures for property, plant and equipment, excluding AFUDC, were $265 million in 2014 and $228 million in 2013. Idaho Power expects these substantial capital expenditures to continue, with estimated total capital expenditures of approximately $1.5 billion over the period from 2015 through 2019.

Idaho Power funds its liquidity needs for capital expenditures through cash flows from operations, debt offerings, commercial paper markets, credit facilities, and capital contributions from IDACORP. Idaho Power periodically files for rate adjustments for recovery of operating costs and capital investments to provide the opportunity to align Idaho Power's earned returns with those allowed by regulators. Idaho Power uses operating and capital budgets to control operating costs and capital expenditures, and has also been focusing on optimizing its business operations, which has included controlling operating and maintenance costs through process review and improvement initiatives. Consistent with 2014, during 2015 IDACORP and Idaho Power will continue to focus on optimizing operations, controlling costs, and generating sufficient operating cash inflows to meet operating expenditures, contribute to capital expenditure requirements, and pay dividends to shareholders.

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As of February 13, 2015, IDACORP's and Idaho Power's access to debt, equity, and credit arrangements included:


•	$125 million and $300 million revolving credit facilities, respectively;


•	IDACORP's shelf registration statement filed with the U.S. Securities and Exchange Commission (SEC) on May 22, 2013, which may be used for the issuance of debt securities and common stock, including up to 3 million shares of IDACORP common stock available for issuance under IDACORP's sales agency agreement executed in July 2013;


•	Idaho Power's shelf registration statement, filed with the SEC jointly with IDACORP on May 22, 2013, which may be used for the issuance of first mortgage bonds and debt securities; $500 million is available for issuance under a selling agency agreement executed in July 2013 and pursuant to state regulatory authority; and


•	IDACORP's and Idaho Power's issuance of commercial paper, which may be issued up to an amount equal to the available credit capacity under their respective credit facilities.

IDACORP and Idaho Power have no significant long-term debt maturities until 2018. Based on planned capital expenditures and operating and maintenance expenses for 2015, the companies believe they will be able to meet capital requirements and fund corporate expenses during 2015 with a combination of existing cash and operating cash flows generated by Idaho Power's utility business, together with proceeds from either draws upon credit facilities or Idaho Power's issuance of debt securities. IDACORP and Idaho Power would expect to meet any short-term cash shortfalls during 2015 with existing credit facilities and expect to continue to manage short-term liquidity through commercial paper markets.

IDACORP and Idaho Power also monitor capital markets with a view toward opportunistic debt and equity transactions, taking into account current and potential long-term future needs. As a result, IDACORP may issue debt securities or may issue common stock under the existing continuous equity program, and Idaho Power may issue debt securities, if the companies believe terms available in the capital markets are favorable and that issuances would be financially prudent. Idaho Power also periodically analyzes whether partial or full early redemption of one or more existing outstanding series of first mortgage bonds is desirable, and in some cases may refinance indebtedness with new indebtedness issued with more favorable terms, including interest rates lower than the series being redeemed.

IDACORP and Idaho Power seek to maintain capital structures of approximately 50 percent debt and 50 percent equity, and maintaining this ratio influences IDACORP's and Idaho Power's debt and equity issuance decisions. As of December 31, 2014, IDACORP's and Idaho Power's capital structures were as follows:



	IDACORP	Idaho Power
Debt	46%	47%
Equity	54%	53%

IDACORP and Idaho Power generally maintain their cash and cash equivalents in highly liquid investments, such as U.S. Treasury Bills, money market funds, and bank deposits.

Operating Cash Flows

IDACORP's and Idaho Power's principal sources of cash flows from operations are Idaho Power's sales of electricity and transmission capacity. Significant uses of cash flows from operations include the purchase of fuel and power, other operating expenses, interest, and pension plan contributions. Operating cash flows can be significantly influenced by factors such as weather conditions, rates and the outcome of regulatory proceedings, and economic conditions. As fuel and purchased power are significant uses of cash, Idaho Power has regulatory mechanisms in place that provide for the deferral and recovery of the majority of the fluctuation in those costs. However, if actual costs rise above the level allowed in retail rates, deferral balances increase (reflected as a regulatory asset), negatively affecting operating cash flows until such time as those costs, with interest, are recovered from customers.

IDACORP’s and Idaho Power’s operating cash inflows in 2014 were $364 million and $343 million, respectively, increases of $59 million and $53 million, respectively, compared with 2013. Significant items that affected the companies' operating cash flows in 2014 relative to 2013 included:


•	changes in regulatory assets and liabilities, mostly related to the relative amounts of power supply costs deferred and collected under the Idaho PCA mechanism, increased operating cash inflows by $58 million;


•	changes in working capital balances due primarily to timing. Decreases in receivable balances from 2013 to 2014 compared with the increase in receivable balances experienced from 2012 to 2013 resulted in an increase to cash flows for 2014 of approximately $50 million for IDACORP and $52 million for Idaho Power;

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•	cash outflows related to income taxes increased by approximately $10 million for IDACORP and $16 million for Idaho Power from 2013 to 2014; and


•	Idaho Power's joint venture, BCC, made net distributions to Idaho Power of $4 million in 2014, as compared with $15 million in 2013. A build-up in coal inventories at BCC during 2014 reduced BCC's cash available for distribution.

IDACORP's and Idaho Power's operating cash inflows in 2013 were $306 million and $290 million, respectively, increases of $56 million and $32 million, respectively, compared with 2012. In addition to increased pre-tax earnings, significant items that affected the companies' operating cash flows in 2013 relative to 2012 included:


•	Idaho Power made $30 million of cash contributions to its defined benefit pension plan in 2013, compared with $44 million of cash contributions during 2012;


•	changes in regulatory assets and liabilities, mostly related to the relative amounts of power supply costs deferred and collected under the Idaho PCA mechanism, increased operating cash inflows by $28 million;


•	cash outflows related to income taxes increased by approximately $25 million for Idaho Power from 2012 to 2013 and cash outflows related to incomes taxes remained relatively flat at $1 million for IDACORP between 2012 and 2013; and

•

changes in working capital balances due primarily to timing. Increases in receivable balances reduced cash flows by approximately $27 million, primarily as a result of increased year-end sales in 2013 compared with 2012. Fluctuations in accounts payables and other accrued liabilities reduced cash flows by $11 million, largely as a result of reduced accruals for PURPA-related payables. Other current liabilities increased cash flows by $10 million primarily due to customer deposits returned in 2012.

Investing Cash Flows

Investing activities consist primarily of capital expenditures related to new construction and improvements to Idaho Power’s generation, transmission, and distribution facilities. Idaho Power's construction expenditures, including AFUDC, were $274 million, $235 million, and $240 million in 2014, 2013, and 2012, respectively. These capital expenditures were primarily for construction of utility infrastructure needed to address Idaho Power’s aging plant and equipment, customer growth, and environmental and regulatory compliance requirements.

Financing Cash Flows

Financing activities provide supplemental cash for both day-to-day operations and capital requirements as needed. Idaho Power funds liquidity needs for capital investment, working capital, managing commodity price risk, and other financial commitments through cash flows from operations, debt offerings, commercial paper markets, credit facilities, and capital contributions from IDACORP. IDACORP funds its cash requirements, such as payment of taxes, capital contributions to Idaho Power, and non-utility operating expenses through cash flows from operations, commercial paper markets, sales of common stock, and credit facilities. The following are significant items and transactions that affected financing cash flows in 2012, 2013, and 2014:


•